Battalion Oil Corp (BATL, NYSE)
Annual report, fiscal year 2016


# UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

# ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

Commission File Number: 001-35467

Halcón Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware 20-0700684
(State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number)

1000 Louisiana Street, Suite 6700, Houston, TX 77002
(Address of principal executive offices)

(832) 538-0300
(Registrant's telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Common Stock, par value $.0001 per share

Name of each exchange on which registered

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T ( \( §223.405 \)  of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K ( \( §229.405 \)  of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☐
(Do not check if a
smaller reporting company)

Smaller reporting company ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

As of February 23, 2017, there were 92,986,173 shares outstanding of registrant's $.0001 par value common stock. Based upon the closing price for the registrant's common stock on the New York Stock Exchange as of June 30, 2016, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $37.0 million.






## TABLE OF CONTENTS

PART I

ITEM 1. Business 6
ITEM 1A. Risk factors 28
ITEM 1B. Unresolved staff comments 46
ITEM 2. Properties 46
ITEM 3. Legal proceedings 46
ITEM 4. Mine safety disclosures 46

PART II

ITEM 5. Market for registrant's common equity, related stockholder matters and issuer purchases of equity securities 47
ITEM 6. Selected financial data 49
ITEM 7. Management's discussion and analysis of financial condition and results of operations 51
ITEM 7A. Quantitative and qualitative disclosures about market risk 78
ITEM 8. Consolidated financial statements and supplementary data 80
ITEM 9. Changes in and disagreements with accountants on accounting and financial disclosure 152
ITEM 9A. Controls and procedures 152
ITEM 9B. Other information 152

PART III

ITEM 10. Directors, executive officers and corporate governance 153
ITEM 11. Executive compensation 165
ITEM 12. Security ownership of certain beneficial owners and management and related stockholder matters 182
ITEM 13. Certain relationships and related transactions, and director independence 184
ITEM 14. Principal accountant fees and services 187

PART IV

ITEM 15. Exhibits and financial statements schedules 189






## Special note regarding forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number and location of wells to be drilled in the future, future cash flows and borrowings, pursuit of potential acquisition or divestiture opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "objective," "believe," "predict," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the "Risk Factors" section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

• volatility in commodity prices for oil and natural gas, including the current sustained decline in the price for oil;

• our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and fully develop our undeveloped acreage positions;

• our ability to replace our oil and natural gas reserves and production;

• we have historically had substantial indebtedness and may incur more debt in the future;

• higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

• the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

• our ability to successfully develop our large inventory of undeveloped acreage in our resource plays;

• our ability to retain key members of senior management, the board of directors, and key technical employees;

• our ability to successfully integrate acquired oil and natural gas businesses and operations;

• the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management's time and energy;

• access to and availability of water and other treatment materials to carry out planned fracture stimulations in our resource plays;

• access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;

• contractual limitations that affect our management's discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

• the potential for production decline rates for our wells to be greater than we expect;

• competition, including competition for acreage in resource play holdings;



## Table of Contents

• environmental risks;

• drilling and operating risks;

• exploration and development risks;

• the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);

• general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

• social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;

• other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

• the insurance coverage maintained by us may not adequately cover all losses that we may sustain;

• title to the properties in which we have an interest may be impaired by title defects;

• senior management’s ability to execute our plans to meet our goals;

• the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars; and

• our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.



## Glossary of Oil and Natural Gas Terms

The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed property. Property where wells have been drilled and production equipment has been installed.

Development well. A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Extension well. A well drilled to extend the limits of a known reservoir.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Hydraulic fracturing. The injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand Boe.

MMBoe. One million Boe.

Mcf. One thousand cubic feet of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million Btu.



## Table of Contents

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves. Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reserve-to-production ratio or Reserve life. A ratio determined by dividing our estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud. Commencement of actual drilling operations.

3-D seismic. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.



## PART I

## ITEM 1. BUSINESS

## Overview

Unless the context otherwise requires, all references in this report to "Halcon," "our," "us," and "we" refer to Halcon Resources Corporation and its subsidiaries, as a common entity.

Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004, recapitalized on February 8, 2012 and reorganized on September 9, 2016. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in select prospect areas. In the years since, we have primarily focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production and broad flexibility to direct our capital resources to projects with the greatest potential returns. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Southern Delaware Basin for $705.0 million and entered into an agreement to sell our assets located in the El Halkén area of East Texas for $500.0 million, which is expected to close by early March 2017.

At December 31, 2016 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell) using Securities and Exchange Commission (SEC) prices of $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, were approximately 148.6 MMBoe, consisting of 119.6 MMBbls of oil, 15.6 MMBbls of natural gas liquids, and 80.2 Bcf of natural gas. Approximately 58% of our proved reserves were classified as proved developed as of December 31, 2016 (Successor). We maintain operational control of approximately 95% of our proved reserves.

Our total operating revenues for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were approximately $153.4 million and $266.8 million, respectively, or $420.2 million combined, compared to total operating revenues for 2015 of $550.3 million. The decrease in total operating revenues year over year was driven by the sustained decline in the prices of crude oil and natural gas along with a decrease in our average daily production year over year. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, or 37,049 Boe/d combined, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor). In response to the sustained decline in commodity prices we reduced our drilling and completion activities in 2016 running only one rig on average in our most economic drilling area. In 2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 net) wells, all of which were completed and capable of production.



## Recent Developments

## Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of our new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under the Securities Act of 1933, as amended (Securities Act), afforded by Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2017. Proceeds from the private placement were approximately $835.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase of the outstanding 2020 Second Lien Notes and will use an additional amount of the net proceeds to redeem the remaining amount of such notes, discussed further below, and for general corporate purposes.

On February 9, 2017 (Successor), we commenced a cash tender offer for any and all of our outstanding 2020 Second Lien Notes and on February 15, 2017, we received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to purchase such notes pursuant to the tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017.

## Pending Divestiture of East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total sales price of $500.0 million (the El Halcón Divestiture). The effective date of the proposed sale is January 1, 2017, and we expect to close the transaction in early March 2017. The sale properties include approximately 80,500 net acres prospective for the Eagle Ford formation in East Texas. As of December 31, 2016, estimated proved reserves from these properties were approximately 35.1 MMBoe, or 24% of our estimated year-end 2016 proved reserves. The sale includes approximately 191 gross (135 net) wells that produced approximately 7,600 Boe/d (80% oil) for the year ended December 31, 2016.

The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the agreement, Hawkwood paid into escrow a deposit of $32.5 million at signing, which amount will be applied to the sales price if the transaction closes.

The completion of the El Halcón Divestiture is subject to customary closing conditions. The parties may terminate the sale agreement if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or $100.0 million, or the transaction has not closed on or before March 20, 2017. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the El Halcón Assets on the terms or timing described or at all. If the El Halcón Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.



## Private Placement of Automatically Convertible Preferred Stock

On January 24, 2017 (Successor), we entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which will be convertible into 10,000 shares of common stock, par value $0.0001 per share (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued), for gross proceeds of approximately $400.1 million, equivalent to a placement at $7.25 per common share. We used the net proceeds from the sale of the preferred stock to partially fund the Pecos County Acquisition.

The preferred stock will convert automatically into common stock on the 20th calendar day after we mail a definitive information statement to holders of our common stock notifying them that holders of a majority of our outstanding common stock consented to the issuance of common stock upon conversion of the preferred stock on January 24, 2017 (Successor). The initial conversion price is subject to adjustment in certain circumstances, including stock splits, stock dividends, rights offerings, or combinations of our common stock. No dividends will be due on the convertible preferred stock if it converts into common stock on or before June 1, 2017. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis.

We have agreed to file a registration statement to register the resale of the shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration is not effective by June 27, 2017.

## Acquisition of Southern Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), we entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which we agreed to acquire a total of 20,901 net acres and related assets in the Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $705.0 million (the Pecos County Acquisition). The effective date of the acquisition is November 1, 2016, and we closed the transaction on February 28, 2017.

Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d (72% oil, 15% NGLs, 13% natural gas). We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production. After closing, we plan to operate two rigs.

The purchase price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. We funded the Pecos County Acquisition with the net proceeds from the private placement of our preferred stock and borrowings under our Senior Credit Agreement.

Following the agreement with Samson, we have agreed to acquire additional interests in the acreage from a non-operating owner for approximately $22.3 million. This incremental acquisition includes 594 additional net acres and approximately 160 Boe/d of current production and is expected to close in early March 2017.

## Option Agreement to Acquire Southern Delaware Basin Assets (Ward County, Texas)

On December 9, 2016 (Successor), we entered into an agreement with a private company, pursuant to which we have acquired the rights to purchase up to 15,040 net acres located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations.



The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. We paid $5.0 million for the option for the Southern Tract and are currently drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017.

## Reorganization

The prices of crude oil and natural gas declined dramatically from mid-year 2014 through 2016, reaching multi-year lows in late 2015 and early 2016, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weak demand in emerging markets, and OPEC's decision to sustain high production levels during this period. In response to these developments, among other things, in 2015 and 2016 we reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements.

These efforts proved insufficient in light of continued low commodity prices to ensure our ability to weather the downturn or position us to take advantage of opportunities that might arise. Accordingly, on July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a prepackaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. Prior to filing the chapter 11 bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), to support a restructuring in accordance with the terms of a plan of reorganization as described therein (the Plan). On September 8, 2016, the Halcón Entities received confirmation of their joint prepackaged plan of reorganization from the Bankruptcy Court and subsequently emerged from chapter 11 bankruptcy on September 9, 2016 (the Effective Date).

Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

• the Predecessor Credit Agreement was refinanced and replaced with the DIP Facility, which was subsequently converted into the Senior Credit Agreement;

• the Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;

• the Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;



## Table of Contents

- the Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

- the Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;

• the general unsecured claims were unimpaired and paid in full in the ordinary course;

• all outstanding shares of the preferred stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and

• all of the outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

Each of the foregoing percentages of equity in the reorganized company were as of September 9, 2016 and subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

## Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (ASC) 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to September 9, 2016 are not comparable to our consolidated financial statements prior to September 9, 2016. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" related to the financial position and results of operations of the Company prior to, and including, September 9, 2016, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Fresh-start Accounting," for further details.

## HK TMS Divestiture

On September 30, 2016 (Successor), certain of our wholly-owned subsidiaries executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which the transaction is referred to as the HK



TMS Divestiture. HK TMS was previously a wholly-owned subsidiary of ours and held all of our oil and natural gas properties in the Tuscaloosa Marine Shale. In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the consolidated balance sheets of HK TMS, from and after such date. The Tuscaloosa Marine Shale properties generated net production of approximately 530 Boe/d during the nine months ended September 30, 2016 and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

## Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016.

## DIP Facility

In connection with the chapter 11 bankruptcy proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under our Predecessor Credit Agreement. Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement on the Effective Date. Loans under the DIP Facility bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or



at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the utilization of the DIP Facility.

## 2017 Capital Budget

We expect to spend approximately $300 million on drilling and completion capital expenditures during 2017. In addition, we expect to spend approximately $15 million on infrastructure, seismic and other in 2017. Approximately 65% of our 2017 drilling and completion budget is expected to be spent in the Bakken/Three Forks formations in North Dakota and approximately 35% is budgeted for the Southern Delaware Basin. Our 2017 drilling and completion budget currently contemplates running two to three operated rigs during the year, is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our budgeted 2017 capital expenditures with cash flows from operations and, to a lesser extent, with borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves in an economical manner is critical to our long-term success.

## Business Strategy

Our primary long-term objective is to increase stockholder value by growing reserves, production and cash flow. To accomplish this objective, we intend to execute the following business strategies:

• Develop and Grow Our Liquids Rich Resource-Style Acreage Positions Using Our Proven Development Expertise. We plan to continue to acquire high quality assets in liquids-rich resource plays to improve our asset quality and expand our drilling inventory. We plan to leverage our management team's expertise and the latest available technologies to economically develop our existing property portfolio in addition to any assets we may acquire. We are the operator for the majority of our acreage, which gives us control over the timing of capital expenditures, execution and costs. It also allows us to adjust our capital spending based on drilling results and the economic environment. Our leasing strategy is to pursue long-term contracts that allow us to maintain flexible development plans and avoid short-term obligations to drill wells, as have been common in other resource plays. As operator, we are also able to evaluate industry drilling results and implement improved operating practices which may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.

• Manage Our Property Portfolio Actively. We continually evaluate our property base to identify and divest non-core assets and higher cost or lower volume producing properties with limited development potential, which allows us to focus on a portfolio of core properties with the greatest economic potential to increase our proved reserves and production.



## Table of Contents

• Maintain Strong Balance Sheet and Financial Flexibility. We believe our cash, internally generated cash flows, borrowing capacity, non-core asset sales and access to capital markets will provide us with sufficient liquidity to execute our current capital program and strategy. We have no near term debt maturities. Our management team is focused on maintaining a strong balance sheet. We also employ a hedging program to reduce the variability of our cash flows used to support our capital spending.

## Our Competitive Strengths

We have a number of competitive strengths that we believe will allow us to successfully execute our business strategies:

• Proven Management Team. Our management team and technical professionals, including geologists and engineers, have decades of combined experience in the industry and a track record for creating shareholder value.

Premier Asset Base. Our proved reserves, production and acreage are located in concentrated positions in two premier onshore U.S. basins. These basins provide exposure to a variety of reservoir formations, each of which has its own characteristics that impact the costs to drill, complete and operate as well as the composition (and therefore value) of the hydrocarbon stream. We believe that this geographic diversity provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns and access to multiple key end markets, which mitigates our exposure to temporary price dislocations in any one market.

Extensive Experience in Resource Plays. Our team has significant experience in all aspects of the development of resource plays. We have been successful in consistently improving drilling times and reserve recoveries through innovation, the use of new technologies and a focus on controlling costs. In addition to our core strength in exploration and production, our personnel have experience in building midstream infrastructure and have managed oilfield service activities.

Strong Technical Team. We believe that there are certain competitive advantages to be gained by employing a highly skilled technical staff. Our technical team has significant experience and expertise in applying the most sophisticated technologies used in conventional and unconventional resource style plays, including 3-D seismic interpretation, horizontal drilling, deep onshore drilling, comprehensive multi-stage hydraulic fracture stimulation programs, and other exploration, production, and processing technologies. We believe this technical expertise is partly responsible for our management team's strong track record of successful exploration and development, including new discoveries and defining core producing areas in emerging plays.

## Oil and Natural Gas Reserves

The proved reserves estimates shown herein for the years ended December 31, 2016 (Successor), 2015 and 2014 (Predecessor) have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves report incorporated herein are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. Mr. Henson, a Licensed Professional Engineer in the State of Texas (No. 73964), has been practicing consulting petroleum engineering at Netherland, Sewell since 1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas (No. 441), has been a practicing petroleum geoscience consultant at Netherland, Sewell since 1989 and has over ten years of prior industry experience. He graduated from Texas A&M University in 1978 with



a Bachelor of Science Degree in Geology. Netherland, Sewell has reported to us that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our board of directors has established a reserves committee composed of three independent directors, all of whom have experience in energy company reserve evaluations. Our independent engineering firm reports jointly to the reserves committee and to our Senior Vice President of Corporate Reserves. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to our board of directors as to whether to approve the report prepared by our independent engineering firm. Ms. Tina Obut, our Senior Vice President of Corporate Reserves, is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. She graduated from Marietta College with a Bachelor of Science degree in Petroleum Engineering, received a Master of Science degree in Petroleum and Natural Gas Engineering from Penn State University and a Master of Business Administration degree from the University of Houston.

The reserves information in this Annual Report on Form 10-K represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary significantly. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. For additional information regarding estimates of proved reserves, the preparation of such estimates by Netherland, Sewell and other information about our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—"Supplemental Oil and Gas Information (Unaudited)."

Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2016 (Successor). Average prices for the 12-month period were as follows: West Texas Intermediate (WTI) crude oil spot price of $42.75 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.481 per MMBtu, as adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.

The following table presents certain proved reserve information as of December 31, 2016 (Successor).

<table><tr><td>Proved Reserves (MBoe) \( ^{(1)} \)</td><td></td></tr><tr><td>Developed</td><td>85,908</td></tr><tr><td>Undeveloped</td><td>62,706</td></tr><tr><td>Total</td><td>148,614</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.



The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2016 (Successor) and 2015 (Predecessor). Shut-in wells currently not capable of production are excluded from the well information below.

<table><tr><td rowspan="2"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td colspan="2">2016</td><td colspan="2">2015</td></tr><tr><td></td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Oil</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>1,470</td><td>356.9</td><td>1,384</td><td>326.5</td></tr><tr><td>Natural Gas</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>71</td><td>36.8</td><td>74</td><td>42.6</td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>1,541</td><td>393.7</td><td>1,458</td><td>369.1</td></tr></table>

## Oil and Natural Gas Production

## Core Resource Plays

In general, our core resource plays are characterized by high oil and liquids-rich natural gas content in thick, continuous sections of source rock that can provide repeatable drilling opportunities and significant initial production rates. Our core resource plays are as follows:

## Bakken/Three Forks Formations

We have working interests in approximately 116,000 net acres as of December 31, 2016 (Successor) prospective in the Bakken/Three Forks formations in North Dakota. Multiple initiatives are underway to lower costs and improve recoveries in our operated project areas. We expect to spud 45 to 50 gross horizontal wells on our operated acreage in 2017 with an average working interest of 72%. In 2017, we expect to operate on average two rigs in the Williston Basin. As of December 31, 2016 (Successor), we had approximately 300 operated wells producing in this area in addition to minor working interests in hundreds of non-operated wells. Our average daily net production from this area for the year ended December 31, 2016 (Successor) was approximately 27,600 Boe/d. As of December 31, 2016 (Successor), estimated proved reserves for the Bakken/Three Forks formations were approximately 112.3 MMBoe, of which approximately 64% were classified as proved developed and approximately 36% as proved undeveloped.

## Delaware Basin

On February 28, 2017, we acquired 20,901 net acres in the Southern Delaware Basin in Pecos and Reeves Counties, Texas and we also have the option to acquire up to 15,040 net acres in Ward and Winkler Counties, Texas. If we exercise the options in full, we will have working interests in 35,941 net acres prospective for the Wolfcamp, Bone Spring and other formations in West Texas.

Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d. We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production.

## Non-core Areas

## East Texas Eagle Ford Formation (El Halcón)

We have working interests in approximately 80,500 net acres as of December 31, 2016 (Successor) prospective for the Eagle Ford formation in Brazos, Burleson, and Robertson Counties, Texas, with targeted depths ranging from 7,000 feet to 10,000 feet. We finished 2016 with no operated rigs and approximately 191 gross (135 net) producing wells in this area. As of December 31, 2016 (Successor), estimated proved reserves for the El Halcón area were approximately 35.1 MMBoe, of which



## Table of Contents

approximately 36% were classified as proved developed and approximately 64% as proved undeveloped. Our average daily net production from this area for the year ended December 31, 2016 (Successor) was approximately 7,600 Boe/d. On January 24, 2017 (Successor), we entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC for the sale of the El Halcón Assets for a total sales price of $500.0 million. The transaction is expected to close in early March 2017.

## Other Non-core Areas

We have other oil and natural gas properties with varying working interests located in the Utica/Point Pleasant formations in Ohio and Pennsylvania and the Austin Chalk Trend in East Texas. Production from these other non-core areas totaled approximately 1,500 Boe/d for the year ended December 31, 2016 (Successor). As of December 31, 2016 (Successor), estimated proved reserves for these properties were approximately 1.2 MMBoe in aggregate, of which all were classified as proved developed. We may consider divesting certain of these assets over time.

## Liquids-Rich Exploratory Plays

In addition to the disclosed areas, we may acquire acreage in other unconventional exploratory plays as opportunities arise. Our strategy for our exploratory projects is to use our in-house geologic and engineering expertise to identify undeveloped areas that we believe are prospective for oil or liquids-rich production. We can provide no assurance that any of these exploratory areas, or any wells we subsequently drill in the formations we have targeted for exploration and development, will be successful.

## Risk Management

We have designed a risk management policy for the use of derivative instruments to provide partial protection against certain risks relating to our ongoing business operations, such as commodity price declines. Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales on future oil and natural gas production. Our objective generally is to hedge 70-80% of our anticipated oil and natural gas production for the next 18 to 24 months. However, our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. Our hedge policies and objectives change as our operational profile changes and/or commodity prices. Our future performance is subject to commodity price risks and our future cash flows from operations may be subject to greater volatility than historically. We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivatives available, we typically use costless collar agreements, swap agreements and deferred put options to attempt to manage price risk more effectively. The costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the swap agreement. Under deferred put option agreements, we pay a fixed premium to lock in a specified floor price for a specified future period. If the index price of oil or natural gas falls below the contracted floor price, the counterparty pays us the difference between the index price and the floor price (netted against the fixed premium payable to the counterparty). If the index price rises above floor price, we pay the fixed premium.



It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Consolidated Financial Statements and Supplementary Data—Note 9, "Derivative and Hedging Activities," for additional information.

## Oil and Natural Gas Operations

Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties. Generally, oil and natural gas leases remain in force as long as production in paying quantities is maintained. Leases on undeveloped oil and natural gas properties are typically for a primary term of three to five years within which we are generally required to develop the property or the lease will expire. In some cases, the primary term of leases on our undeveloped properties can be extended by option payments; the amount of any payments and time extended vary by lease.

The table below sets forth the results of our drilling activities for the periods indicated:

<table><tr><td rowspan="3"></td><td colspan="6">Years Ended December 31,</td></tr><tr><td colspan="2">2016</td><td colspan="2">2015</td><td colspan="2">2014</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Exploratory Wells:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Productive(1)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Dry</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total Exploratory</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td rowspan="2">—</td></tr><tr><td>Extension Wells:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Productive(1)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Dry</td><td>54</td><td>8.5</td><td>72</td><td>18.1</td><td>207</td><td>51.1</td></tr><tr><td>Total Extension</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Development Wells:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Productive(1)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Dry</td><td>36</td><td>22.1</td><td>112</td><td>30.9</td><td>113</td><td>47.2</td></tr><tr><td>Total Development</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total Wells:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Productive(1)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Dry</td><td>90</td><td>30.6</td><td>184</td><td>49.0</td><td>320</td><td>98.3</td></tr><tr><td>Total</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr></table>

(1) Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly extension or exploratory wells where there is no production history.

We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil



and natural gas leases that have varying provisions. The following table presents a summary of our acreage interests as of December 31, 2016:

<table><tr><td rowspan="2">State</td><td colspan="3">Developed Acreage</td><td colspan="3">Undeveloped Acreage</td><td colspan="3">Total Acreage</td></tr><tr><td>Gross</td><td>Net</td><td></td><td>Gross</td><td>Net</td><td></td><td>Gross</td><td>Net</td><td></td></tr><tr><td>Montana</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>7,352</td><td>1,616</td><td></td><td>4,073</td><td>1,644</td><td></td><td>11,425</td><td>3,260</td><td></td></tr><tr><td>North Dakota</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>261,028</td><td>107,827</td><td></td><td>42,342</td><td>8,256</td><td></td><td>303,370</td><td>116,083</td><td></td></tr><tr><td>Ohio</td><td></td><td>3,134</td><td></td><td>3,122</td><td>37,059</td><td></td><td>35,943</td><td>40,193</td><td>39,065</td></tr><tr><td>Oklahoma</td><td></td><td>—</td><td></td><td>—</td><td>27,694</td><td></td><td>15,002</td><td>27,694</td><td>15,002</td></tr><tr><td>Pennsylvania</td><td></td><td>917</td><td></td><td>852</td><td>74,758</td><td></td><td>72,746</td><td>75,675</td><td>73,598</td></tr><tr><td>Texas</td><td></td><td>285,436</td><td></td><td>173,039</td><td>54,874</td><td></td><td>36,926</td><td>340,310</td><td>209,965</td></tr><tr><td>Total Acreage</td><td></td><td>557,867</td><td></td><td>286,456</td><td>240,800</td><td></td><td>170,517</td><td>798,667</td><td>456,973</td></tr></table>

The table below reflects the percentage of our total net undeveloped and mineral acreage as of December 31, 2016 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included or do not pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease.



For our proved undeveloped locations that are not scheduled to be drilled until after lease expiration, we continually review our near-term lease expirations, actively pursue lease extensions and renewals and modify our drilling schedules in order to preserve the leases.

At December 31, 2016 (Successor), we had estimated proved reserves of approximately 148.6 MMBoе comprised of 119.6 MMBoеs of crude oil, 15.6 MMBoеs of natural gas liquids, and 80.2 Bcf of natural gas. The following table sets forth, at December 31, 2016 (Successor), these reserves:

<table><tr><td></td><td>Proved Developed</td><td>Proved Undeveloped</td><td>Total Proved</td></tr><tr><td>Oil (MBbls)</td><td></td><td></td><td></td></tr><tr><td></td><td>67,983</td><td>51,617</td><td>119,600</td></tr><tr><td>Natural Gas Liquids (MBbls)</td><td></td><td></td><td></td></tr><tr><td></td><td>9,337</td><td>6,304</td><td>15,641</td></tr><tr><td>Natural Gas (MMcf)</td><td></td><td></td><td></td></tr><tr><td></td><td>51,525</td><td>28,713</td><td>80,238</td></tr><tr><td>Equivalent (MBoe) \( ^{(1)} \)</td><td></td><td></td><td></td></tr><tr><td></td><td>85,908</td><td>62,706</td><td>148,614</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.



At December 31, 2016 (Successor), our estimated proved undeveloped (PUD) reserves were approximately 62.7 MMBoe, a 2.2 MMBoe net decrease over the previous year's estimate of 64.9 MMBoe. The following table details the changes in PUD reserves for 2016 (in MBoe):

<table><tr><td>Beginning proved undeveloped reserves at December 31, 2015 (Predecessor)</td><td>64,919</td></tr><tr><td>Undeveloped reserves transferred to developed</td><td>(7,510)</td></tr><tr><td>Revisions</td><td>(9,314)</td></tr><tr><td>Purchases</td><td>526</td></tr><tr><td>Divestitures</td><td>(246)</td></tr><tr><td>Extension and discoveries</td><td>14,331</td></tr><tr><td>Ending proved undeveloped reserves at December 31, 2016 (Successor)</td><td>62,706</td></tr></table>

The decrease in PUD reserves was due to a negative revision associated with the decline in the unweighted 12-month average prices of oil and natural gas during 2016. Negative revisions of approximately 9 MMBoE were largely associated with PUD locations in the Bakken/Three Forks and El Halcón areas that became uneconomic at the lower unweighted 12-month average prices of oil and natural gas as of December 31, 2016 (Successor), or were removed because they no longer met the SEC five year development requirement as we have reduced our capital spending since the prior year as a result of the sustained decline in oil and natural gas prices. Further reductions of approximately 8 MMBoE in PUD reserves were the direct result of development through our drilling program and the associated transfer of those reserves to proved developed reserves, primarily in the Bakken/Three Forks and El Halcón areas.

As of December 31, 2016 (Successor), all of our PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2016, approximately $181.7 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line open hole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells. Our management team has been a leader in data gathering and evaluation in these areas and was instrumental in developing consortiums that allow various operators to exchange data. We relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves.

The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. For additional information on our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—"Supplemental Oil and Gas Information (Unaudited)."

We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations. Accordingly, all costs incurred in the acquisition, exploration, and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, direct internal costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test. Our net book value of oil and



natural gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes of $754.8 million and $420.9 million for the period from January 1, 2016 through September 9, 2016 (Predecessor), and the period from September 10, 2016 through December 31, 2016 (Successor), respectively. See further discussion in Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, "Oil and Natural Gas Properties."

Capitalized costs of our evaluated and unevaluated properties at December 31, 2016 (Successor), 2015 and 2014 (Predecessor) are summarized as follows (in thousands):

<table><tr><td rowspan="2"></td><td colspan="2">Successor</td><td colspan="2">Predecessor</td></tr><tr><td>December 31, 2016</td><td>December 31, 2015</td><td>December 31, 2014</td><td></td></tr><tr><td>Oil and natural gas properties (full cost method):</td><td></td><td></td><td></td><td></td></tr><tr><td>Evaluated</td><td>$ 1,269,034</td><td>$ 7,060,721</td><td>$ 6,390,820</td><td></td></tr><tr><td>Unevaluated</td><td>316,439</td><td>1,641,356</td><td>1,829,786</td><td></td></tr><tr><td>Gross oil and natural gas properties</td><td>1,585,473</td><td>8,702,077</td><td>8,220,606</td><td></td></tr><tr><td>Less—accumulated depletion</td><td>(465,849)</td><td>(5,933,688)</td><td>(2,953,038)</td><td></td></tr><tr><td>Net oil and natural gas properties</td><td>$ 1,119,624</td><td>$ 2,768,389</td><td>$ 5,267,568</td><td></td></tr></table>



The following table summarizes our oil, natural gas and natural gas liquids production volumes, average sales price per unit and average costs per unit. In addition, this table summarizes our production for each field that contains 15% or more of our total proved reserves:

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil—MBbl</td><td></td><td></td><td></td><td></td></tr><tr><td>Bakken / Three Forks</td><td>2,639</td><td>5,282</td><td>8,702</td><td>9,316</td></tr><tr><td>El Halcón</td><td>566</td><td>1,613</td><td>2,840</td><td>2,708</td></tr><tr><td>Other</td><td>45</td><td>223</td><td>477</td><td>763</td></tr><tr><td>Total</td><td>3,250</td><td>7,118</td><td>12,019</td><td>12,787</td></tr><tr><td>Natural gas—MMcf</td><td></td><td></td><td></td><td></td></tr><tr><td>Bakken / Three Forks</td><td>1,966</td><td>4,003</td><td>5,673</td><td>3,861</td></tr><tr><td>El Halcón</td><td>314</td><td>817</td><td>1,489</td><td>976</td></tr><tr><td>Other</td><td>731</td><td>1,740</td><td>2,961</td><td>3,975</td></tr><tr><td>Total</td><td>3,011</td><td>6,560</td><td>10,123</td><td>8,812</td></tr><tr><td>Natural gas liquids—MBbl</td><td></td><td></td><td></td><td></td></tr><tr><td>Bakken / Three Forks</td><td>384</td><td>791</td><td>918</td><td>591</td></tr><tr><td>El Halcón</td><td>78</td><td>213</td><td>382</td><td>278</td></tr><tr><td>Other</td><td>39</td><td>92</td><td>157</td><td>244</td></tr><tr><td>Total</td><td>501</td><td>1,096</td><td>1,457</td><td>1,113</td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Total MBoe(1)</td><td>4,253</td><td>9,307</td><td>15,163</td><td>15,369</td></tr><tr><td>Average daily production—Boe(1)</td><td>37,637</td><td>36,787</td><td>41,542</td><td>42,107</td></tr><tr><td>Average price per unit:(2)</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil price—Bbl</td><td>$ 43.01</td><td>$ 34.85</td><td>$ 42.63</td><td>$ 83.78</td></tr><tr><td>Natural gas price—Mcf</td><td>2.24</td><td>1.45</td><td>2.22</td><td>4.21</td></tr></table>



<table><tr><td>Natural gas liquids price—Bbl</td><td>12.01</td><td>7.23</td><td>9.35</td><td>33.66</td></tr><tr><td>Barrel of oil equivalent price—Boe(1)</td><td>35.87</td><td>28.53</td><td>36.17</td><td>74.56</td></tr><tr><td>Average cost per Boe:</td><td></td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td>$ 5.26</td><td>$ 5.38</td><td>$ 6.83</td><td>$ 8.47</td></tr><tr><td>Workover and other</td><td>2.47</td><td>2.42</td><td>1.38</td><td>1.05</td></tr><tr><td>Taxes other than income</td><td>2.91</td><td>2.63</td><td>3.22</td><td>6.92</td></tr><tr><td>Gathering and other</td><td>3.45</td><td>3.15</td><td>2.66</td><td>1.74</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid or received on settled commodities derivative contracts as we did not elect to apply hedge accounting.



The average crude oil and natural gas sales prices above do not reflect the impact of cash paid on, or cash received from, settled derivative contracts as these amounts are reflected as "Net gain (loss) on derivative contracts" in the consolidated statements of operations, consistent with our decision not to elect hedge accounting. Including this impact, during the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), average crude oil sales prices were $68.99 and $69.25 per Bbl and average natural gas sales prices were $2.33 and $1.58 per Mcf, respectively. For the year ended December 31, 2015 and 2014 (Predecessor), including the impact of our settled derivative contracts, average crude oil sales prices were $78.50 and $84.72 per Bbl and average natural gas sales prices were $3.06 and $4.06 per Mcf, respectively.

## Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States, the states in which our properties are located and tribal regulations in North Dakota. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

## Other Business Matters

## Markets and Major Customers

The purchasers of our oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, we have not experienced any significant losses from uncollectible accounts. For the combined periods of September 10, 2016 through December 31, 2016 (Successor), and January 1, 2016 through September 9, 2016 (Predecessor), two individual purchasers of our production, Crestwood Midstream Partners, formerly Arrow Field Services LLC (Crestwood), and Suncor Energy Marketing Inc. (Suncor), each accounted for more than 10% of our total sales, collectively representing 58% of our total sales. In 2015 and 2014, three individual purchasers, Crestwood, Sunoco Inc. and Suncor, each accounted for more than 10% of our total sales, collectively representing 57% and 66% of our total sales for the year, respectively.

## Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.



## Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental releases of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position or cash flows. For further discussion on risks see Item 1A. Risk Factors.

## Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.

The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

## Environmental Regulations

Our operations are subject to stringent federal, state, tribal and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection



Agency, commonly referred to as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

Beyond existing requirements, new programs and changes in existing programs, may address various aspects of our business, including natural occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.

## Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste. Periodically, however, there are proposals to lift the existing exemption for oil and gas wastes and reclassify them as hazardous wastes or to subject them to enhanced solid waste regulation. If such proposals were to be enacted, they could have a significant impact on our operating costs and those of all the industry in general. In the ordinary course of our operations moreover, some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes have occurred at locations we own or at which we have operations. These properties and the materials or wastes released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we have been and may be required to remove or remediate such materials or wastes.

## Water Discharges

Our operations are also subject to the federal Clean Water Act and analogous state laws. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff.



This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we are upgrading storm water management practices at some facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and will need to make only minor modifications to existing facilities and operations that would not have a material effect on us. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil. In the event of a discharge of oil into U.S. waters we could be liable under the Oil Pollution Act for clean up costs, damages and economic losses.

Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (SDWA), the Underground Injection Control (UIC) regulations promulgated under the SDWA and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

## Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short- or long-term. In particular, the well completion technique known as hydraulic fracturing, which is used to stimulate production of oil and natural gas, has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depths to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

Working at the direction of Congress, the EPA has completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. The EPA has also finalized pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants. Beyond that, several environmental groups have petitioned the EPA to extend toxic release reporting requirements under the Emergency Planning and Community Right-to-Know Act to the oil and natural gas extraction industry and to require disclosure under the Toxic Substances Control Act of chemicals used in fracturing. Congress might likewise consider legislation to amend the federal SDWA to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, already have issued similar disclosure rules.

In addition, the Department of the Interior has promulgated regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations. States similarly have been imposing new restrictions or bans on hydraulic fracturing. Even local jurisdictions, such as Denton, Texas and several cities in Colorado, have adopted,



or tried to adopt, regulations restricting hydraulic fracturing. Additional hydraulic fracturing requirements at the federal, state, tribal or local level may limit our ability to operate or increase our operating costs.

## Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

In 2012 and 2016, the EPA issued air regulations for the oil and natural gas industry that address emissions from certain new sources of volatile organic compounds, sulfur dioxide, air toxics, and methane. The rules include the first federal air standards for natural gas and oil wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks. Compliance with these regulations has imposed additional requirements and costs on our operations. The EPA also has started to consider whether to extend such regulations to existing wells.

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

## Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response increasingly governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and several countries, including those comprising the European Union, have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have been implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emissions targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the EPA has issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from our oil and natural gas facilities. Beyond its measuring and reporting rules, the EPA has issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step in issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

In addition, the Obama Administration developed a Strategy to Reduce Methane Emissions that was intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas



industry as compared to 2012 levels. Consistent with that strategy, the EPA issued its air rules for oil and gas production sources, and the federal Bureau of Land Management (BLM) promulgated standards for reducing venting and flaring on public lands.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and reduce demand for our products.

## The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

## Threatened and endangered species, migratory birds, and natural resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Water Act. The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties, may result.

## Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration's hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

## Employees and Principal Office

As of December 31, 2016 (Successor), we had 245 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

As of December 31, 2016 (Successor), we leased corporate office space in Houston, Texas at 1000 Louisiana Street, where our principal offices are located. We also lease corporate office space in Denver, Colorado as well as a number of other field office locations.



## Access to Company Reports

We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Securities Exchange Act of 1934, as amended. We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Forms 3, 4 and 5 filed on behalf of directors and officers, and any amendments to such reports, available free of charge through our corporate website at www.halconresources.com as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. In addition, our insider trading policy, regulation FD policy, equity-based incentive grant policy, corporate governance guidelines, code of conduct, code of ethics, audit committee charter, compensation committee charter, nominating and corporate governance committee charter and reserves committee charter are available on our website under the heading "Investor Relations—Corporate Governance". Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the code of conduct and the code of ethics for our Chief Executive Officer and senior financial officers and any waivers applicable to senior officers as defined in the applicable code, as required by the Sarbanes-Oxley Act of 2002. You may also read and copy any document we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, our reports, proxy and information statements, and our other filings are also available to the public over the internet at the SEC's website at www.sec.gov. Unless specifically incorporated by reference in this Annual Report on Form 10-K, information that you may find on our website is not part of this report.

## ITEM 1A. RISK FACTORS

## Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our Senior Credit Agreement will be subject to periodic redeterminations based in part on current oil and natural gas prices and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

• the domestic and foreign supply of oil and natural gas;

• the ability of members of the Organization of Petroleum Exporting Countries and other producing countries to agree upon and maintain oil prices and production levels;

• social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

• the level of consumer product demand;

• the growth of consumer product demand in emerging markets, such as China;

• labor unrest in oil and natural gas producing regions;

• weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

• the price and availability of alternative fuels;



## Table of Contents

• the price of foreign imports;

• worldwide economic conditions; and

• the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

Our actual financial results may vary materially from the projections that we filed with the bankruptcy court in connection with the confirmation of our plan of reorganization.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of our plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

## Our historical financial information may not be indicative of our future financial performance.

On the effective date of our emergence from bankruptcy on September 9, 2016 we adopted fresh-start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and we have no beginning or ending retained earnings or deficit balances. Accordingly, our financial condition and results of operations following our emergence from chapter 11 bankruptcy will not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, as a result of the implementation of our plan of reorganization and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance.

## Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Under the plan of reorganization, the composition of our Board of Directors (the Board) changed significantly from an eleven member Board with terms of one year to, upon emergence, a nine member Board, structured into three tiers and classified into staggered three year terms. Only three of our current directors served on our Board previously and a total of six of our directors were designated by Franklin Advisors, Inc. and Ares Management LLC. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine our future.

## There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

As of December 31, 2016, funds advised by Franklin Advisors, Inc. and Ares Management LLC held approximately 36% and 19%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that,



in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into registration rights agreements with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We are currently authorized to issue 1.0 billion shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of December 31, 2016, we had outstanding approximately 93.0 million shares of common stock and warrants and options to purchase an aggregate of 10.1 million shares of our common stock. On February 27, 2017 (Successor), we issued in a private placement, 5,518 shares of new 8% automatically convertible preferred stock, each share of which is convertible into 10,000 shares of common stock. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis, or approximately 55.2 million shares of common stock.

As of December 31, 2016, we have also reserved an additional 1.7 million shares for future issuance to our directors, officers and employees as restricted stock or stock option awards pursuant to our 2016 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

Our business requires substantial capital expenditures primarily to fund our drilling program. We may also continue to selectively increase our acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. In addition, it is possible that we will acquire acreage in other areas that we believe are prospective for oil and natural gas production and expend capital to develop such acreage. We expect to use borrowings under our Senior Credit Agreement and proceeds from potential future capital markets transactions, if necessary, to fund capital expenditures that are in excess of our operating cash flow and cash on hand.

Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. As of December 31, 2016, our Senior Credit Agreement had a borrowing base of approximately $600.0 million. As of December 31, 2016, we had $186.0 million of indebtedness.



outstanding, $6.7 million of letters of credit outstanding and $407.3 million of borrowing capacity available under our Senior Credit Agreement. Our borrowing base is determined semi-annually, and may also be redetermined periodically at the discretion of our lenders. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Our Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. In the event we have difficulty meeting the total net indebtedness leverage ratio test or the current ratio test in the future, we would be required to seek additional relief, and there is no assurance that it would be granted.

Additionally, the indentures governing our senior debt contain covenants limiting our ability to incur additional indebtedness, including borrowings under our Senior Credit Agreement, unless we meet one of two alternative tests. The first test applies to all indebtedness and requires that, after giving effect to the incurrence of additional debt, our fixed charge coverage ratio (which is the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters) will be at least 2.0 to 1.0. The second test allows us to incur additional indebtedness, beyond the limitations of the fixed charge coverage ratio test, as long as this additional debt is incurred under Credit Facilities (as defined in our indentures) and generally, the amount thereof is not more than, subject to certain exceptions, the greater of (i) $900 million, (ii) the borrowing base in effect under our Senior Credit Agreement, and (iii) 30% of our adjusted consolidated net tangible assets, or ACTNA. ACTNA is defined in all of our indentures and is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves plus the capitalized cost attributable to our unevaluated properties. Currently, we are permitted to incur additional indebtedness under these incurrence tests, but may be limited in the future. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our ACTNA, and thus could reduce our ability to incur additional indebtedness.

Additionally, our ability to complete future equity offerings is limited by general market conditions. If we are not able to borrow sufficient amounts under our Senior Credit Agreement and/or are unable to raise sufficient capital to fund our capital expenditures, we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, forfeiture of leasehold interests if we are unable or unwilling to renew them, and could force us to sell some of our assets on an untimely or unfavorable basis, each of which could have a material adverse effect on our results and future operations.

## We may be required to take non-cash asset write downs.

We may be required under full cost accounting rules to write down the carrying value of oil and natural gas properties if oil and natural gas prices do not improve or if there are substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or "ceiling," of the book value of oil and natural gas properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using the unweighted arithmetic average of the first day of each month for the 12-month period ending at the balance sheet date. If the net book value of oil and natural gas properties (reduced by any related



net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, SEC regulations require us to impair or "write down" the book value of our oil and natural gas properties.

In the past, due to the sustained decline in the unweighted 12-month average price of oil and natural gas used in the ceiling test calculations, we recorded full cost ceiling test impairments. During 2015, the net book value of our oil and natural gas properties at March 31, June 30, September 30, and December 31, 2015 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes totaling $2.6 billion for the year ended December 31, 2015 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil from $94.99 per Bbl at December 31, 2014 (Predecessor) to $50.28 per Bbl at December 31, 2015 (Predecessor).

During 2016, the net book value of our oil and natural gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each quarter end. As a result, we recorded full cost ceiling test impairments before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor) and $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date, September 9, 2016. The ceiling test impairments at March 31 and June 30, 2016 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. As ceiling test computations depend in part upon the calculated unweighted arithmetic average prices and oil and natural gas prices are inherently volatile, sustained lower commodity prices will continue to have a material impact upon our full cost ceiling test calculation. Continued write downs of oil and natural gas properties may occur until such time as commodity prices have recovered, and remained at recovered levels, so as to increase the 12-month average price used in the ceiling calculation. Depending on the magnitude, a ceiling test write down could materially affect our results of operations.

Costs associated with unevaluated properties, which were approximately $316.4 million at December 31, 2016 (Successor), are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to depletion and the ceiling test limitation.

Historically, we have had substantial indebtedness and we may incur substantially more debt in the future. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We have incurred debt amounting to approximately $964.7 million as of December 31, 2016 (Successor). In addition, on February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025 in a private placement exempt from registration under the Securities Act of 1933, as amended, afforded by Rule 144A and Regulation S, and applicable



state securities laws. The net proceeds from the private placement will fund the repurchase and redemption of all $700 million of our outstanding 2020 Second Lien Notes. As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our Senior Credit Agreement is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have hedging arrangements that are effective in mitigating interest rate fluctuations. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our outstanding senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute "indebtedness" as defined under the indentures. At December 31, 2016 (Successor), our Senior Credit Agreement had a borrowing base of approximately $600.0 million. At December 31, 2016 (Successor), we had $186.0 million of indebtedness outstanding, $6.7 million of letters of credit outstanding and $407.3 million of borrowing capacity available under our Senior Credit Agreement.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional shares of common or preferred stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an "ownership change" is subject to limitations on its ability to utilize its pre-change net operating losses (NOLs), to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years).

We believe we experienced an ownership change in September 2016 as a result of the consummation of our plan of reorganization under chapter 11 of the U.S. Bankruptcy Code. Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our



related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations.

## A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

As of the date of this filing, our corporate credit rating was "B-" with a stable outlook by Standard and Poor's (S&P) and "B3" with a stable outlook by Moody's Investors Service (Moody's). Although we are not aware of any current plans of these or other rating agencies to lower their respective ratings on us or our senior debt, we cannot be assured that our credit ratings will not be downgraded. A downgrade in our credit ratings could negatively impact our cost of capital and our ability to effectively execute aspects of our strategy. If our credit rating were downgraded, it could be difficult for us to raise debt in the public debt markets and the cost of that new debt could be higher than debt we could raise with our current ratings. In addition, a downgrade could impact requirements for us to provide financial assurance of performance under contractual arrangements or derivative agreements.

## We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

As of December 31, 2016 (Successor), we owned leasehold interests in approximately 113,000 net acres in the Utica/Point Pleasant formation (Utica). Our current drilling plans for 2017 do not include any drilling or completion activities on our Utica acreage. Unless production in paying quantities is established on units containing these leases during their terms or unless we pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. As a non-operating leaseholder we have less control over the timing of drilling and are therefore subject to additional risk of expirations.

## We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for



qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of natural gas, condensate or oil being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of weather conditions (which may worsen due to climate changes), accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition, results of operations, cash flows and potentially the borrowing capacity under our Senior Credit Agreement.

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of our reserves.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and



availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2016 (Successor), approximately 42% of our estimated proved reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations, however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

## Our oil and natural gas activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:

human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

• blowouts, fires, hurricanes, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

• unavailability of materials and equipment;

• engineering and construction delays;

• unanticipated transportation costs and delays;

• unfavorable weather conditions;

• hazards resulting from unusual or unexpected geological or environmental conditions;

• environmental regulations and requirements;

• accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or salt water, into the environment;



• hazards resulting from the presence of hydrogen sulfide ( \( H_{2}S \) ) or other contaminants in gas we produce;

• changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

• fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

• the availability of alternative fuels and the price at which they become available.

As a result of these risks, expenditures, quantities and rates of production, revenues and operating costs may be materially affected and may differ materially from those anticipated by us.

## Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns.

We require significant amounts of undeveloped leasehold acreage to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling and completing a well, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including:

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents and shortages or delays in the availability of drilling and completion equipment and services;

• adverse weather conditions, including hurricanes; and

• compliance with governmental requirements.

## We are subject to various contractual limitations that affect the discretion of our management in operating our business.

The indentures governing our debt and our Senior Credit Agreement contain various provisions that may limit our management's discretion in certain respects. In particular, these agreements limit our and our subsidiaries' ability to, among other things:

• pay dividends on, redeem or repurchase shares of our common stock and, under certain circumstances, our convertible preferred stock, and redeem or repurchase our subordinated debt;

• make loans to others;



## Table of Contents

• make investments;

• incur additional indebtedness;

• create certain liens;

• sell assets;

• enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

• consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;

• engage in transactions with affiliates;

• enter into hedging contracts;

• create unrestricted subsidiaries; and

• enter into sale and leaseback transactions.

Compliance with these and other limitations may limit our ability to operate and finance our business and engage in certain transactions in the manner we might otherwise. In addition, if we fail to comply with the limitations under our indentures or Senior Credit Agreement, our creditors, if the agreements so provide, may accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.

## Our business is highly competitive.

The oil and natural gas industry is highly competitive in many respects, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.

The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability. In order to secure drilling rigs and pressure pumping equipment, we have entered into certain contracts that extend over several months and or years. If demand for drilling rigs and pressure pumping equipment subside during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.



We are subject to complex federal, state, local and other laws and regulations that frequently are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

Companies that explore for and develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

• water discharge and disposal permits for drilling operations;

• drilling bonds;

• drilling permits;

• reports concerning operations;

• air quality, air emissions, noise levels and related permits;

• spacing of wells;

• rights-of-way and easements;

• unitization and pooling of properties;

• pipeline construction;

• gathering, transportation and marketing of oil and natural gas;

• taxation; and

• waste transport and disposal permits and requirements.

Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Under environmental, health and safety laws and regulations, we also could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Such laws may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation by oil and natural gas producing states relating to conservation practices and protection of correlative rights. The North Dakota Industrial Commission (NDIC), the State's chief energy regulator, for example, approved comprehensive rules in 2016 for the conservation of crude oil and natural gas that address site



construction, gathering pipelines and spill containment. Such regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. By way of example, in 2015 the EPA lowered the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation will take place over several years; however, the new standard eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

Part of our strategy involves drilling in shale formations, using horizontal drilling and completion techniques. The results of our drilling program using these techniques may be subject to more uncertainties than conventional drilling programs, especially in areas that are new and emerging. These uncertainties could result in an inability to meet our expectations for reserves and production.

The results of our drilling in shale formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history; consequently our predictions of drilling results in these areas are more uncertain. In addition, the use of horizontal drilling and completion techniques used in all of our shale formations involve certain risks and complexities that do not exist in conventional wells. The ultimate success of our drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established.

If our drilling results are less than anticipated our investment in these areas may not be as attractive as we anticipate and could result in material write downs of unevaluated properties and future declines in the value of our undeveloped acreage.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state, tribal and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or in the future plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to amend the federal SDWA to require federal permitting of hydraulic fracturing and the disclosure of chemicals used in the hydraulic fracturing process. Further, the EPA completed a study finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been recently conducted or are under way that focus on environmental aspects of hydraulic fracturing. For example, a federal BLM rulemaking for hydraulic fracturing practices on federal and Indian lands resulted in a 2015 final rule that requires public disclosure of chemicals used in hydraulic fracturing, confirmation that the wells used in fracturing operations meet proper construction standards and development of plans for managing related flowback water. These activities could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.



Certain states, including North Dakota and Texas where we conduct a majority of our operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing.

The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

## Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response, increasingly governments have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration pledged for the Paris Agreement to meet an economy-wide target in 2025 of reducing greenhouse gas emissions by 26-28% below the 2005 level. To help achieve these reductions, federal agencies have been addressing climate change through a variety of administrative actions. The EPA thus issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Consistent with that strategy, the EPA issued final rules in 2016 for new and modified oil and gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. In addition, the BLM has promulgated standards for reducing venting and flaring on public lands. The EPA and BLM actions are part of a series of steps by the Obama Administration that were intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to



force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our products.

## Requirements to reduce gas flaring in North Dakota could have an adverse effect on our operations.

Wells in the Bakken / Three Forks formations in North Dakota, where we have significant operations, yield natural gas as a byproduct of oil production. Bottlenecks in the gas gathering network in certain areas resulted in some of that natural gas being flared instead of processed. In 2014, the NDIC, the State's chief energy regulator, issued an order to reduce the volume of natural gas flared from oil wells in the Bakken / Three Forks formations. The State's current objectives are to cause operators to capture 85% of the natural gas by November 1, 2016, 88% by November 1, 2018 and 91-93% by November 1, 2020. In addition, the NDIC is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. These capture requirements and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

## Crude oil from the Bakken / Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

The United States Department of Transportation (USDOT) has concluded that crude oil from the Bakken / Three Forks formations has a higher volatility than most other crude oil from the United States and thus is more ignitable and flammable. Based on that information, and several fires involving rail transportation of crude oil, USDOT imposed additional requirements for shipping crude oil by rail. Beyond that, the rail industry has adopted increased precautions for crude shipments. Any restrictions that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

Operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal and tribal regulations and laws, any of which may increase our costs and delay our operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation on which we hold approximately 28,500 net acres. In addition, the Three Affiliated Tribes is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.



Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas liquids and natural gas, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

The ongoing implementation of federal legislation enacted in 2010 could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, then President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the SEC and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation.

The CFTC has finalized other regulations implementing the Dodd-Frank Act's provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.



We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.

We have completed in the past and may complete in the future significant acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy, which may include the acquisition of asset packages of producing properties or existing companies or businesses operating in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

• recoverable reserves;

• future oil, natural gas and natural gas liquids prices and their appropriate differentials;

• development and operating costs; and

• potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well or well site, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are generally not able to obtain contractual indemnification for environmental liabilities and normally acquire properties on an "as is" basis.

Significant acquisitions of existing companies or businesses and other strategic transactions may involve additional risks, including:

• diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

• the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with our own while carrying on our ongoing business;

• difficulty associated with coordinating geographically separate organizations;

• the challenge of integrating environmental compliance systems to meet requirements of rapidly changing regulations;

• the challenge of attracting and retaining personnel associated with acquired operations; and

• failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within our expected time frame.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could be materially and adversely affected.



## Table of Contents

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

• personal injury;

• bodily injury;

• third party property damage;

• medical expenses;

• legal defense costs;

• pollution in some cases;

• well blowouts in some cases; and

• workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our financial position, results of operations and cash flows. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover claims made against us in the future.

## Title to the properties in which we have an interest may be impaired by title defects.

We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

## We depend on the skill, ability and decisions of third-party operators of the oil and natural gas properties in which we have a non-operated working interest.

The success of the drilling, development and production of the oil and natural gas properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third-party operator to make decisions, perform their services, discharge their obligations, deal with regulatory agencies, and comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs. Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could materially affect our results of operations.

## Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production, we have entered into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into



## Table of Contents

additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

• our production is less than expected;

• there is a widening of price differentials between delivery points for our production; or

• the counterparties to our hedging agreements fail to perform under the contracts.

We are currently out of compliance with the New York Stock Exchange's average market capitalization requirement and are at risk of the NYSE delisting our common stock, which could materially impair the liquidity and value of our common stock.

Our common stock is currently listed on the New York Stock Exchange (NYSE). On August 12, 2016, we were notified by the NYSE that the average market capitalization of our common stock was less than $50 million over a 30 trading day period, at the same time as our stockholders' equity was less than $50 million. In accordance with NYSE rules, we timely submitted a plan to regain compliance with the average market capitalization requirement, which we successfully executed as a consequence of our emergence from chapter 11 bankruptcy effective September 9, 2016. However, the NYSE has indicated it may take up to two calendar quarters for notice from the NYSE that compliance has been regained.

A delisting of our common stock, either as a result of a failure to regain compliance with the NYSE's average market capitalization requirement or the Company's failure to satisfy other qualitative or quantitative standards for continued listing on the NYSE, could reduce the liquidity and market price of our common stock.

## ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

## ITEM 2. PROPERTIES

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

## ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Item 8. Consolidated Financial Statements and Supplementary Data—Note 11, "Commitments and Contingencies," and is incorporated herein by reference.

From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not currently involved in any legal proceedings, nor are we a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on our financial condition or results of operations.

## ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.



## PART II

## ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Successor common stock trades on the New York Stock Exchange (NYSE) under the symbol HK. On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of our Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of new common stock which began trading on the NYSE on September 12, 2016. The following table sets forth the quarterly high and low sales prices per share of our Successor common stock as reported on the NYSE from September 12, 2016 through December 31, 2016. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Reorganization," for further details.



We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the Board and will be dependent upon then existing conditions, including our prospects, and such other factors, as the Board deems relevant. We are also restricted from paying cash dividends on common stock under our Senior Credit Agreement and under the terms of the indentures governing our other long-term debt.

Approximately 727 registered stockholders of record as of February 23, 2017 held our common stock. In many instances, a stockholder can hold shares through a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

## Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

There were no purchases of equity securities during the three months ended December 31, 2016 (Successor).



## Stock Performance Graph

The following graph and table compare the cumulative total return to our stockholders on our Successor common stock beginning September 12, 2016 through December 31, 2016, relative to the cumulative total returns of the NYSE Composite Index and the S&P Oil & Gas Exploration & Production Index for the same period. The comparison assumes an investment of $100 (with reinvestment of all dividends at the average of the closing stock prices at the beginning and end of the quarter) was made in our Successor common stock on September 12, 2016, and in each of the indexes, and relative performance is tracked through December 31, 2016. The identity of the companies included in the S&P Oil & Gas Exploration & Production Index will be provided upon request.

## COMPARISON OF 4 MONTH CUMULATIVE TOTAL RETURN*
Among Halcón Resources Corporation, the NYSE Composite Index,
and S&P Oil & Gas Exploration & Production index



* 100 invested on 9/12/16 in stock or 8/31/16 in index, including reinvestment of dividends. Fiscal year ending December 31.

## Value of Initial $100 Investment

<table><tr><td></td><td>September 12, 2016</td><td>September 30, 2016</td><td>October 31, 2016</td><td>November 30, 2016</td><td>December 31, 2016</td></tr><tr><td>Halcón Resources Corporation</td><td>$ 100</td><td>$ 86</td><td>$ 82</td><td>$ 88</td><td>$ 86</td></tr><tr><td>NYSE Composite</td><td>100</td><td>100</td><td>98</td><td>101</td><td>104</td></tr><tr><td>S&amp;P Oil &amp; Gas Exploration &amp; Production Index</td><td>100</td><td>103</td><td>86</td><td>108</td><td>99</td></tr></table>



## ITEM 6. SELECTED FINANCIAL DATA

Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

The following table presents selected historical financial data derived from our consolidated financial statements. The following data is only a summary and should be read with our historical consolidated financial statements and related notes contained in this document. Refer to the footnotes in Item 8. Consolidated Financial Statements and Supplementary Data, for details regarding our recent reorganization and adoption of fresh-start accounting, as well as other transactions that could impact the comparability of the following data (in thousands, except per share data):

<table><tr><td rowspan="2"></td><td>Successor</td><td colspan="5">Predecessor</td></tr><tr><td>Period from September 10, 2016 through December 31, 2016(7)</td><td>Period from January 1, 2016 through September 9, 2016(8)</td><td>2015(9)</td><td>2014(10)</td><td>2013(11)</td><td>2012</td></tr><tr><td>Income Statement Data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total operating revenues</td><td>$ 153,362</td><td>$ 266,843</td><td>$ 550,278</td><td>$ 1,148,261</td><td>$ 999,506</td><td>$ 248,322</td></tr><tr><td>Income (loss) from operations</td><td>(415,799)</td><td>(851,617)</td><td>(2,744,506)</td><td>(58,387)</td><td>(1,290,947)</td><td>(29,717)</td></tr><tr><td>Net income (loss)</td><td>(479,193)</td><td>11,958</td><td>(1,922,621)</td><td>315,956</td><td>(1,222,622)</td><td>(53,885)</td></tr><tr><td>Net income (loss) available to common stockholders</td><td>(479,984)</td><td>(32,794)</td><td>(2,006,958)</td><td>282,942</td><td>(1,233,407)</td><td>(142,330)</td></tr><tr><td>Net income (loss) per share of common stock(1):</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 3.40</td><td>$ (16.25)</td><td>$ (4.55)</td></tr><tr><td>Diluted</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 2.93</td><td>$ (16.25)</td><td>$ (4.55)</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="2">Successor</td><td colspan="4">Predecessor</td></tr><tr><td>As of December 31, 2016</td><td>2015</td><td colspan="3">As of December 31, 2014</td><td>2012</td></tr><tr><td>Balance sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Working capital (deficit)</td><td>$ (46,904)</td><td>$ 261,345</td><td>$ (41,977)</td><td>$ (325,756)</td><td>$ (390,111)</td><td></td></tr><tr><td>Total assets</td><td>1,319,670</td><td>3,458,692</td><td>6,383,227</td><td>5,298,986</td><td>5,002,320</td><td></td></tr><tr><td>Total long-term debt, net(2)(3)</td><td>964,653</td><td>2,873,637</td><td>3,695,488</td><td>3,126,318</td><td>1,995,793</td><td></td></tr><tr><td>Redeemable noncontrolling interest(4)</td><td>—</td><td>183,986</td><td>117,166</td><td>—</td><td>—</td><td></td></tr><tr><td>Preferred stock(5)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>695,238</td><td></td></tr><tr><td>Stockholders&#x27; equity(6)</td><td>112,688</td><td>52,414</td><td>1,772,169</td><td>1,447,610</td><td>1,397,982</td><td></td></tr></table>

(1) No cash dividends on our common stock were declared or paid for any periods presented.

(2) Excludes current portion of long-term debt for all periods presented.



(3) On September 9, 2016, upon emergence from chapter 11 bankruptcy, approximately $1.9 billion of our senior notes were cancelled. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Reorganization," for additional information.

(4) On June 16, 2014, HK TMS, LLC (HK TMS), which was then a wholly owned subsidiary of the Company, entered into a transaction with funds and accounts managed by Apollo Global Management, LLC (Apollo), by initially selling 150,000 preferred shares in HK TMS (Membership Interests), which then held all of our acreage in the Tuscaloosa Marine Shale, located in Mississippi and Louisiana. On September 30, 2016, Apollo acquired one hundred percent of the common shares of HK TMS and assumed all obligations relating to the Membership Interests. For additional information regarding these transactions, see Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Divestitures" and Note 12, "Mezzanine Equity."



(5) Predecessor preferred stock outstanding at December 31, 2012 converted into 21.8 million shares of our Predecessor common stock on January 18, 2013, following stockholder approval.

(6) On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of new common stock in total to the Predecessor Company's existing common stockholders, Third Lien Noteholders, Unsecured Noteholders, and the Convertible Noteholder. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Reorganization," for further details.

(7) For the period from September 10, 2016 through December 31, 2016 (Successor), we incurred a $420.9 million full cost ceiling impairment on the carrying value of our oil and natural gas properties. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, "Oil and Natural Gas Properties," for additional information.

(8) For the period from January 1, 2016 through September 9, 2016 (Successor), we incurred a $754.8 million full cost ceiling impairment on the carrying value of our oil and natural gas properties, a $28.1 million impairment on other operating property and equipment, an $81.4 million gain on extinguishment of debt, and a $913.7 million gain on reorganization items due to fresh-start accounting. Refer to the footnotes in Item 8. Consolidated Financial Statements and Supplementary Data, for additional information regarding these events.

(9) For the year ended December 31, 2015 (Predecessor), we incurred a $2.6 billion full cost ceiling impairment on the carrying value of our oil and natural gas properties. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 6, "Oil and Natural Gas Properties," for additional information regarding this impairment.

(10) For the year ended December 31, 2014 (Predecessor), we incurred the following charges, a $239.7 million full cost ceiling impairment on the carrying value of oil and natural gas properties and a $35.6 million impairment on other operating property and equipment. Refer to the footnotes included in Item 8. Consolidated Financial Statements and Supplementary Data, for additional information regarding these impairments.

(11) For the year ended December 31, 2013 (Predecessor), we incurred the following charges which contributed to our net loss for the year, a $1.1 billion full cost ceiling impairment on the carrying value of our oil and natural gas properties, a $228.9 million goodwill impairment, and a $67.5 million impairment of other operating property and equipment.



## ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.

Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

## Overview

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. We were incorporated in Delaware on February 5, 2004, recapitalized on February 8, 2012 and reorganized on September 9, 2016. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in select prospect areas. In the years since, we have primarily focused on the development of acquired properties and also divested non-core assets in order to fund activities in our core resource plays. Our oil and natural gas assets consist of proved reserves and undeveloped acreage positions in unconventional liquids-rich basins/fields, providing us with an extensive drilling inventory in multiple basins that we believe allow for multiple years of production and broad flexibility to direct our capital resources to projects with the greatest potential returns. As discussed below in more detail under "Recent Developments," we have recently acquired certain properties in the Southern Delaware Basin for $705.0 million and entered into an agreement to sell our assets located in the El Hacón area of East Texas for $500.0 million, which is expected to close by early March 2017.

At December 31, 2016 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), using Securities and Exchange Commission (SEC) prices of $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, were approximately 148.6 MMBoe, consisting of 119.6 MMBbs of oil, 15.6 MMBbs of natural gas liquids, and 80.2 Bcf of natural gas. Approximately 58% of our proved reserves were classified as proved developed as of December 31, 2016 (Successor). We maintain operational control of approximately 95% of our proved reserves.

Our total operating revenues for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were approximately $153.4 million and $266.8 million, respectively, or $420.2 million combined, compared to total operating revenues for 2015 of $550.3 million. The decrease in total operating revenues year over year was driven by the sustained decline in the prices of crude oil and, to a lesser extent, natural gas along with a decrease in our average daily production year over year. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, or 37,049 Boe/d combined, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor). In response to the sustained decline in commodity prices we reduced our drilling and completion activities in 2016, running only one rig on average in our most economic drilling area. In



2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 net) wells, all of which were completed and capable of production.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

In 2016, (for the combined Successor and Predecessor periods) we incurred capital expenditures for drilling and completions of approximately $183.9 million. We expect to spend approximately $300 million on drilling and completion capital expenditures during 2017. In addition, we expect to spend approximately $15 million on infrastructure, seismic and other in 2017. Approximately 65% of our 2017 drilling and completion budget is expected to be spent in the Bäkken/Three Forks formations in North Dakota and approximately 35% is budgeted for the Southern Delaware Basin. Our 2017 drilling and completion budget currently contemplates growing to four (on average) operated rigs during the second quarter of 2017, is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our budgeted 2017 capital expenditures with cash flows from operations and, to a lesser extent, borrowings under our Senior Credit Agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may further curtail our capital spending.

Oil and natural gas prices are inherently volatile and have declined dramatically since mid-year 2014. In response to this we have significantly curtailed our capital spending, reduced operating costs, and have incurred substantial asset impairments, primarily as a result of the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for February 2017 of $53.88 per Bbl, and holding it constant for one month to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test limitation would not have generated an impairment at December 31, 2016 holding all other inputs and factors constant. Sustained lower commodity prices would have a material impact upon our full cost ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

## Recent Developments

## Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

On February 16, 2017 (Successor), we issued $850.0 million aggregate principal amount of our new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under the Securities Act of 1933, as amended (Securities Act), afforded by Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year,



beginning on August 15, 2017. Proceeds from the private placement were approximately $835.1 million after deducting initial purchasers' discounts and commissions and offering expenses. We utilized a portion of the net proceeds from the private placement to fund the repurchase of the outstanding 2020 Second Lien Notes and will use an additional amount of the net proceeds to redeem the remaining amount of such notes, discussed further below, and for general corporate purposes.

On February 9, 2017 (Successor), we commenced a cash tender offer for any and all of our 2020 Second Lien Notes and on February 15, 2017, we received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to the tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million aggregate principal amount of outstanding 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017.

## Pending Divestiture of East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of our subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of our oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total sales price of $500.0 million (the El Halcón Divestiture). The effective date of the proposed sale is January 1, 2017, and we expect to close the transaction in early March 2017. The sale properties include approximately 80,500 net acres prospective for the Eagle Ford formation in East Texas. As of December 31, 2016, estimated proved reserves from these properties were approximately 35.1 MMBoE, or 24% of our estimated year-end 2016 proved reserves. The sale includes approximately 191 gross (135 net) wells that produced approximately 7,600 Boe/d (80% oil) for the year ended December 31, 2016.

The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the agreement, Hawkwood paid into escrow a deposit of $32.5 million at signing, which amount will be applied to the sales price if the transaction closes.

The completion of the El Halcón Divestiture is subject to customary closing conditions. The parties may terminate the sale agreement if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or $100.0 million, or the transaction has not closed on or before March 20, 2017. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the El Halcón Assets on the terms or timing described or at all. If the El Halcón Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.

## Private Placement of Automatically Convertible Preferred Stock

On January 24, 2017 (Successor), we entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which will be convertible into 10,000 shares of common stock, par value $0.0001 per share (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued), for gross proceeds of approximately



$400.1 million, equivalent to a placement at $7.25 per common share. We used the net proceeds from the sale of the preferred stock to partially fund the Pecos County Acquisition.

The preferred stock will convert automatically into common stock on the 20th calendar day after we mail a definitive information statement to holders of our common stock notifying them that holders of a majority of our outstanding common stock consented to the issuance of common stock upon conversion of the preferred stock on January 24, 2017 (Successor). The initial conversion price is subject to adjustment in certain circumstances, including stock splits, stock dividends, rights offerings, or combinations of our common stock. No dividends will be due on the convertible preferred stock if it converts into common stock on or before June 1, 2017. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of our outstanding common stock as of December 31, 2016 on an as-converted basis.

We have agreed to file a registration statement to register the resale of the shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration is not effective by June 27, 2017.

## Acquisition of Southern Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), we entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which we agreed to acquire a total of 20,901 net acres and related assets in the Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $705.0 million (the Pecos County Acquisition). The effective date of the acquisition was November 1, 2016, and we closed the transaction on February 28, 2017.

Based on information provided by Samson, we estimate that current net production from the Pecos County Assets is approximately 2,600 Boe/d (72% oil, 15% NGLs, 13% natural gas). We estimate that the Pecos County Assets include a 75% average working interest, with approximately 44% held by production. After closing, we plan to operate two rigs.

The purchase price was subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. We funded the Pecos County Acquisition with the net proceeds from the private placement of our preferred stock and borrowings under our Senior Credit Agreement.

Following the agreement with Samson, we have agreed to acquire additional interests in the acreage from a non-operating owner for approximately $22.3 million. This incremental acquisition includes 594 additional net acres and approximately 160 Boe/d of current production and is expected to close in early March 2017.

## Option Agreement to Acquire Southern Delaware Basin Assets (Ward County, Texas)

On December 9, 2016 (Successor), we entered into an agreement with a private company, pursuant to which we have acquired the rights to purchase up to 15,040 net acres located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. We paid $5.0 million for the option for the Southern Tract and are currently drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017.



## Reorganization

The prices of crude oil and natural gas declined dramatically from mid-year 2014 through 2016, reaching multi-year lows, as a result of robust non-Organization of the Petroleum Exporting Countries' (OPEC) supply growth led by unconventional production in the United States, weak demand in emerging markets, and OPEC's decision to sustain high production levels during this period. In response to these developments, among other things, in 2015 and 2016 we reduced our spending and completed a series of transactions that resulted in the reduction of our debt by approximately $1.1 billion and reduced our annual interest burden by approximately $61.5 million. We also extended the maturity date and amended other provisions of certain of our debt agreements.

These efforts proved insufficient in light of continued low commodity prices to ensure our ability to weather the current downturn or position us to take advantage of opportunities that might arise. Accordingly, on July 27, 2016, we and certain of our subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a prepackaged plan of reorganization in accordance with the terms of the Restructuring Support Agreement discussed below. Prior to filing the chapter 11 bankruptcy petitions, on June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of our 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), our 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of our 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of our 5.75% Series A Convertible Perpetual Preferred Stock (the Preferred Holders), to support a restructuring in accordance with the terms of a plan of reorganization as described therein (the Plan). On September 8, 2016, the Halcón Entities received confirmation of their joint prepackaged plan of reorganization from the Bankruptcy Court and subsequently emerged from chapter 11 bankruptcy on September 9, 2016 (the Effective Date).

Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

• the Predecessor Credit Agreement was refinanced and replaced with the DIP Facility, which was subsequently converted into the Senior Credit Agreement (see below for credit agreement definitions and further details regarding the credit agreements);

• the Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;

• the Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

• the Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

• the Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to



purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;

• the general unsecured claims were unimpaired and paid in full in the ordinary course;

• all outstanding shares of the preferred stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and

• all of the outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.

Each of the foregoing percentages of equity in the reorganized company were as of September 9, 2016 and subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

## Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (ASC) 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to September 9, 2016 are not comparable to our consolidated financial statements prior to September 9, 2016, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Fresh-start Accounting," for more details.

## HK TMS Divestiture

On September 30, 2016 (Successor), certain of our wholly-owned subsidiaries executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which the transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary of ours and held all of our oil and natural gas properties in the Tuscaloosa Marine Shale (TMS). In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the consolidated balance sheets of HK TMS, from and after such date. The TMS properties generated net production of approximately 530 Boe/d during the nine months ended September 30, 2016 and had 1.1 MMBoe of proved reserves at December 31, 2015 (Predecessor).

## Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other



financial institutions party thereto, as lenders, which refinanced the DIP Facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120 \( ^{th} \)  day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016.

## DIP Facility

In connection with the chapter 11 bankruptcy proceedings, we entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under our Predecessor Credit Agreement. Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement on the Effective Date. Loans under the DIP Facility bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the utilization of the DIP Facility.

## Capital Resources and Liquidity

Our near-term capital spending requirements are expected to be funded with cash flows from operations and borrowings under our Senior Credit Agreement, the terms of which are discussed above.

The Senior Credit Agreement contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter period and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017



and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. At December 31, 2016, we had approximately $186.0 million of indebtedness outstanding, $6.7 million letters of credit outstanding and approximately $407.3 million of borrowing capacity available under our Senior Credit Agreement. At December 31, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.

We have in the past obtained amendments to the covenants under our financing agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. For example, under the Predecessor Credit Agreement, we received a reduction in the minimum required interest coverage ratio of 2.0 to 1.0 on March 21, 2014 and again on February 25, 2015. The basis for these amendment and waiver requests was the potential for us to fall out of compliance as a result of our strategic decisions. Declining commodity prices also adversely impacted our ability to comply with these covenants. As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties and completed our reorganization (as described above). Upon consummation of the Plan and emergence from chapter 11 bankruptcy, approximately $2.0 billion of our debt obligations were cancelled, reducing our ongoing interest obligations by more than $200 million annually.

In the event that we are unable to access sufficient capital to fund our business and planned capital expenditures, we may be required to further curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, subject to our forfeitures of leasehold interests to the extent we are unable or unwilling to renew them, and force us to sell some of our assets on an untimely or unfavorable basis, each of which could adversely affect our results of operations and financial condition.

Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. We therefore continuously monitor our liquidity and the capital markets and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.

We strive to maintain financial flexibility while pursuing our drilling plans and evaluating potential acquisitions, and will therefore likely continue to access capital markets (if on acceptable terms) as necessary to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects while sustaining sufficient operating cash levels. Our ability to complete future debt and equity offerings and maintain or increase our borrowing base is subject to a number of variables, including our level of oil and natural gas production, reserves and commodity prices, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly, as they have since mid-year 2014, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge varies from period to period based on our view of current and future market conditions. Our hedge



policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

## Cash Flow

Historically, our primary sources of cash were from operating and financing activities. For the period of January 1, 2016 through September 9, 2016 (Predecessor), cash generated by operating and financing activities was used to fund our drilling and completion program and to support our reorganization plan. For the period of September 10, 2016 through December 31, 2016 (Successor), cash generated by operating activities was used to fund our drilling and completion program and make repayments on our Senior Credit Agreement. See "Results of Operations" for a review of the impact of prices and volumes on sales. The period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) are distinct reporting periods as a result of our emergence from chapter 11 bankruptcy on September 9, 2016 and are not comparable to prior periods.

Net increase (decrease) in cash is summarized as follows (in thousands):

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td colspan="2">Years Ended December 31,</td></tr><tr><td>Cash flows provided by (used in) operating activities</td><td>$ 103,136</td><td>$ 175,348</td><td>$ 466,999</td><td>$ 667,934</td></tr><tr><td>Cash flows provided by (used in) investing activities</td><td>(63,042)</td><td>(227,774)</td><td>(667,132)</td><td>(1,271,093)</td></tr><tr><td>Cash flows provided by (used in) financing activities</td><td>(54,013)</td><td>58,343</td><td>164,446</td><td>644,038</td></tr><tr><td>Net increase (decrease) in cash</td><td>$ (13,919)</td><td>$ 5,917</td><td>$ (35,687)</td><td>$ 40,879</td></tr></table>

Operating Activities. Net cash provided by operating activities for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were $103.1 million and $175.3 million, respectively. Net cash provided by operating activities were $467.0 million and $667.9 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively. Key drivers of net operating cash flows are commodity prices, production volumes, operating costs, and in 2016 and 2015, realized settlements on our derivative contracts.

For the period September 10, 2016 through December 31, 2016 (Successor), cash flows were modestly impacted by changes in our working capital. For the period January 1, 2016 through September 9, 2016 (Predecessor) our net operating cash flows were $175.3 million, which resulted primarily from realized settlements on our derivative contracts that were partially offset by transaction costs related to our chapter 11 bankruptcy and reorganization activities.

For the year ended December 31, 2015, the $467.0 million of net cash provided by operating activities primarily reflects the impact of realized settlements on our derivative contracts of $418.4 million, which largely mitigated the decrease in revenues due to lower commodity prices, as compared to the prior year period. Cash operating expenses also decreased over the prior year period.

For the year ended December 31, 2014, net cash provided by operating activities increased $174.0 million over the prior year. The improvement in operating cash flows primarily reflects the impact of the 26% increase in our average daily production compared to the 2013 period, which drove the increase in operating revenues. Production for 2014 averaged 42,107 Boe/d compared to 33,329 Boe/d in 2013.



Investing Activities. The primary driver of cash used in investing activities is capital spending on our oil and natural gas properties. Net cash used in investing activities for the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) were $63.0 million and $227.8 million, respectively. Net cash used in investing activities was $667.1 million and $1.3 billion for the years ended December 31, 2015 and 2014 (Predecessor), respectively.

During the period of September 10, 2016 through December 31, 2016 (Successor), we spent $61.5 million on oil and natural gas capital expenditures, of which $54.4 million related to drilling and completion costs. During the period of January 1, 2016 through September 9, 2016 (Predecessor), we spent $226.6 million on oil and natural gas capital expenditures, of which $129.5 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, and to a lesser extent, leasing and seismic data. In 2016 (for the combined Successor and Predecessor periods), we participated in the drilling of 90 gross (30.6 net) wells, all of which were completed and capable of production.

In 2015, we used $659.4 million of cash on oil and natural gas capital expenditures, of which $508.4 million related to drilling and completion costs and the remainder was primarily associated with capitalized interest, leasing and seismic data. We participated in the drilling of 184 gross (49.0 net) wells, all of which were completed and capable of production. We significantly decreased our capital spending for 2015, as compared to capital expenditure levels in prior years, in response to the significant decrease in crude oil prices over the latter of 2014 and throughout 2015, and our expectation that prices may not recover in the near term. Cash paid for drilling and completion costs during the year were attributable to both costs incurred before we slowed our drilling and completion program and costs related to wells spud or drilled during the period.

In 2014, we used $1.5 billion of cash on oil and natural gas capital expenditures, of which $1.2 billion related to drilling and completion costs and the remainder was primarily associated with leasing, acquisitions and seismic data. We participated in the drilling of 320 gross (98.3 net) wells, all of which were completed and capable of production. These expenditures were offset by $484.2 million in proceeds received from the divestitures of various non-core assets, including the East Texas Assets. As part of HK TMS's transaction with Apollo, discussed in further detail below, we received proceeds of approximately $33.8 million from the conveyance of an overriding royalty interest to Apollo.

Financing Activities. Net cash flows used in financing activities for the period of September 10, 2016 through December 31, 2016 (Successor) were $54.0 million and net cash flows provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) were $58.3 million. Net cash flows provided by financing activities were $164.4 million and $644.0 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively.

During the period of September 10, 2016 through December 31, 2016 (Successor), we paid a consent fee of approximately $10.0 million to holders of our Second Lien Notes and made net repayments of $44.0 million on our Senior Credit Agreement. The primary drivers of cash provided by financing activities for the period of January 1, 2016 through September 9, 2016 (Predecessor) were net borrowings on our Predecessor Credit Agreement, offset by cash payments totaling $97.5 million made to the Third Lien Noteholders, Unsecured Noteholders, Convertible Noteholder and Preferred Holders in accordance with the Plan.

During the first quarter of 2016 (Predecessor), we repurchased approximately $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $9.7 million and we recognized an $81.4 million net gain on the extinguishment of debt, as an $82.1 million gain on the repurchase was partially offset by the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective senior unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the senior unsecured notes repurchased.



During the fourth quarter of 2015 (Predecessor), we repurchased approximately $6.2 million principal amount of our 9.75% senior notes due 2020, $28.0 million principal amount of our 8.875% senior notes due 2021, and $10.3 million principal amount of our 9.25% senior notes due 2022. The net cash used to make these repurchases was approximately $14.8 million and we recognized a $29.4 million net gain on the extinguishment of debt, as a $29.7 million gain on the repurchase was partially offset by the write-down of $0.3 million associated with related issuance costs and discounts and premiums for the respective unsecured notes. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased.

On May 1, 2015 (Predecessor), we completed the issuance of $700.0 million aggregate principal amount of our 2020 Second Lien Notes. The net proceeds from the offering were approximately $686.2 million after deducting commissions and offering expenses and were used to repay a majority of the then outstanding borrowings under our Predecessor Credit Agreement.

Cash flows provided by financing activities include net borrowings under our Predecessor Credit Agreement of $62.0 million for the year ended December 31, 2015 (Predecessor), primarily used to fund drilling and completion activities and other general corporate purposes.

During the year ended December 31, 2015, cash flows from financing activities were modestly impacted by sales of our Predecessor common stock. For the year ended December 31, 2015 (Predecessor), we sold approximately 1.9 million shares for net proceeds of approximately $15.0 million, after deducting offering expenses.

On June 16, 2014 (Predecessor), our subsidiary, HK TMS, entered into a transaction with Apollo by initially selling 150,000 preferred shares in HK TMS, which held all of our acreage in the TMS, located in Mississippi and Louisiana. Apollo contributed $150 million to HK TMS, and we contributed all our assets related to the TMS as well as $50 million in cash. The proceeds from Apollo were allocated as follows: $110.1 million of proceeds associated with the issuance of HK TMS preferred stock and approximately $4.5 million associated with Apollo's rights to additional preferred shares within cash flows from financing activities and the aforementioned $33.8 million investing cash flows related to the overriding royalty conveyance. The proceeds were used to develop the TMS.

## Contractual Obligations

We have a significant degree of flexibility to adjust the level of our future capital expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, oil and natural gas price conditions, our access to capital and liquidity and other related economic factors. We currently have no material off-balance sheet arrangements or transactions with unconsolidated, limited-purpose



entities. The following table summarizes our contractual obligations and commitments by payment periods as of December 31, 2016 (Successor).

<table><tr><td rowspan="2">Contractual Obligations</td><td colspan="5">Payments Due by Period</td><td rowspan="2">2022 and Beyond</td></tr><tr><td>Total</td><td>2017</td><td>2018 - 2019 (In thousands)</td><td>2020 - 2021</td><td></td></tr><tr><td>Successor senior revolving credit facility</td><td>$ 186,000</td><td>$ —</td><td>$ 186,000</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>8.625% senior secured second lien notes due 2020(1)(2)</td><td>700,000</td><td>—</td><td>—</td><td>700,000</td><td>—</td><td></td></tr><tr><td>12.0% senior secured second lien notes due 2022(3)</td><td>112,826</td><td>—</td><td>—</td><td>—</td><td>112,826</td><td></td></tr><tr><td>Interest expense on long-term debt(4)</td><td>280,314</td><td>82,906</td><td>163,644</td><td>32,109</td><td>1,655</td><td></td></tr><tr><td>Operating leases</td><td>15,518</td><td>3,493</td><td>6,537</td><td>3,308</td><td>2,180</td><td></td></tr><tr><td>Drilling rig commitments</td><td>25,018</td><td>17,574</td><td>7,444</td><td>—</td><td>—</td><td></td></tr><tr><td>Rig stacking commitments</td><td>11,080</td><td>6,820</td><td>1,260</td><td>3,000</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 1,330,756</td><td>$ 110,793</td><td>$ 364,885</td><td>$ 738,417</td><td>$ 116,661</td><td></td></tr></table>

(1) Excludes a $27.4 million unamortized discount.

(2) On February 16, 2017, we issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025. We utilized a portion of the net proceeds from the issuance of the new 6.75% senior unsecured notes to repurchase approximately $289.2 million aggregate principal amount of the 2020 Second Lien Notes and will use the remaining net proceeds to redeem the remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes and for general corporate purposes. These transactions are not included in the table above. See "6.75% Senior Notes" below and Item 8. Consolidated Financial Statements and Supplementary Data-Note 17, "Subsequent Events," for more details.

(3) Excludes a $6.8 million unamortized discount.

(4) Future interest expense was calculated based on interest rates and debt amounts outstanding at December 31, 2016 less required annual repayments.

We lease corporate office space in Houston, Texas and Denver, Colorado as well as a number of other field office locations. Rent expense was approximately $1.4 million for the period of September 10, 2016 through December 31, 2016 (Successor) and $5.9 million for the period January 1, 2016 through September 30, 2016 (Predecessor). Rent expense was approximately $8.6 million and $8.1 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively. In connection with the chapter 11 bankruptcy, we modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. Future obligations associated with our operating leases are presented in the table above.

On December 9, 2016, we entered into an agreement with a private operator for the right to purchase the Ward County Assets. The Ward County Assets are divided into two tracts: the Southern Tract (6,720 net acres) and the Northern Tract (8,320 net acres) with separate options for each tract. Pursuant to the terms of the agreement, in January 2017, we paid $5.0 million and began drilling a commitment well on the Southern Tract. We have until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If we initially elect only to exercise our option on the Southern Tract, we would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017. This option purchase is not included in the table above.



We also have various long-term gathering, transportation and sales contracts in the Bakken / Three Forks formations in North Dakota that are not included in the table above. As of December 31, 2016 (Successor), we had in place eight long-term crude oil contracts and five long-term natural gas contracts in this area, with sales prices based on posted market rates. Under the terms of these contracts we have committed a substantial portion of our Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. We believe that there are sufficient available reserves and production in the Bakken/Three Forks formations to meet our commitments, as the proved reserves from this area represent approximately 76% of our total proved reserves. Historically, we have been able to meet our delivery commitments.

The contractual obligations table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. In addition, amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total estimated amount of our asset retirement obligations at December 31, 2016 (Successor) was $32.4 million.

## Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of our 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on the utilization of the facility. We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if we have outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, we may also be required to make mandatory prepayments.

Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. At December 31, 2016, we were in compliance with the financial covenants under the Senior Credit Agreement.



The Senior Credit Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

At December 31, 2016, we had approximately $186.0 million of indebtedness outstanding, approximately $6.7 million letters of credit outstanding and approximately $407.3 million of borrowing capacity available under the Senior Credit Agreement.

## 8.625% Senior Secured Second Lien Notes

On May 1, 2015 (Predecessor), we issued $700.0 million aggregate principal amount of our 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes) in a private placement. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses).

The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year. The 2020 Second Lien Notes will mature on February 1, 2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of our and our subsidiaries' assets to the extent such assets secure our Senior Credit Agreement and our 2022 Second Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015, as amended by those certain Priority Confirmation Jointers, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes (discussed below), respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2020 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of our future unrestricted subsidiaries. In accordance with the terms of the Plan, the 2020 Second Lien Notes were unimpaired and reinstated upon our emergence from the chapter 11 bankruptcy.

On September 9, 2016, in connection with fresh-start accounting, we adjusted the 2020 Second Lien Notes to fair value of $679.0 million by recording a discount of $21.0 million to be amortized over the remaining life of the 2020 Second Lien Notes, using the effective interest method.

In addition, on September 28, 2016 (Successor), us and each of our guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2020 Second Lien Note Supplemental Indenture) to the Indenture dated as of May 1, 2015 with respect to the 2020 Second Lien Notes (the 2020 Second Lien Note Indenture). The 2020 Second Lien Note Supplemental Indenture amended the 2020 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2020 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016 (Successor). We paid an aggregate consent fee of approximately $8.6 million to holders of the 2020 Second Lien Notes and recorded an additional discount of approximately $8.6 million. The remaining unamortized discount was $27.4 million at December 31, 2016.

On February 16, 2017 (Successor), we paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to a tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017. The repurchase and redemption of the 2020 Second



Lien Notes will be funded with proceeds from the issuance of $850.0 million in new 6.75% senior unsecured notes due 2025. See "Recent Developments" for further details.

## 12.0% Senior Secured Second Lien Notes

On December 21, 2015 (Predecessor), we completed the issuance in a private placement of approximately $112.8 million aggregate principal amount of new 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of our then outstanding senior unsecured notes, consisting of $116.6 million principal amount of 9.75% senior notes due 2020, $137.7 million principal amount of 8.875% senior notes due 2021 and $35.3 million principal amount of 9.25% senior notes due 2022. At closing, we paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. We recorded the issuance of the 2022 Second Lien Notes at par.

Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on the Collateral. Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually equal with the liens that secure the 2020 Second Lien Notes and contractually subordinated to liens that secure the Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness and effectively equal to the 2020 Second Lien Notes, in each case to the extent of the value of the Collateral. In accordance with the terms of the Plan, the 2022 Second Lien Notes were unimpaired and reinstated upon our emergence from chapter 11 bankruptcy.

On September 9, 2016, in connection with fresh-start accounting, we adjusted the 2022 Second Lien Notes to fair value of $107.2 million by recording a discount of $5.7 million to be amortized over the remaining life of the 2022 Second Lien Notes, using the effective interest method.

In addition, on September 28, 2016 (Successor), us and each of our guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2022 Second Lien Note Supplemental Indenture) to the Indenture dated as of December 21, 2015 with respect to the 2022 Second Lien Notes (the 2022 Second Lien Note Indenture). The 2022 Second Lien Note Supplemental Indenture amended the 2022 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2022 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016 (Successor). We paid an aggregate consent fee of approximately $1.4 million to holders of the 2022 Second Lien Notes and recorded an additional discount of approximately $1.4 million.

The remaining unamortized discount was $6.8 million at December 31, 2016.

## Off-Balance Sheet Arrangements

At December 31, 2016 (Successor), we did not have any material off-balance sheet arrangements.

## Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had



been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, "Summary of Significant Events and Accounting Policies," for a discussion of additional accounting policies and estimates made by management.

## Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on September 9, 2016, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

Fresh-start accounting requires an entity to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as "Successor" or "Successor Company." However, we will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are presented to distinguish between the Predecessor and Successor Companies. Refer to Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 3, "Fresh-start Accounting," for further details.

## Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available—successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.

## Full Cost Method

We used the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas



properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

## Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2016 (Successor), 2015 and 2014 (Predecessor) were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—"Supplemental Oil and Gas Information (Unaudited)."

## Depreciation, Depletion and Accretion

Our rate of recording depletion, depreciation and accretion expense (DD&A) is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2016 (Successor), a five percent positive revision to proved reserves would decrease the DD&A rate by approximately $0.48 per Boe and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $0.52 per Boe.

## Full Cost Ceiling Test Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write down to the extent of such excess. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However,



the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write downs of our oil and natural gas properties could occur in the future.

If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2016 (Successor) had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $238.4 million and would have generated a full cost ceiling impairment.

## Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2016 (Successor), a five percent increase in future development and abandonment costs would increase the DD&A rate by approximately $0.23 per Boe and a five percent decrease in future development and abandonment costs would decrease the DD&A rate by $0.24 per Boe.

## Accounting for Derivative Instruments and Hedging Activities

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, when derivative contracts are available at terms (or prices) acceptable to us, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by us have consisted of transactions in which we hedge the variability of cash flow related to a forecasted transaction. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

## Income Taxes

Our provision for taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized.



In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. A significant item of objective negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2016 (Successor) driven primarily by the full cost ceiling impairments over that period which limits the ability to consider other subjective evidence such as the Company's anticipated future growth. Based upon the evaluation of the available evidence we recorded an increase of $604.4 million to our valuation allowance resulting in a valuation allowance of $821.9 million being applied against our deferred tax assets as of December 31, 2016 (Successor).

We follow ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

In November 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-17, Balance Sheet Classification of Deferred Taxes (ASU 2015-17) to simplify the presentation of deferred income taxes. Under ASU 2015-17, all deferred tax assets and liabilities, along with any related valuation allowance, are required to be classified as noncurrent on the balance sheet. Effective December 31, 2015, we early adopted ASU 2015-17, on a prospective basis, which resulted in the reclassification of our current deferred tax assets and liabilities as a non-current deferred tax assets and liabilities, net of the valuation allowance, on our consolidated balance sheets. No prior periods were retrospectively adjusted.

## Comparison of Results of Operations

## Year Ended December 31, 2016 (Successor) Compared to Year Ended December 31, 2015 (Predecessor)

The table included below sets forth financial information for the periods presented. The period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor) are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from chapter 11 bankruptcy on September 9, 2016 and are not



comparable to prior periods. Refer to the paragraphs following the table below for a discussion around our results of operations.

<table><tr><td rowspan="2">In thousands (except per unit and per Boe amounts)</td><td>Successor</td><td>Predecessor</td></tr><tr><td>Period from September 10, 2016 through December 31, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td><td>Year Ended December 31, 2015</td></tr><tr><td>Net income (loss)</td><td>$ (479,193)</td><td>$ 11,958</td><td>$ (1,922,621)</td></tr><tr><td>Operating revenues:</td><td></td><td></td><td></td></tr><tr><td>Oil</td><td>139,786</td><td>248,064</td><td>512,346</td></tr><tr><td>Natural gas</td><td>6,756</td><td>9,511</td><td>22,509</td></tr><tr><td>Natural gas liquids</td><td>6,018</td><td>7,929</td><td>13,624</td></tr><tr><td>Other</td><td>802</td><td>1,339</td><td>1,799</td></tr><tr><td>Operating expenses:</td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td>22,382</td><td>50,032</td><td>103,590</td></tr><tr><td>Workover and other</td><td>10,510</td><td>22,507</td><td>20,862</td></tr><tr><td>Taxes other than income</td><td>12,364</td><td>24,453</td><td>48,890</td></tr><tr><td>Gathering and other</td><td>14,677</td><td>29,279</td><td>40,281</td></tr><tr><td>Restructuring</td><td>—</td><td>5,168</td><td>2,886</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td>19,876</td><td>78,765</td><td>73,237</td></tr><tr><td>Share-based compensation</td><td>21,519</td><td>4,876</td><td>14,529</td></tr><tr><td>Depletion, depreciation and accretion:</td><td></td><td></td><td></td></tr><tr><td>Depletion—Full cost</td><td>45,204</td><td>114,775</td><td>354,344</td></tr><tr><td>Depreciation—Other</td><td>1,108</td><td>4,366</td><td>8,063</td></tr><tr><td>Accretion expense</td><td>587</td><td>1,414</td><td>1,797</td></tr><tr><td>Full cost ceiling impairment</td><td>420,934</td><td>754,769</td><td>2,626,305</td></tr><tr><td>Other operating property and equipment impairment</td><td>—</td><td>28,056</td><td>—</td></tr><tr><td>Other income (expenses):</td><td></td><td></td><td></td></tr><tr><td>Net gain (loss) on derivative contracts</td><td>(27,740)</td><td>(17,998)</td><td>310,264</td></tr><tr><td>Interest expense and other, net</td><td>(28,861)</td><td>(122,249)</td><td>(232,878)</td></tr></table>



<table><tr><td>Reorganization items</td><td>(2,049)</td><td>913,722</td><td>—</td></tr><tr><td>Gain (loss) on extinguishment of debt</td><td>—</td><td>81,434</td><td>761,804</td></tr><tr><td>Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants</td><td>—</td><td>—</td><td>(8,219)</td></tr><tr><td>Income tax benefit (provision)</td><td>(4,744)</td><td>8,666</td><td>(9,086)</td></tr><tr><td>Production:</td><td></td><td></td><td></td></tr><tr><td>Crude oil—MBbls</td><td>3,250</td><td>7,118</td><td>12,019</td></tr><tr><td>Natural gas—MMcf</td><td>3,011</td><td>6,560</td><td>10,123</td></tr><tr><td>Natural gas liquids—MBbls</td><td>501</td><td>1,096</td><td>1,457</td></tr><tr><td>Total MBo€(1)</td><td>4,253</td><td>9,307</td><td>15,163</td></tr><tr><td>Average daily production—Bo€(1)</td><td>37,637</td><td>36,787</td><td>41,542</td></tr><tr><td>Average price per unit(2):</td><td></td><td></td><td></td></tr><tr><td>Crude oil price—Bbl</td><td>$ 43.01</td><td>$ 34.85</td><td>$ 42.63</td></tr><tr><td>Natural gas price—Mcf</td><td>2.24</td><td>1.45</td><td>2.22</td></tr><tr><td>Natural gas liquids price—Bbl</td><td>12.01</td><td>7.23</td><td>9.35</td></tr><tr><td>Total per Bo€(1)</td><td>35.87</td><td>28.53</td><td>36.17</td></tr><tr><td>Average cost per Boe:</td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td>$ 5.26</td><td>$ 5.38</td><td>$ 6.83</td></tr><tr><td>Workover and other</td><td>2.47</td><td>2.42</td><td>1.38</td></tr><tr><td>Taxes other than income</td><td>2.91</td><td>2.63</td><td>3.22</td></tr><tr><td>Gathering and other</td><td>3.45</td><td>3.15</td><td>2.66</td></tr><tr><td>Restructuring</td><td>—</td><td>0.56</td><td>0.19</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td>4.67</td><td>8.46</td><td>4.83</td></tr><tr><td>Share-based compensation</td><td>5.06</td><td>0.52</td><td>0.96</td></tr><tr><td>Depletion</td><td>10.63</td><td>12.33</td><td>23.37</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.






Oil, natural gas and natural gas liquids revenues were $152.6 million, $265.5 million and $548.5 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in revenues year over year was driven by the sustained decline in the prices of crude oil and natural gas along with a decrease in our average daily production. Oil and natural gas prices are inherently volatile and have decreased significantly since mid-year 2014 and have remained relatively low throughout 2016. We curtailed our drilling and shut in some production in 2016 in response to the decline in commodity prices, which resulted in a decrease in our average daily production. During the period of September 10, 2016 through December 31, 2016 (Successor) and the period of January 1, 2016 through September 9, 2016 (Predecessor), production averaged 37,637 Boe/d and 36,787 Boe/d, respectively, compared to average daily production of 41,542 Boe/d during 2015 (Predecessor).

Lease operating expenses on a per Boe basis were $5.26 per Boe, $5.38 per Boe and $6.83 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in lease operating expense per Boe from 2015 levels is primarily due to price decreases from our vendors in light of the commodity price environment.

Workover and other expenses on a per Boe basis were $2.47 per Boe, $2.42 per Boe and $1.38 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The increased costs per Boe in 2016 relate primarily to workovers in our Bakken/Three Forks area, specifically costs spent to restore production on wells.

Taxes other than income on a per Boe basis were $2.91 per Boe, $2.63 per Boe and $3.22 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease.

Gathering and other expenses on a per Boe basis were $3.45 per Boe, $3.15 per Boe and $2.66 per Boe for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Gathering and other expenses include gathering fees paid on our oil and natural gas production as well as rig termination or stacking charges incurred. Throughout 2016 (for the Successor and Predecessor periods combined), we stacked two rigs in response to the sustained decline in commodity prices, whereas in 2015, we stacked only one rig.

In 2016, we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we incurred $5.2 million in severance costs and accelerated stock-based compensation expense related to reductions in our workforce recorded in "Restructuring" on the consolidated statements of operations. For the year ended December 31, 2015 (Predecessor), in conjunction with our divestitures of certain non-core properties, we incurred approximately $2.9 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

General and administrative expense was $19.9 million, $78.8 million and $73.2 million, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. General and administrative expenses increased from 2015 levels due to costs incurred in connection with efforts to restructure our indebtedness.



Share-based compensation expense was $21.5 million, $4.9 million and $14.5 million, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Share-based compensation expense decreased in the Predecessor periods due to a reduction in our workforce and increased in the Successor period due to equity awards made in conjunction with our emergence from chapter 11 bankruptcy. A portion of these awards vested immediately on the day of the grant.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. On a per unit basis, depletion expense was $10.63 per Boe, $12.33 per Boe and $23.37 per Boe, for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in depletion expense and the depletion rate per Boe from 2015 levels is attributable to decreases in the amortizable base due to our full cost ceiling test impairments.

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling", based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. During 2016, the net book value of our oil and gas properties at March 31, June 30, and September 30, 2016 exceeded the respective ceiling amounts for each period. We recorded a full cost ceiling test impairment before income taxes of $420.9 million for the period of September 10, 2016 through September 30, 2016 (Successor). The impairment at September 30, 2016 primarily reflects the pricing differences between the first-day-of-the-month average price for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date, September 9, 2016. We recorded full cost ceiling test impairments before income taxes totaling $754.8 million for the period January 1, 2016 through September 9, 2016 (Predecessor). The ceiling test impairments were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. We recorded full cost ceiling test impairments before income taxes totaling $2.6 billion for the year ended December 31, 2015 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations since December 31, 2014. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion of potential future ceiling impairments in an environment of sustained lower commodity prices.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the period of January 1, 2016 through September 9, 2016 (Predecessor), we recorded a non-cash impairment charge of $28.1 million. The impairment relates to our gross investments of $32.8 million in gas gathering infrastructure that will not likely be economically recoverable due to our shift in exploration, drilling and developmental plans to our most economic areas as a result of the low commodity price environment.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have



elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2016 (Successor), we had a $5.9 million derivative asset, $5.9 million of which was classified as current, and we had a $16.9 million derivative liability, $16.4 million of which was classified as current. We recorded a net derivative loss of $27.7 million ($112.4 million net unrealized loss and $84.7 million net realized gain on settled contracts) and $18.0 million ($263.7 million net unrealized loss and $245.7 million net realized gain on settled contracts) for the period of September 10, 2016 through December 31, 2016 (Successor) and for the period of January 1, 2016 through September 9, 2016 (Predecessor), respectively, compared to a net derivative gain of $310.3 million ($129.2 million net unrealized loss offset by a $439.5 million net realized gain on settled contracts) for the year ended December 31, 2015 (Predecessor).

Interest expense and other was $28.9 million, $122.2 million and $232.9 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. Capitalized interest for the period of January 1, 2016 through September 9, 2016 (Successor) and the year ended December 31, 2015 (Predecessor) was $68.2 million and $113.0 million, respectively. The Successor Company's accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. Gross interest expense was $28.6 million, $195.7 million and $337.6 million for the period of September 10, 2016 through December 31, 2016 (Successor), the period of January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), respectively. The decrease in gross interest expense from 2015 levels was primarily due to the discontinuance of interest expense on our senior notes that were cancelled as part of our chapter 11 bankruptcy proceedings.

Reorganization items represent (i) expenses or income incurred subsequent to July 27, 2016 (when we filed voluntary petitions for relief under chapter 11) as a direct result of the reorganization Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in "Reorganization items" in the consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

<table><tr><td></td><td>Successor</td><td>Predecessor</td></tr><tr><td></td><td>Period from September 10, 2016 through December 31, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td></tr><tr><td>Gain on settlement of Liabilities subject to compromise</td><td>$ —</td><td>$ 1,368,908</td></tr><tr><td>Fresh start adjustments</td><td>—</td><td>(392,232)</td></tr><tr><td>Reorganization professional fees and other</td><td>(2,049)</td><td>(30,287)</td></tr><tr><td>Write-off debt discounts/premiums and debt issuance costs</td><td>—</td><td>(32,667)</td></tr><tr><td>Gain (loss) on reorganization items</td><td>$ (2,049)</td><td>$ 913,722</td></tr></table>

During the three months ended March 31, 2016 (Predecessor), we repurchased approximately $91.8 million principal amount of our senior unsecured notes, consisting of $24.5 million principal amount of our 9.75% senior notes due 2020, $51.8 million principal amount of our 8.875% senior notes due 2021, and $15.5 million principal amount of our 9.25% senior notes due 2022 for cash at prevailing market prices at the time of the transactions. The net cash used to make these repurchases was approximately $9.7 million. Upon settlement of the repurchases, we paid all accrued and unpaid interest since the respective interest payment dates of the notes repurchased and we recorded a net gain on the extinguishment of debt of approximately $81.4 million, which included the write-down of $0.7 million associated with related issuance costs and discounts and premiums for the respective notes. During the year ended December 31, 2015 (Predecessor), we entered into several transactions intended



to reduce our long-term debt. The table below denotes the transaction description, the reduction of the principal amount of long-term debt, the write-down of associated issuance costs and discounts and premiums, and the net gain on extinguishment of debt that was recorded for each transaction:

<table><tr><td>Transaction Description</td><td>Principal Reduction</td><td>Common Stock Issuance</td><td>Issuance Cost and Discount / Premium Writedown</td><td>Net (Gain)</td></tr><tr><td>Unsecured Notes Exchanged for Common Stock</td><td>$ (258.0)</td><td>$ 231.4</td><td>$ (3.8)</td><td>$ (22.8)</td></tr><tr><td>Unsecured Notes Exchanged for Secured Third Lien Notes</td><td>(548.2)</td><td>—</td><td>(13.1)</td><td>(535.1)</td></tr><tr><td>Repurchases of Unsecured Notes</td><td>(29.7)</td><td>—</td><td>(0.3)</td><td>(29.4)</td></tr><tr><td>Unsecured Notes Exchanged for Secured Second Lien Notes</td><td>(176.7)</td><td>—</td><td>(2.2)</td><td>(174.5)</td></tr><tr><td></td><td>$ (1,012.6)</td><td>$ 231.4</td><td>$ (19.4)</td><td>$ (761.8)</td></tr></table>

During the year ended December 31, 2015 (Predecessor), we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

We recorded an income tax provision of $4.7 million for the period of September 10, 2016 through December 31, 2016 (Successor) and an income tax benefit of $8.7 million for the period January 1, 2016 through September 9, 2016 (Predecessor) relating to our estimated 2016 alternative minimum tax liability and the reversal of the Predecessor estimated 2015 alternative minimum tax liability, respectively. We recorded an income tax provision of $9.1 million on a loss before income taxes of $1.9 billion for the year ended December 31, 2015 (Predecessor), related to projected alternative minimum tax.



## Year Ended December 31, 2015 (Predecessor) Compared to Year Ended December 31, 2014 (Predecessor)

We reported a net loss of $1.9 billion for the year ended December 31, 2015 (Predecessor) compared to net income of $316.0 million for the comparable period in 2014 (Predecessor). The following table summarizes key items of comparison and their related change for the periods indicated. Refer to the paragraphs following the table below for a discussion around our results of operations.

<table><tr><td rowspan="3">In thousands (except per unit and per Boe amounts)</td><td colspan="3">Predecessor</td></tr><tr><td colspan="3">Years Ended December 31,</td></tr><tr><td>2015</td><td>2014</td><td>Change</td></tr><tr><td>Net income (loss)</td><td></td><td></td><td></td></tr><tr><td></td><td>$ (1,922,621)</td><td>$ 315,956</td><td>$ (2,238,577)</td></tr><tr><td>Operating revenues:</td><td></td><td></td><td></td></tr><tr><td>Oil</td><td></td><td></td><td></td></tr><tr><td></td><td>512,346</td><td>1,071,319</td><td>(558,973)</td></tr><tr><td>Natural gas</td><td></td><td></td><td></td></tr><tr><td></td><td>22,509</td><td>37,101</td><td>(14,592)</td></tr><tr><td>Natural gas liquids</td><td></td><td></td><td></td></tr><tr><td></td><td>13,624</td><td>37,460</td><td>(23,836)</td></tr><tr><td>Other</td><td></td><td></td><td></td></tr><tr><td></td><td>1,799</td><td>2,381</td><td>(582)</td></tr><tr><td>Operating expenses:</td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td></td><td></td><td></td></tr><tr><td></td><td>103,590</td><td>130,239</td><td>(26,649)</td></tr><tr><td>Workover and other</td><td></td><td></td><td></td></tr><tr><td></td><td>20,862</td><td>16,193</td><td>4,669</td></tr><tr><td>Taxes other than income</td><td></td><td></td><td></td></tr><tr><td></td><td>48,890</td><td>106,331</td><td>(57,441)</td></tr><tr><td>Gathering and other</td><td></td><td></td><td></td></tr><tr><td></td><td>40,281</td><td>26,719</td><td>13,562</td></tr><tr><td>Restructuring</td><td></td><td></td><td></td></tr><tr><td></td><td>2,886</td><td>987</td><td>1,899</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td></td><td></td><td></td></tr><tr><td></td><td>73,237</td><td>97,799</td><td>(24,562)</td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></td></tr><tr><td></td><td>14,529</td><td>18,733</td><td>(4,204)</td></tr><tr><td>Depletion, depreciation and accretion:</td><td></td><td></td><td></td></tr><tr><td>Depletion—Full cost</td><td></td><td></td><td></td></tr><tr><td></td><td>354,344</td><td>523,855</td><td>(169,511)</td></tr><tr><td>Depreciation—Other</td><td></td><td></td><td></td></tr><tr><td></td><td>8,063</td><td>8,744</td><td>(681)</td></tr><tr><td>Accretion expense</td><td></td><td></td><td></td></tr><tr><td></td><td>1,797</td><td>1,822</td><td>(25)</td></tr><tr><td>Full cost ceiling impairment</td><td></td><td></td><td></td></tr><tr><td></td><td>2,626,305</td><td>239,668</td><td>2,386,637</td></tr><tr><td>Other operating property and equipment impairment</td><td></td><td>—</td><td>35,558</td></tr><tr><td>Other income (expenses):</td><td></td><td></td><td></td></tr><tr><td>Net gain (loss) on derivative contracts</td><td></td><td></td><td></td></tr><tr><td></td><td>310,264</td><td>518,956</td><td>(208,692)</td></tr></table>



<table><tr><td>Interest expense and other, net</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>(232,878)</td><td>(145,689)</td><td>(87,189)</td></tr><tr><td>Gain (loss) on extinguishment of debt</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>761,804</td><td>—</td><td>761,804</td></tr><tr><td>Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>(8,219)</td><td>—</td><td>(8,219)</td></tr><tr><td>Income tax benefit (provision)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>(9,086)</td><td>1,076</td><td>(10,162)</td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil—MBbls</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>12,019</td><td>12,787</td><td>(768)</td></tr><tr><td>Natural gas—MMcf</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>10,123</td><td>8,812</td><td>1,311</td></tr><tr><td>Natural gas liquids—MBbls</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>1,457</td><td>1,113</td><td>344</td></tr><tr><td>Total MBoed(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>15,163</td><td>15,369</td><td>(206)</td></tr><tr><td>Average daily production—Boe(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>41,542</td><td>42,107</td><td>(565)</td></tr><tr><td>Average price per unit(2):</td><td></td><td></td><td></td><td></td></tr><tr><td>Crude oil price—Bbl</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>42.63</td><td>83.78</td><td>(41.15)</td></tr><tr><td>Natural gas price—Mcf</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>2.22</td><td>4.21</td><td>(1.99)</td></tr><tr><td>Natural gas liquids price—Bbl</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>9.35</td><td>33.66</td><td>(24.31)</td></tr><tr><td>Total per Boed(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>36.17</td><td>74.56</td><td>(38.39)</td></tr><tr><td>Average cost per Boe:</td><td></td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>6.83</td><td>8.47</td><td>(1.64)</td></tr><tr><td>Workover and other</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>1.38</td><td>1.05</td><td>0.33</td></tr><tr><td>Taxes other than income</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>3.22</td><td>6.92</td><td>(3.70)</td></tr><tr><td>Gathering and other</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>2.66</td><td>1.74</td><td>0.92</td></tr><tr><td>Restructuring</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>0.19</td><td>0.06</td><td>0.13</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>4.83</td><td>6.36</td><td>(1.53)</td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>0.96</td><td>1.22</td><td>(0.26)</td></tr><tr><td>Depletion</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>23.37</td><td>34.09</td><td>(10.72)</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a ratio of six Moe to one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.






For the year ended December 31, 2015 (Predecessor), oil, natural gas and natural gas liquids revenues decreased $597.4 million from the same period in 2014 due to lower average realized prices and a slight decrease in our production volumes. Average realized prices (excluding effects of hedging arrangements) decreased from $74.56 per Boe to $36.17 per Boe, representing a 51% decrease from the prior year period. Oil and natural gas prices are inherently volatile and decreased significantly since mid-year 2014. Production slightly decreased year over year, as we curtailed our drilling in response to the decline in commodity prices. However, production volumes associated with our core properties in the Bakken/Three Forks and El Halcón areas have remained flat or increased slightly year over year, as we have focused our drilling efforts on our most economic areas due to the current price environment. Sustained lower commodity prices will continue to impact our oil, natural gas and natural gas liquids revenues.

Lease operating expenses decreased $26.6 million for the year ended December 31, 2015 (Predecessor). On a per unit basis, lease operating expenses were $6.83 per Boe in 2015 compared to $8.47 per Boe in 2014. The decrease per Boe is primarily due to lower relative operating expenses on our core properties due, in part, to operational improvements and efficiencies as well as cost decreases from our vendors in light of the commodity price environment.

Workover and other expenses increased $4.7 million for the year ended December 31, 2015 (Predecessor) as compared to the same period in 2014 primarily due to $8.6 million of expenses associated with increased activity in our core areas as we continued to develop these areas.

Taxes other than income decreased $57.4 million for the year ended December 31, 2015 (Predecessor) as compared to the same period in 2014 primarily due to lower oil, natural gas and natural gas liquids revenues attributable to significantly lower commodity prices. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $3.22 per Boe and $6.92 per Boe, for the years ended 2015 and 2014 (Predecessor), respectively. The decrease on a per Boe basis in 2015 is driven by a decrease in our realized average prices.

Gathering and other expenses for the year ended December 31, 2015 and 2014 (Predecessor) were $40.3 million and $26.7 million, respectively. Approximately, $29.2 million of expenses incurred in 2015 relate to gathering and other fees paid on our oil and natural gas production. Also included is a $6.0 million termination fee paid to early terminate one of our drilling rig contacts and $3.8 million of rig stacking fees. The decision to early terminate one drilling rig contract and stack another drilling rig was in response to the decline in crude oil prices.

For the year ended December 31, 2015 (Predecessor), we had reductions in our workforce due to the decrease in our drilling and developmental activities planned for the year. We incurred approximately $2.9 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the year. For the year ended December 31, 2014 (Predecessor), in conjunction with our divestitures of certain non-core properties, we incurred approximately $1.0 million in severance costs and accelerated stock-based compensation expense related to the termination of certain employees in these non-core areas.

General and administrative expense for the year ended December 31, 2015 (Predecessor) decreased $24.6 million to $73.2 million as compared to the same period in 2014. The decrease was primarily due to decreases in professional fees, payroll and employee related benefit costs, and transaction expenses amounting to $9.9 million, $9.3 million and $1.8 million, respectively. On a per unit basis, general and administrative expenses were $4.83 per Boe and $6.36 per Boe, for the years ended December 31, 2015 and 2014 (Predecessor), respectively.



Share-based compensation expense for the year ended December 31, 2015 (Predecessor) was $14.5 million, a decrease of $4.2 million compared to the same period in 2014. The decrease in share-based compensation expense results from forfeitures and lower fair market value for new awards granted to employees and directors during 2015.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production volume for the current period to total remaining reserve volumes for evaluated properties as of the beginning of the period. Depletion expense decreased $169.5 million to $354.3 million for the year ended December 31, 2015 (Predecessor) compared to the same period in 2014, primarily attributable to decreases in the amortizable base due to the full cost ceiling impairments since the prior year period. On a per unit basis, depletion expense was $23.37 per Boe for the year ended December 31, 2015 (Predecessor) compared to $34.09 per Boe for the year ended December 31, 2014 (Predecessor).

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," established by the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $2.6 billion for the year ended December 31, 2015 (Predecessor), compared to a full cost ceiling test impairment before income taxes of $239.7 million for the year ended December 31, 2014 (Predecessor). The ceiling test impairments in 2015 were driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations from $94.99 per Bbl at December 31, 2014 (Predecessor) to $50.28 per Bbl at December 31, 2015 (Predecessor). Changes in commodity prices, production rates, reserve volumes, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. See "Overview" for a discussion and quantification of potential future ceiling impairments in an environment of sustained lower commodity prices.

We review our gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360. For the year ended December 31, 2014 (Predecessor), we recorded a non-cash impairment charge for gas gathering systems and other related operating assets of $35.6 million, net of $1.9 million of accumulated depreciation. The majority of the impairment represents approximately half of our gas gathering infrastructure, right-of-way and permitting investments in the Utica/Point Pleasant area. These infrastructure related investments were related to acreage in certain non-core areas of the Utica play which, at the time of evaluation for impairment in December 2014 (Predecessor), we did not plan to develop in light of the recent downtrend in oil prices, which rendered certain areas to be deemed uneconomic and/or non-strategic.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2015 (Predecessor), we had a $365.5 million derivative asset, $348.9 million of which was classified as current, and we had a $0.3 million derivative liability, none of which was classified as current. We recorded a net derivative gain of $310.3 million ($129.2 million net unrealized loss offset by a $439.5 million net realized gain on settled contracts) for the year ended December 31, 2015 (Predecessor) compared to a net derivative gain of $518.9 million ($506.5 million net unrealized gain and $12.4 million net realized gain on settled contracts) in the prior year.



Interest expense and other increased $87.2 million for the year ended December 31, 2015 (Predecessor) from the same period in 2014. Capitalized interest for the years ended December 31, 2015 and 2014 (Predecessor) was $113.0 million and $168.9 million, respectively. The decrease in capitalized interest was driven by decreases in our unevaluated properties since 2014, which is the basis of our capitalized interest calculation. Interest expense subject to capitalization increased $19.9 million, over the prior year period, from $317.7 million in 2014 to $337.6 million in 2015. The increase in interest subject to capitalization is primarily due to the issuance of our 2020 Second Lien Notes since the prior year period.

During the year ended December 31, 2015 (Predecessor), we entered into several transactions intended to reduce our long-term debt. The table below denotes the transaction description, the reduction of the principal amount of long-term debt, the write-down of associated issuance costs and discounts and premiums, and the net gain on extinguishment of debt that was recorded for each transaction:

<table><tr><td>Transaction Description</td><td>Principal Reduction</td><td>Common Stock Issuance</td><td>Issuance Cost and Discount / Premium Writedown (In millions)</td><td>Net (Gain)</td></tr><tr><td>Unsecured Notes Exchanged for Common Stock</td><td>$ (258.0)</td><td>$ 231.4</td><td>$ (3.8)</td><td>$ (22.8)</td></tr><tr><td>Unsecured Notes Exchanged for Secured Third Lien Notes</td><td>(548.2)</td><td>—</td><td>(13.1)</td><td>(535.1)</td></tr><tr><td>Repurchases of Unsecured Notes</td><td>(29.7)</td><td>—</td><td>(0.3)</td><td>(29.4)</td></tr><tr><td>Unsecured Notes Exchanged for Secured Second Lien Notes</td><td>(176.7)</td><td>—</td><td>(2.2)</td><td>(174.5)</td></tr><tr><td></td><td>$ (1,012.6)</td><td>$ 231.4</td><td>$ (19.4)</td><td>$ (761.8)</td></tr></table>

During the year ended December 31, 2015 (Predecessor), we entered into an amendment to our Convertible Note and to the February 2012 Warrants, in which we recorded a net gain on the extinguishment of the Convertible Note of $5.9 million and a net loss on the modification of the February 2012 Warrants of $14.1 million.

We recorded an income tax provision of $9.1 million on a loss before income taxes of $1.9 billion for the year ended December 31, 2015 (Predecessor). The provision represents projected alternative minimum tax. For the year ended December 31, 2014 (Predecessor), we recorded an income tax benefit of $1.1 million on income before income taxes of $314.9 million. The benefit reflects the impact of the change in the valuation allowance for the year of $102.0 million.

## Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, "Summary of Significant Events and Accounting Policies."

## ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## Derivative Instruments and Hedging Activity

We are exposed to various risks including energy commodity price risk. When oil, natural gas, and natural gas liquids prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically



utilize include costless collars, swaps, and deferred put options. The total volumes which we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 70% to 80% of our current and anticipated production for the next 18 to 24 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. We did not post collateral under any of these contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 9, "Derivative and Hedging Activities," for additional information.

We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 9, "Derivative and Hedging Activities," for more details.

## Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, "Fair Value Measurements," for additional information.

## Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At December 31, 2016 (Successor), the principal amount of our total long-term debt was $998.8 million, of which approximately 81.4% bears interest at a weighted average fixed interest rate of 9.09% per year. The remaining 18.6% of our total long-term debt at December 31, 2016 (Successor) bears interest at floating or market interest rates that at our option are tied to prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2016 (Successor), the weighted average interest rate on our variable rate debt was 3.74% per year. If the balance of our variable rate debt at December 31, 2016 (Successor) were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.7 million per year.



## ITEM8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

## INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Management's report on internal control over financial reporting 81
Reports of independent registered public accounting firm 82
Consolidated statements of operations 85
Consolidated balance sheets 86
Consolidated statements of stockholders' equity 87
Consolidated statements of cash flows 88
Notes to the consolidated financial statements 89
Supplemental oil and gas information (unaudited) 145
Selected quarterly financial data (unaudited) 151



## MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Halcón Resources Corporation (the Company), including the Company's Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company's internal control system was designed to provide reasonable assurance to the Company's Management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, management concluded that Halcón Resources Corporation's internal control over financial reporting was effective as of December 31, 2016.

Deloitte & Touche LLP, the Company's independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2016 which is included herein.

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board, Chief Executive Officer and President
/s/ MARK J. MIZE

Mark J. Mize
Executive Vice President,
Chief Financial Officer and Treasurer

Houston, Texas
February 28, 2017



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Halcón Resources Corporation
Houston, Texas

We have audited the internal control over financial reporting of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2016 (Successor Company balance sheet) and 2015 (Predecessor Company balance sheet), and the related consolidated statements of operations, stockholders' equity (deficit), and cash flows for the



## Table of Contents

period of September 10, 2016 to December 31, 2016 (Successor Company operations), the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015 (Predecessor Company operations) and our report dated February 28, 2017 expressed an unqualified opinion on those financial statements.

## /s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2017



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Halcón Resources Corporation
Houston, Texas

We have audited the accompanying balance sheet of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2016 (Successor Company balance sheet) and 2015 (Predecessor Company balance sheet), and the related consolidated statements of operations, stockholders' equity, and cash flows for the period of September 10, 2016 to December 31, 2016 (Successor Company operations), the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015 (Predecessor Company operations). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements, on September 8, 2016, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective on September 9, 2016.

Accordingly, the accompanying financial statements have been prepared in conformity with AICPA Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note [2] to the financial statements.

In our opinion, the Successor Company financial statements present fairly, in all material respects, the financial position of Halcón Resources Corporation and subsidiaries as of December 31, 2016, and the results of its operations and its cash flows for the period of September 10, 2016 to December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor Company as of December 31, 2015, and the results of its operations and its cash flows for the period of January 1, 2016 to September 9, 2016, and for each of the two years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2017



## HALCÓN RESOURCES CORPORATION

## CONSOLIDATED STATEMENTS OF OPERATIONS

## (In thousands, except per share amounts)

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Operating revenues:</td><td></td><td></td><td></td><td></td></tr><tr><td>Oil, natural gas and natural gas liquids sales:</td><td></td><td></td><td></td><td></td></tr><tr><td>Oil</td><td>$ 139,786</td><td>$ 248,064</td><td>$ 512,346</td><td>$1,071,319</td></tr><tr><td>Natural gas</td><td>6,756</td><td>9,511</td><td>22,509</td><td>37,101</td></tr><tr><td>Natural gas liquids</td><td>6,018</td><td>7,929</td><td>13,624</td><td>37,460</td></tr><tr><td>Total oil, natural gas and natural gas liquids sales</td><td>152,560</td><td>265,504</td><td>548,479</td><td>1,145,880</td></tr><tr><td>Other</td><td>802</td><td>1,339</td><td>1,799</td><td>2,381</td></tr><tr><td>Total operating revenues</td><td>153,362</td><td>266,843</td><td>550,278</td><td>1,148,261</td></tr><tr><td>Operating expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Production:</td><td></td><td></td><td></td><td></td></tr><tr><td>Lease operating</td><td>22,382</td><td>50,032</td><td>103,590</td><td>130,239</td></tr><tr><td>Workover and other</td><td>10,510</td><td>22,507</td><td>20,862</td><td>16,193</td></tr><tr><td>Taxes other than income</td><td>12,364</td><td>24,453</td><td>48,890</td><td>106,331</td></tr><tr><td>Gathering and other</td><td>14,677</td><td>29,279</td><td>40,281</td><td>26,719</td></tr><tr><td>Restructuring</td><td>—</td><td>5,168</td><td>2,886</td><td>987</td></tr><tr><td>General and administrative</td><td>41,395</td><td>83,641</td><td>87,766</td><td>116,532</td></tr><tr><td>Depletion, depreciation and accretion</td><td>46,899</td><td>120,555</td><td>364,204</td><td>534,421</td></tr><tr><td>Full cost ceiling impairment</td><td>420,934</td><td>754,769</td><td>2,626,305</td><td>239,668</td></tr><tr><td>Other operating property and equipment impairment</td><td>—</td><td>28,056</td><td>—</td><td>35,558</td></tr><tr><td>Total operating expenses</td><td>569,161</td><td>1,118,460</td><td>3,294,784</td><td>1,206,648</td></tr><tr><td>Income (loss) from operations</td><td>(415,799)</td><td>(851,617)</td><td>(2,744,506)</td><td>(58,387)</td></tr><tr><td>Other income (expenses):</td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td>Net gain (loss) on derivative contracts</td><td>(27,740)</td><td>(17,998)</td><td>310,264</td><td>518,956</td></tr><tr><td>Interest expense and other, net</td><td>(28,861)</td><td>(122,249)</td><td>(232,878)</td><td>(145,689)</td></tr><tr><td>Reorganization items</td><td>(2,049)</td><td>913,722</td><td>—</td><td>—</td></tr><tr><td>Gain (loss) on extinguishment of debt</td><td>—</td><td>81,434</td><td>761,804</td><td>—</td></tr><tr><td>Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants</td><td>—</td><td>—</td><td>(8,219)</td><td>—</td></tr><tr><td>Total other income (expenses)</td><td>(58,650)</td><td>854,909</td><td>830,971</td><td>373,267</td></tr><tr><td>Income (loss) before income taxes</td><td>(474,449)</td><td>3,292</td><td>(1,913,535)</td><td>314,880</td></tr><tr><td>Income tax benefit (provision)</td><td>(4,744)</td><td>8,666</td><td>(9,086)</td><td>1,076</td></tr><tr><td>Net income (loss)</td><td>(479,193)</td><td>11,958</td><td>(1,922,621)</td><td>315,956</td></tr><tr><td>Series A preferred dividends</td><td>—</td><td>(8,847)</td><td>(17,517)</td><td>(19,838)</td></tr><tr><td>Preferred dividends and accretion on redeemable noncontrolling interest</td><td>(791)</td><td>(35,905)</td><td>(66,820)</td><td>(13,176)</td></tr><tr><td>Net income (loss) available to common stockholders</td><td>$ (479,984)</td><td>$ (32,794)</td><td>$ (2,006,958)</td><td>$ 282,942</td></tr><tr><td>Net income (loss) per share of common stock:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 3.40</td></tr><tr><td>Diluted</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 2.93</td></tr><tr><td>Weighted average common shares outstanding:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>91,228</td><td>120,513</td><td>107,531</td><td>83,155</td></tr><tr><td>Diluted</td><td>91,228</td><td>120,513</td><td>107,531</td><td>108,481</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



## HALCÓN RESOURCES CORPORATION

## CONSOLIDATED BALANCE SHEETS

## (In thousands, except share and per share amounts)

<table><tr><td></td><td>Successor December 31, 2016</td><td>Predecessor December 31, 2015</td></tr><tr><td>Current assets:</td><td></td><td></td></tr><tr><td>Cash</td><td>$ 24</td><td>$ 8,026</td></tr><tr><td>Accounts receivable</td><td>147,762</td><td>173,624</td></tr><tr><td>Receivables from derivative contracts</td><td>5,923</td><td>348,861</td></tr><tr><td>Restricted cash</td><td>182</td><td>16,812</td></tr><tr><td>Prepaids and other</td><td>6,758</td><td>9,270</td></tr><tr><td>Total current assets</td><td>160,649</td><td>556,593</td></tr><tr><td>Oil and natural gas properties (full cost method):</td><td></td><td></td></tr><tr><td>Evaluated</td><td>1,269,034</td><td>7,060,721</td></tr><tr><td>Unevaluated</td><td>316,439</td><td>1,641,356</td></tr><tr><td>Gross oil and natural gas properties</td><td>1,585,473</td><td>8,702,077</td></tr><tr><td>Less—accumulated depletion</td><td>(465,849)</td><td>(5,933,688)</td></tr><tr><td>Net oil and natural gas properties</td><td>1,119,624</td><td>2,768,389</td></tr><tr><td>Other operating property and equipment:</td><td></td><td></td></tr><tr><td>Gas gathering and other operating assets</td><td>38,617</td><td>130,090</td></tr><tr><td>Less—accumulated depreciation</td><td>(1,107)</td><td>(22,435)</td></tr><tr><td>Net other operating property and equipment</td><td>37,510</td><td>107,655</td></tr><tr><td>Other noncurrent assets:</td><td></td><td></td></tr><tr><td>Receivables from derivative contracts</td><td>—</td><td>16,614</td></tr><tr><td>Debt issuance costs, net</td><td>—</td><td>7,633</td></tr><tr><td>Funds in escrow and other</td><td>1,887</td><td>1,808</td></tr><tr><td>Total assets</td><td>$ 1,319,670</td><td>$ 3,458,692</td></tr></table>



<table><tr><td>Current liabilities:</td><td></td><td></td></tr><tr><td>Accounts payable and accrued liabilities</td><td></td><td></td></tr><tr><td></td><td>$ 186,184</td><td>$ 295,085</td></tr><tr><td>Liabilities from derivative contracts</td><td></td><td></td></tr><tr><td></td><td>16,434</td><td>—</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>4,935</td><td>163</td></tr><tr><td>Total current liabilities</td><td></td><td></td></tr><tr><td></td><td>207,553</td><td>295,248</td></tr><tr><td>Long-term debt, net</td><td></td><td></td></tr><tr><td></td><td>964,653</td><td>2,873,637</td></tr><tr><td>Other noncurrent liabilities:</td><td></td><td></td></tr><tr><td>Liabilities from derivative contracts</td><td></td><td></td></tr><tr><td></td><td>486</td><td>290</td></tr><tr><td>Asset retirement obligations</td><td></td><td></td></tr><tr><td></td><td>31,985</td><td>46,853</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>2,305</td><td>6,264</td></tr><tr><td>Commitments and contingencies (Note 11)</td><td></td><td></td></tr><tr><td>Mezzanine equity:</td><td></td><td></td></tr><tr><td>Redeemable noncontrolling interest</td><td></td><td></td></tr><tr><td></td><td>—</td><td>183,986</td></tr><tr><td>Stockholders&#x27; equity:</td><td></td><td></td></tr><tr><td>Predecessor Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 244,724 shares of 5.75% Cumulative Perpetual Convertible Series A, issued and outstanding</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Predecessor Common stock: 1,340,000,000 shares of $0.0001 par value authorized; 122,523,559 shares issued and outstanding</td><td></td><td>12</td></tr><tr><td>Predecessor Additional paid-in capital</td><td></td><td>3,283,097</td></tr><tr><td>Successor Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 92,991,183 shares issued and outstanding</td><td></td><td>—</td></tr><tr><td>Successor Additional paid-in capital</td><td></td><td>—</td></tr><tr><td>Retained earnings (accumulated deficit)</td><td></td><td></td></tr><tr><td></td><td>(479,984)</td><td>(3,230,695)</td></tr><tr><td>Total stockholders&#x27; equity</td><td></td><td></td></tr><tr><td></td><td>112,688</td><td>52,414</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td></td><td></td></tr><tr><td></td><td>$ 1,319,670</td><td>$ 3,458,692</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



## HALCÓN RESOURCES CORPORATION

## CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

## (In thousands)

<table><tr><td rowspan="2"></td><td colspan="2">Preferred Stock</td><td colspan="2">Common Stock</td><td rowspan="2">Additional Paid-In Capital</td><td rowspan="2">Accumulated Deficit</td><td rowspan="2">Stockholders&#x27; Equity</td></tr><tr><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Balances at December 31, 2013 (Predecessor)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>345</td><td>$ —</td><td>83,146</td><td>$ 8</td><td>$ 2,953,819</td><td>$ (1,506,217)</td><td>$ 1,447,610</td></tr><tr><td>Net income (loss)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>315,956</td><td>315,956</td></tr><tr><td>Dividends on Series A preferred stock</td><td></td><td></td><td>653</td><td>—</td><td>14,878</td><td>(19,838)</td><td>(4,960)</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(6,543)</td><td>(6,543)</td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td></td><td></td><td></td><td></td><td></td><td>(6,633)</td><td>(6,633)</td></tr><tr><td>Offering costs</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>39</td><td>—</td><td>39</td></tr><tr><td>Long-term incentive plan grants</td><td></td><td></td><td>1,878</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Long-term incentive plan forfeitures</td><td></td><td></td><td>(91)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Reduction in shares to cover individuals&#x27; tax withholding</td><td></td><td></td><td>(24)</td><td>—</td><td>(453)</td><td>—</td><td>(453)</td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>27,153</td><td>—</td><td>27,153</td></tr><tr><td>Balances at December 31, 2014 (Predecessor)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>345</td><td>—</td><td>85,562</td><td>8</td><td>2,995,436</td><td>(1,223,275)</td><td>1,772,169</td></tr><tr><td>Net income (loss)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1,922,621)</td><td>(1,922,621)</td></tr><tr><td>Dividends on Series A preferred stock</td><td></td><td></td><td>1,354</td><td>1</td><td>9,801</td><td>(17,979)</td><td>(8,177)</td></tr><tr><td>Conversion of Series A preferred stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(100)</td><td>—</td><td>3,258</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest</td><td></td><td></td><td></td><td></td><td></td><td>(12,614)</td><td>(12,614)</td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(53,561)</td><td>(53,561)</td></tr><tr><td>Change in fair value of redeemable noncontrolling interest</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(645)</td><td>(645)</td></tr><tr><td>Common stock issuance</td><td></td><td></td><td>1,888</td><td>—</td><td>15,356</td><td>—</td><td>15,356</td></tr><tr><td>Common stock issuance on conversion of senior notes</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>28,955</td><td>3</td><td>231,380</td><td>—</td><td>231,383</td></tr><tr><td>Modification of February 2012 Warrants</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>14,129</td><td>—</td><td>14,129</td></tr><tr><td>Offering costs</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1,871)</td><td>—</td><td>(1,871)</td></tr><tr><td>Long-term incentive plan grants</td><td></td><td></td><td>2,048</td><td>—</td><td>—</td><td>—</td><td>—</td></tr></table>



<table><tr><td>Long-term incentive plan forfeitures</td><td>—</td><td>—</td><td>(388)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Reduction in shares to cover individuals&#x27; tax withholding</td><td>—</td><td>—</td><td>(153)</td><td>—</td><td>(947)</td><td>—</td><td>(947)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>19,813</td><td>—</td><td>19,813</td></tr><tr><td>Balances at December 31, 2015 (Predecessor)</td><td>245</td><td>—</td><td>122,524</td><td>12</td><td>3,283,097</td><td>(3,230,695)</td><td>52,414</td></tr><tr><td>Net income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>11,958</td><td>11,958</td></tr><tr><td>Conversion of Series A preferred stock</td><td>(23)</td><td>—</td><td>724</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(9,329)</td><td>(9,329)</td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(26,576)</td><td>(26,576)</td></tr><tr><td>Fair value of equity issued to Predecessor common stockholders</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(22,176)</td><td>—</td><td>(22,176)</td></tr><tr><td>Cash payment to Preferred Holders</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(11,100)</td><td>—</td><td>(11,100)</td></tr><tr><td>Reverse stock split rounding</td><td>—</td><td>—</td><td>5</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Offering costs</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(10)</td><td>—</td><td>(10)</td></tr><tr><td>Long-term incentive plan forfeitures</td><td>—</td><td>—</td><td>(517)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Reduction in shares to cover individuals&#x27; tax withholding</td><td>—</td><td>—</td><td>(498)</td><td>—</td><td>(176)</td><td>—</td><td>(176)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>4,995</td><td>—</td><td>4,995</td></tr><tr><td>Balances at September 9, 2016 (Predecessor)</td><td>222</td><td>$</td><td>122,238</td><td>$</td><td>12</td><td>$ 3,254,630</td><td>(3,254,642)</td></tr><tr><td>Cancellation of Predecessor equity</td><td>(222)</td><td>$</td><td>(122,238)</td><td>$</td><td>(12)</td><td>$ 3,254,630</td><td>$ 3,254,642</td></tr><tr><td>Balances at September 9, 2016 (Predecessor)</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td><td>—</td><td>$</td></tr><tr><td>Issuance of Successor common stock and warrants</td><td>—</td><td>$</td><td>90,000</td><td>$</td><td>9</td><td>$ 571,114</td><td>$</td></tr><tr><td>Balances at September 9, 2016 (Successor)</td><td>—</td><td>$</td><td>90,000</td><td>$</td><td>9</td><td>$ 571,114</td><td>$</td></tr><tr><td>Net income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(479,193)</td><td>(479,193)</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(791)</td><td>(791)</td></tr><tr><td>Long-term incentive plan grants</td><td>—</td><td>—</td><td>2,991</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>21,549</td><td>—</td><td>21,549</td></tr><tr><td>Balances at December 31, 2016 (Successor)</td><td>—</td><td>$</td><td>92,991</td><td>$</td><td>9</td><td>$ 592,663</td><td>$ (479,984)</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.






## HALCÓN RESOURCES CORPORATION

## CONSOLIDATED STATEMENTS OF CASH FLOWS

## (In thousands)

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Cash flows from operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$ (479,193)</td><td>$ 11,958</td><td>$ (1,922,621)</td><td>$ 315,956</td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depletion, depreciation and accretion</td><td>46,899</td><td>120,555</td><td>364,204</td><td>534,421</td></tr><tr><td>Full cost ceiling impairment</td><td>420,934</td><td>754,769</td><td>2,626,305</td><td>239,668</td></tr><tr><td>Other operating property and equipment impairment</td><td>—</td><td>28,056</td><td>—</td><td>35,558</td></tr><tr><td>Share-based compensation, net</td><td>21,519</td><td>4,876</td><td>14,529</td><td>18,733</td></tr><tr><td>Unrealized loss (gain) on derivative contracts</td><td>112,449</td><td>263,732</td><td>129,282</td><td>(508,285)</td></tr><tr><td>Amortization and write-off of deferred loan costs</td><td>—</td><td>6,371</td><td>7,357</td><td>4,315</td></tr><tr><td>Non-cash interest and amortization of discount and premium</td><td>2,506</td><td>1,515</td><td>2,509</td><td>2,780</td></tr><tr><td>Reorganization items</td><td>(15,963)</td><td>(929,084)</td><td>—</td><td>—</td></tr><tr><td>Loss (gain) on extinguishment of debt</td><td>—</td><td>(81,434)</td><td>(761,804)</td><td>—</td></tr><tr><td>Loss (gain) on extinguishment of Convertible Note and modification of February 2012 Warrants</td><td>—</td><td>—</td><td>8,219</td><td>—</td></tr><tr><td>Accrued settlements on derivative contracts</td><td>(18,498)</td><td>—</td><td>(47,011)</td><td>(25,868)</td></tr><tr><td>Other expense (income)</td><td>79</td><td>(4,233)</td><td>8,934</td><td>(2,435)</td></tr><tr><td>Change in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(20,459)</td><td>47,920</td><td>86,411</td><td>85,767</td></tr><tr><td>Prepaids and other</td><td>857</td><td>(4,329)</td><td>3,714</td><td>7,474</td></tr><tr><td>Accounts payable and accrued liabilities</td><td>32,006</td><td>(45,324)</td><td>(53,029)</td><td>(40,150)</td></tr><tr><td>Net cash provided by (used in) operating activities</td><td>103,136</td><td>175,348</td><td>466,999</td><td>667,934</td></tr><tr><td>Cash flows from investing activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Oil and natural gas capital expenditures</td><td>(61,459)</td><td>(226,617)</td><td>(659,419)</td><td>(1,524,341)</td></tr></table>



<table><tr><td>Proceeds received from sales of oil and natural gas assets</td><td>888</td><td>(407)</td><td>1,222</td><td>484,184</td></tr><tr><td>Advance on carried interest</td><td>—</td><td>—</td><td>—</td><td>(189,442)</td></tr><tr><td>Other operating property and equipment capital expenditures</td><td>(750)</td><td>(950)</td><td>(10,838)</td><td>(43,083)</td></tr><tr><td>Funds held in escrow and other</td><td>(1,721)</td><td>200</td><td>1,903</td><td>1,589</td></tr><tr><td>Net cash provided by (used in) investing activities</td><td>(63,042)</td><td>(227,774)</td><td>(667,132)</td><td>(1,271,093)</td></tr><tr><td>Cash flows from financing activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Proceeds from borrowings</td><td>115,000</td><td>886,000</td><td>1,834,000</td><td>2,276,000</td></tr><tr><td>Repayments of borrowings</td><td>(159,000)</td><td>(727,648)</td><td>(1,643,804)</td><td>(1,719,000)</td></tr><tr><td>Cash payments to Noteholders and Preferred Holders</td><td>(10,013)</td><td>(97,521)</td><td>—</td><td>—</td></tr><tr><td>Debt issuance costs</td><td>—</td><td>(1,977)</td><td>(29,568)</td><td>(819)</td></tr><tr><td>Series A preferred dividends</td><td>—</td><td>—</td><td>(8,177)</td><td>(4,960)</td></tr><tr><td>Common stock issued</td><td>—</td><td>—</td><td>15,356</td><td>—</td></tr><tr><td>HK TMS LLC preferred stock issued</td><td>—</td><td>—</td><td>—</td><td>110,051</td></tr><tr><td>HK TMS LLC tranche rights</td><td>—</td><td>—</td><td>—</td><td>4,516</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest</td><td>—</td><td>—</td><td>—</td><td>(3,518)</td></tr><tr><td>Restricted cash</td><td>—</td><td>—</td><td>(543)</td><td>(16,131)</td></tr><tr><td>Offering costs and other</td><td>—</td><td>(511)</td><td>(2,818)</td><td>(2,101)</td></tr><tr><td>Net cash provided by (used in) financing activities</td><td>(54,013)</td><td>58,343</td><td>164,446</td><td>644,038</td></tr><tr><td>Net increase (decrease) in cash</td><td>(13,919)</td><td>5,917</td><td>(35,687)</td><td>40,879</td></tr><tr><td>Cash at beginning of period</td><td>13,943</td><td>8,026</td><td>43,713</td><td>2,834</td></tr><tr><td>Cash at end of period</td><td>$ 24</td><td>$ 13,943</td><td>$ 8,026</td><td>$ 43,713</td></tr><tr><td>Supplemental cash flow information:</td><td></td><td></td><td></td><td></td></tr><tr><td>Cash paid for interest, net of capitalized interest</td><td>$ 3,605</td><td>$ 139,930</td><td>$ 204,178</td><td>$ 132,557</td></tr><tr><td>Cash paid (refunded) for income taxes</td><td>5,000</td><td>—</td><td>(3,078)</td><td>(8,600)</td></tr><tr><td>Cash paid for reorganization items</td><td>18,012</td><td>15,362</td><td>—</td><td>—</td></tr><tr><td>Disclosure of non-cash investing and financing activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accrued capitalized interest</td><td>$ —</td><td>$ (23,966)</td><td>$ (1,417)</td><td>$ (1,180)</td></tr><tr><td>Asset retirement obligations</td><td>513</td><td>939</td><td>6,742</td><td>(1,262)</td></tr></table>



<table><tr><td>Series A preferred dividends paid in common stock</td><td>—</td><td>—</td><td>9,802</td><td>14,878</td></tr><tr><td>Preferred dividends on redeemable noncontrolling interest paid-in-kind</td><td>791</td><td>9,329</td><td>12,614</td><td>3,025</td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td>—</td><td>26,576</td><td>53,561</td><td>6,633</td></tr><tr><td>Change in fair value of redeemable noncontrolling interest</td><td>—</td><td>—</td><td>645</td><td>—</td></tr><tr><td>Common stock issued on conversion of senior notes</td><td>—</td><td>—</td><td>231,383</td><td>—</td></tr><tr><td>Third Lien Notes issued on conversion of senior notes</td><td>—</td><td>—</td><td>1,017,970</td><td>—</td></tr><tr><td>2022 Second Lien Notes issued on conversion of senior notes</td><td>—</td><td>—</td><td>112,826</td><td>—</td></tr><tr><td>Accrued debt issuance costs</td><td>—</td><td>1,176</td><td>(1,176)</td><td>—</td></tr><tr><td>Receivable for sale of oil and natural gas properties</td><td>—</td><td>—</td><td>—</td><td>1,000</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

## Basis of Presentation and Principles of Consolidation

Halcón Resources Corporation (Halcón or the Company) is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company's oil and natural gas properties are managed as a whole rather than through discrete operating areas. Operational information is tracked by operating area; however, financial performance is assessed as a whole. Allocation of capital is made across the Company's entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. The Company has evaluated events or transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.

## Emergence from Voluntary Reorganization under Chapter 11

On July 27, 2016 (the Petition Date), the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a joint prepackaged plan of reorganization (the Plan). On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. The Company's subsidiary, HK TMS, LLC which was divested on September 30, 2016, was not part of the chapter 11 bankruptcy filings. See Note 2, "Reorganization," for further details on the Company's chapter 11 bankruptcy and the Plan and Note 5, "Divestitures," for further details on the divestiture of HK TMS, LLC.

Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result of the adoption of fresh-start accounting, the Company's consolidated financial statements subsequent to September 9, 2016 are not comparable to its consolidated financial statements prior to, and including, September 9, 2016. See Note 3, "Fresh-start Accounting," for further details on the impact of fresh-start accounting on the Company's consolidated financial statements.

References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.

## Use of Estimates

The preparation of the Company's consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's consolidated financial statements.

## Accounts Receivable and Allowance for Doubtful Accounts

The Company's accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. There were no significant allowances for doubtful accounts as of December 31, 2016 (Successor) or 2015 (Predecessor).

## Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Successor Company's



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization.

## Other Operating Property and Equipment

Gas gathering systems and equipment are recorded at cost. Depreciation is calculated using the straight-line method over a 30-year or 10-year estimated useful life applicable to gas gathering systems and compressed natural gas facilities, respectively. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. With the adoption of fresh-start accounting, the Company recorded its gas gathering systems and equipment at fair value totaling approximately $16.3 million as of the fresh-start reporting date. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used. At December 31, 2016 (Successor) and 2015 (Predecessor), the Company had approximately $16.4 million and $87.2 million capitalized, respectively, related to the construction of its gas gathering systems, after any amounts impaired.

Other operating assets are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years or the lesser of lease term; trailers, seven years; heavy equipment, ten years; buildings, twenty years and leasehold improvements, lease term. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. With the adoption of fresh-start accounting, the Company recorded its other operating assets at fair value totaling approximately $21.8 million as of the fresh-start reporting date. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used.

The Company reviews its gas gathering systems and equipment and other operating assets for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate gas gathering systems and equipment and other operating assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its gas gathering systems and equipment and other operating assets at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. For the three months ended March 31, 2016 (Predecessor), the Company recorded a non-cash impairment charge of $28.1 million related to $32.8 million gross investments in gas gathering infrastructure that were deemed non-economical due to a shift in exploration, drilling and developmental plans in a low commodity price environment. For the year ended December 31, 2014 (Predecessor), the Company recorded a non-cash impairment charge for gas gathering systems and other related operating assets of $35.6 million, net of $1.9 million of accumulated depreciation. The majority of the impairment represents approximately half of the Predecessor Company's gas gathering infrastructure, right-of-way and permitting investments in the Utica / Point Pleasant area (Utica). These infrastructure related



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

investments were related to acreage in certain non-core areas of the Utica play which, at the time of evaluation for impairment in December 2014, the Predecessor Company did not plan to develop in light of the downtrend in oil prices which rendered certain areas to be deemed uneconomical and/or non-strategic. These impairments were recorded in "Other operating property and equipment impairment" in the Company's consolidated statements of operations and in "Gas gathering and other operating assets" in the Company's consolidated balance sheets.

In accordance with ASC 820, Fair Value Measurements and Disclosures (ASC 820), a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The estimate of the fair value of the Company's gas gathering systems was based on an income approach that estimated future cash flows associated with those assets over the remaining asset lives. This estimation includes the use of unobservable inputs, such as estimated future production, gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company's gas gathering systems being classified as Level 3.

## Revenue Recognition

Revenues from the sale of crude oil, natural gas, and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company follows the entitlement method of accounting for crude oil and natural gas sales, recognizing as revenues only its net interest share of all production sold. Any amount attributable to the sale of production in excess of or less than the Company's net interest is recorded as a balancing asset or liability. At December 31, 2016 (Successor) and 2015 (Predecessor), the Company's imbalances were immaterial.

## Concentrations of Credit Risk

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company's joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company's joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company's oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. For the combined periods, September 10, 2016 through December 31, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor), two individual purchasers of the Company's production, Crestwood Midstream Partners, formerly Arrow Field Services LLC (Crestwood), and Energy Marketing Inc. (Suncor), each accounted for more than 10% of total sales, collectively representing 58%, of the Company's total sales for the period. In 2015 and 2014 (Predecessor), three individual purchasers of the Company's production, Crestwood, Sunoco Inc. and Suncor, each accounted for more than 10% of total sales, collectively representing 57% and 66%, respectively, of the Company's total sales for the years.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

## Risk Management Activities

The Company follows ASC 815, Derivatives and Hedging (ASC 815). From time to time, when derivative contracts are available at terms (or prices) acceptable to the Company, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. The Company recognized all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

## Income Taxes

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company follows ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements.

The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

The Company has no liability for unrecognized tax benefits as of December 31, 2016 (Successor) and 2015 (Predecessor). Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2016 (Successor), 2015 and 2014 (Predecessor). In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

The Company includes interest and penalties relating to uncertain tax positions within "Interest expense and other, net" on the Company's consolidated statements of operations. Refer to Note 14, "Income Taxes," for more details.

Generally, the Company's tax years 2013 through 2016 are either currently under audit or remain open and subject to examination by federal tax authorities or the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, principal operations. In certain of these jurisdictions, the Company operates through more than one legal entity, each of which may have different open years subject to examination. Additionally, it is important to note that years are open for examination until the statute of limitations in each respective jurisdiction expires.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.

## Asset Retirement Obligations

ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company's legal obligations related to future plugging and abandonment of its oil and natural gas wells and gas gathering systems and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems and equipment as these obligations are incurred.

## 401(k) Plan

The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees' contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $0.8 million and $2.0 million for the period September 10, 2016 through December 31, 2016 (Successor) and the period January 1, 2016 through September 9, 2016 (Predecessor), respectively. The Company provided matching contributions of $3.8 million and $4.5 million in 2015 and 2014 (Predecessor), respectively. The Company matches employee contributions dollar-for-dollar on the first 10% of an employee's pre-tax earnings, subject to individual IRS limitations.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

## Recently Issued Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and early adoption is permitted. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this ASU using a retrospective transition method. The Company is in the early stages of assessing the effects of the application of the new guidance.

In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (ASU 2016-09). For public business entities, ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. The areas for simplification in this ASU involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Some of the areas for simplification apply only to nonpublic entities. As there are multiple amendments in this ASU, the FASB has issued guidance on how an entity should apply each amendment, either prospectively or retrospectively. The Company adopted ASU 2016-09 on September 9, 2016. See Note 13, "Stockholders' Equity" for further details.

In March 2016, the FASB issued ASU 2016-06, Contingent Put and Call Options in Debt Instruments (ASU 2016-06). For public business entities, ASU 2016-06 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and early adoption is permitted. ASU 2016-06 provides new guidance that simplifies the analysis of whether a contingent put or call option in a debt instrument qualifies as a separate derivative. An entity should apply the amendments in this ASU on a modified retrospective basis to existing debt instruments as of the beginning of the fiscal year for which the amendments are effective. The Company adopted ASU 2016-06 in 2016 resulting in no changes to the accounting for its current debt instruments.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and early adoption is permitted. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity should apply the amendments in this ASU on a modified retrospective basis. The transition will require application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company is in the early stages of assessing the effects of the application of the new guidance and the financial statement and disclosure impacts. The Company will adopt ASU 2016-02 no later than January 1, 2019.

In September 2015, the FASB issued ASU 2015-16, Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). For public business entities, ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. The amendments in this ASU require that an acquirer, in a business combination, recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. To simplify the accounting for adjustments made to provisional amounts recognized in a



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Continued)

business combination, the amendments in this ASU eliminate the requirement to retrospectively account for those adjustments, and instead present separately on the face of the income statement or disclose in the footnotes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods. The adoption of ASU 2015-16 did not have a material impact to the Company's financial statements or disclosures.

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis (ASU 2015-02). The amendments in ASU 2015-02 eliminate the previous presumption that a general partner controls a limited partner. ASU 2015-02 is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. Entities may apply the guidance using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the first fiscal year adopted or it may apply the amendment retrospectively. The adoption of ASU 2015-02 did not have an impact on the Company's financial statements or disclosures.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern (ASU 2014-15). ASU 2014-15 is effective for annual reporting periods (including interim periods within those periods) ending after December 15, 2016. Early application is permitted. The amendments in ASU 2014-15 create a new ASC Sub-topic 205-40, Presentation of Financial Statements—Going Concern and require management to assess for each annual and interim reporting period if conditions exist that raise substantial doubt about an entity's ability to continue as a going concern. The rule requires various disclosures depending on the facts and circumstances surrounding an entity's ability to continue as a going concern. Effective June 30, 2016, the Company early adopted ASU 2014-15 on a prospective basis.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, after December 15, 2017. Early adoption is not permitted. The Company is in the early stages of assessing the effects of the application of the new guidance and the financial statement and disclosure impacts. The Company will adopt ASU 2014-09 effective January 1, 2018.

## 2. REORGANIZATION

On June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company's 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), the Company's 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of the Company's 8% senior unsecured convertible note due 2020



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 2. REORGANIZATION (Continued)

(the Convertible Noteholder), and certain holders of the Company's 5.75% Series A Convertible Perpetual Preferred Stock. On July 27, 2016, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to effect an accelerated prepackaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement. On September 8, 2016, the Bankruptcy Court entered an order confirming the Company's plan of reorganization and on September 9, 2016, the Halcón Entities emerged from chapter 11 bankruptcy.

Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred:

- the Predecessor Company's financing facility under the Predecessor Credit Agreement was refinanced and replaced with the DIP Facility, which was subsequently converted into the Senior Credit Agreement (refer to Note 7, "Long-term Debt" for credit agreement definitions and further details regarding the credit agreements);

- the Predecessor Company's Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated;

- the Predecessor Company's Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

- the Predecessor Company's Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims;

- the Predecessor Company's Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims;

• the general unsecured claims were unimpaired and paid in full in the ordinary course;

- all outstanding shares of the Predecessor Company's Series A Preferred Stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and

- all of the Predecessor Company's outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 2. REORGANIZATION (Continued)

Each of the foregoing percentages of equity in the reorganized Company were as of September 9, 2016 and subject to dilution from the exercise of the new warrants described above, a management incentive plan and other future issuances of equity securities.

See Note 7, "Long-term Debt," and Note 13, "Stockholders' Equity," for further information regarding the Company's Successor and Predecessor debt and equity instruments.

## 3. FRESH-START ACCOUNTING

Upon the Company's emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company's assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 2, "Reorganization," for the terms of the Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as "Successor" or "Successor Company." However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies may lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are presented to distinguish between the Predecessor and Successor Companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the application of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company's total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would value the Company's assets immediately after the reorganization.

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company's long-term debt, stockholders' equity and working capital. The estimated Enterprise Value at the Effective Date is below the midpoint of the Court approved range of $1.6 billion to $1.8 billion, primarily reflecting the decline in forward commodity prices during the period between the Company's analysis performed in advance of the July 2016 chapter 11 bankruptcy filing and the Effective Date. The Enterprise Value was derived from an independent valuation using an asset based methodology of proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of September 9, 2016.

The Company's principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.5% for proved reserves and 12.5% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

$72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.

In estimating the fair value of the Company's unproved acreage that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

See further discussion below in the "Fresh-start accounting adjustments" for the specific assumptions used in the valuation of the Company's various other assets.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment.

The following table reconciles the Company's Enterprise Value to the estimated fair value of the Successor's common stock as of September 9, 2016 (in thousands):

<table><tr><td></td><td>September 9, 2016</td></tr><tr><td>Enterprise Value</td><td>$ 1,618,888</td></tr><tr><td>Plus: Cash</td><td>13,943</td></tr><tr><td>Less: Fair value of debt</td><td>(1,016,160)</td></tr><tr><td>Less: Fair value of redeemable noncontrolling interest</td><td>(41,070)</td></tr><tr><td>Less: Fair value of other long-term liabilities</td><td>(4,478)</td></tr><tr><td>Less: Fair value of warrants</td><td>(16,691)</td></tr><tr><td>Fair Value of Successor common stock</td><td>$ 554,432</td></tr></table>

The following table reconciles the Company's Enterprise Value to its Reorganization Value as of September 9, 2016 (in thousands):

<table><tr><td></td><td>September 9, 2016</td></tr><tr><td>Enterprise Value</td><td>$ 1,618,888</td></tr><tr><td>Plus: Cash</td><td>13,943</td></tr><tr><td>Plus: Current liabilities</td><td>178,639</td></tr><tr><td>Plus: Noncurrent asset retirement obligation</td><td>32,156</td></tr><tr><td>Reorganization Value of Successor assets</td><td>$ 1,843,626</td></tr></table>

## Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company's consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company's assumptions and methods used to



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

determine fair value for its assets and liabilities. Amounts included in the table below are rounded to thousands.

<table><tr><td rowspan="2"></td><td colspan="5">As of September 9, 2016</td></tr><tr><td>Predecessor Company</td><td>Reorganization Adjustments</td><td>Fresh-Start Adjustments</td><td>Successor Company</td><td></td></tr><tr><td>Current assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash</td><td>$ 111,464</td><td>$ (97,521)</td><td>$ —</td><td>$ 13,943</td><td></td></tr><tr><td>Accounts receivable</td><td>116,859</td><td>—</td><td>—</td><td>116,859</td><td></td></tr><tr><td>Receivables from derivative contracts</td><td>97,648</td><td>—</td><td>—</td><td>97,648</td><td></td></tr><tr><td>Restricted cash</td><td>17,164</td><td>—</td><td>—</td><td>17,164</td><td></td></tr><tr><td>Prepaids and other</td><td>8,961</td><td>—</td><td>(1,332)</td><td>7,629</td><td></td></tr><tr><td>Total current assets</td><td>352,096</td><td>(97,521)</td><td>(1,332)</td><td>253,243</td><td></td></tr></table>

Oil and natural gas properties (full cost method):

<table><tr><td>Evaluated</td><td>7,712,003</td><td>—</td><td>(6,497,874)</td><td>(8)</td><td>1,214,129</td></tr><tr><td>Unevaluated</td><td>1,193,259</td><td>—</td><td>(861,144)</td><td>(8)</td><td>332,115</td></tr><tr><td>Gross oil and natural gas properties</td><td>8,905,262</td><td>—</td><td>(7,359,018)</td><td>1,546,244</td><td></td></tr><tr><td>Less—accumulated depletion</td><td>(6,803,231)</td><td>—</td><td>6,803,231</td><td>(8)</td><td>—</td></tr><tr><td>Net oil and natural gas properties</td><td>2,102,031</td><td>—</td><td>(555,787)</td><td>1,546,244</td><td></td></tr></table>

Other operating property and equipment:

<table><tr><td>Gas gathering and other operating assets</td><td>100,079</td><td>—</td><td>(62,008)</td><td>(9)</td><td>38,071</td></tr><tr><td>Less—accumulated depreciation</td><td>(24,154)</td><td>—</td><td>24,154</td><td>(9)</td><td>—</td></tr><tr><td>Net other operating property and equipment</td><td>75,925</td><td>—</td><td>(37,854)</td><td>38,071</td><td></td></tr></table>

Other noncurrent assets:

<table><tr><td>Receivables from derivative contracts</td><td>4,431</td><td>—</td><td>—</td><td>4,431</td></tr><tr><td>Funds in escrow and other</td><td>1,610</td><td>—</td><td>27</td><td>1,637</td></tr><tr><td>Total assets</td><td>$ 2,536,093</td><td>$ (97,521)</td><td>$ (594,946)</td><td>$1,843,626</td></tr></table>



<table><tr><td>Accounts payable and accrued liabilities</td><td>$ 160,000</td><td>$ 13,688(2)</td><td>$ —</td><td>$ 173,688</td></tr><tr><td>Liabilities from derivative contracts</td><td>102</td><td>—</td><td>—</td><td>102</td></tr><tr><td>Other</td><td>414</td><td>—</td><td>(11)</td><td>4,435(12)</td></tr><tr><td>Total current liabilities</td><td>160,516</td><td>13,688</td><td>4,435</td><td>178,639</td></tr><tr><td>Long-term debt, net</td><td>1,031,114</td><td>—</td><td>(14,954)(13)</td><td>1,016,160</td></tr><tr><td>Liabilities subject to compromise</td><td>2,007,703</td><td>(2,007,703)(3)</td><td>—</td><td>—</td></tr><tr><td>Other noncurrent liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities from derivative contracts</td><td>525</td><td>—</td><td>—</td><td>525</td></tr><tr><td>Asset retirement obligations</td><td>48,955</td><td>—</td><td>(16,799)(12)</td><td>32,156</td></tr><tr><td>Other</td><td>528</td><td>—</td><td>(11)</td><td>3,425(14)</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td><td></td><td></td></tr><tr><td>Mezzanine equity:</td><td></td><td></td><td></td><td></td></tr><tr><td>Redeemable noncontrolling interest</td><td>219,891</td><td>—</td><td>(178,821)(14)</td><td>41,070</td></tr><tr><td>Stockholders&#x27; equity:</td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred stock (Predecessor)</td><td>—</td><td>—(4)</td><td>—</td><td>—</td></tr><tr><td>Common Stock (Predecessor)</td><td>12</td><td>(12)(4)</td><td>—</td><td>—</td></tr><tr><td>Common Stock (Successor)</td><td>—</td><td>9(5)</td><td>—</td><td>9</td></tr><tr><td>Additional paid-in capital (Predecessor)</td><td>3,287,906</td><td>(3,287,906)(4)</td><td>—</td><td>—</td></tr><tr><td>Additional paid-in capital (Successor)</td><td>—</td><td>571,114(5)</td><td>—</td><td>571,114</td></tr><tr><td>Retained earnings (accumulated deficit)</td><td>(4,221,057)</td><td>4,613,289(6)</td><td>(392,232)(15)</td><td>—</td></tr><tr><td>Total stockholders&#x27; equity</td><td>(933,139)</td><td>1,896,494</td><td>(392,232)</td><td>571,123</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td>$ 2,536,093</td><td>$ (97,521)</td><td>$ (594,946)</td><td>$1,843,626</td></tr></table>



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

## Reorganization adjustments

1) The table below details cash payments as of September 9, 2016, pursuant to the terms of the Plan described in Note 2, "Reorganization" (in thousands):

<table><tr><td>Payment to Third Lien Noteholders</td><td>$ 33,826</td></tr><tr><td>Payment to Unsecured Noteholders</td><td>37,595</td></tr><tr><td>Payment to Convertible Noteholder</td><td>15,000</td></tr><tr><td>Payment to Preferred Holders</td><td>11,100</td></tr><tr><td>Total Uses</td><td>$ 97,521</td></tr></table>

2) In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. This amount also reflects $10.3 million paid to the Company's restructuring advisors subsequent to the emergence from chapter 11 bankruptcy.

3) Liabilities subject to compromise were as follows (in thousands):

<table><tr><td>13.0% senior secured third lien notes due 2022</td><td>$ 1,017,970</td></tr><tr><td>9.25% senior notes due 2022</td><td>37,194</td></tr><tr><td>8.875% senior notes due 2021</td><td>297,193</td></tr><tr><td>9.75% senior notes due 2020</td><td>315,535</td></tr><tr><td>8.0% convertible note due 2020</td><td>289,669</td></tr><tr><td>Accrued interest</td><td>46,715</td></tr><tr><td>Office lease modification and rejection fees</td><td>3,427</td></tr><tr><td>Liabilities subject to compromise</td><td>2,007,703</td></tr><tr><td>Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder</td><td>(548,947)</td></tr><tr><td>Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder</td><td>(86,421)</td></tr><tr><td>Office lease modification and rejection fees</td><td>(3,427)</td></tr><tr><td>Gain on settlement of Liabilities subject to compromise</td><td>$ 1,368,908</td></tr></table>

4) Reflects the cancellation of Predecessor equity, as follows (in thousands):

<table><tr><td>Predecessor Company stock</td><td>$ 3,287,918</td></tr></table>



<table><tr><td>Fair value of equity issued to Predecessor common stockholders</td><td>(22,176)</td></tr><tr><td>Cash payment to Preferred Holders</td><td>(11,100)</td></tr><tr><td>Cancellation of Predecessor Company equity</td><td></td></tr><tr><td></td><td>$ 3,254,642</td></tr></table>

5) Reflects the issuance of Successor equity. In accordance with the Plan, the Successor Company issued 3.6 million shares of common stock to the Predecessor Company's existing common stockholders, 68.8 million shares of common stock to the Third Lien Noteholders, 14.0 million shares of common stock to the Unsecured Noteholders, and 3.6 million shares of common stock to



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

the Convertible Noteholder. This amount is subject to dilution by warrants issued to the Unsecured Noteholders and the Convertible Noteholder totaling 4.7 million shares with an exercise price of $14.04 per share and a term of four years. The fair value of the warrants was estimated at $3.52 per share using a Black-Scholes-Merton valuation model.

6) The table below reflects the cumulative effect of the reorganization adjustments discussed above (in thousands):

<table><tr><td>Gain on settlement of Liabilities subject to compromise</td><td>$ 1,368,908</td></tr><tr><td>Accrued reorganization items</td><td>(10,261)</td></tr><tr><td>Cancellation of Predecessor Company equity</td><td>3,254,642</td></tr><tr><td>Net impact to retained earnings (accumulated deficit)</td><td>$ 4,613,289</td></tr></table>

## Fresh-start accounting adjustments

7) Reflects the reclassification of tubulars and well equipment to "Oil and natural gas properties."

8) In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.5% for proved reserves and 12.5% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.

In estimating the fair value of the Company's unproved acreage that was not included in the valuation of probable and possible reserves, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company's unproved acreage from a market participant perspective.

9) In estimating the fair value of its gas gathering and other operating assets, the Company used a combination of the income, cost, and market approaches.

For purposes of estimating the fair value of its gas gathering assets, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues, and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%.

For purposes of estimating the fair value of its other operating assets, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and computer equipment, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.

10) Reflects the adjustment of the Company's equity method investment in SBE Partners, L.P. to fair value based on an income approach, which calculated the discounted cash flows of the Company's share of the partnership's interest in oil and gas proved reserves. The anticipated cash flows of the reserve were risked by reserve category and discounted at 10.5%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and analysts' estimated prices.

11) Records an intangible liability of approximately $8.3 million, $4.5 million of which was recorded as current, to adjust the Company's active rig contract to fair value at September 9, 2016. The intangible liability will be amortized over the remaining life of the contract through July 2018.

12) Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 9, 2016, adjusted for inflation and then discounted at the appropriate credit-adjusted risk free rate ranging from 5.5% to 6.6% depending on the life of the well. The fair value of asset retirement obligations was estimated at $32.5 million, approximately $0.3 million of which was recorded as current. Refer to Note 10, "Asset Retirement Obligations" for further details of the Company's asset retirement obligations.

13) Reflects the adjustment of the 2020 Second Lien Notes and the 2022 Second Lien Notes to fair value. The fair value estimate was based on quoted market prices from trades of such debt on September 9, 2016. Refer to Note 7, "Long-term Debt" for definitions of and further information regarding the 2020 Second Lien Notes and 2022 Second Lien Notes.

14) Reflects the adjustment of the Company's redeemable noncontrolling interest and related embedded derivative of HK TMS, LLC to fair value. The fair value of the redeemable noncontrolling interest was estimated at $41.1 million and the embedded derivative was estimated at zero. For purposes of estimating the fair values, an income approach was used that estimated fair value based on the anticipated cash flows associated with HK TMS, LLC's proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 12.5%. The value of the redeemable noncontrolling interest was further reduced by a probability factor of the potential assignment of the common shares of HK TMS, LLC to Apollo Global Management, which occurred subsequent to the fresh-start date. Refer to Note 5, "Divestitures," for further information regarding the divestiture of HK TMS, LLC on September 30, 2016.

15) Reflects the cumulative effect of the fresh-start accounting adjustments discussed above.

## Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. FRESH-START ACCOUNTING (Continued)

adjustments and are recorded in "Reorganization items" in the Company's consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

<table><tr><td></td><td>Successor</td><td>Predecessor</td></tr><tr><td></td><td>Period from September 10, 2016 through December 31, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td></tr><tr><td>Gain on settlement of Liabilities subject to compromise</td><td>$ —</td><td>$ 1,368,908</td></tr><tr><td>Fresh start adjustments</td><td>—</td><td>(392,232)</td></tr><tr><td>Reorganization professional fees and other</td><td>(2,049)</td><td>(30,287)</td></tr><tr><td>Write-off debt discounts/premiums and debt issuance costs</td><td>—</td><td>(32,667)</td></tr><tr><td>Gain (loss) on reorganization items</td><td>$ (2,049)</td><td>$ 913,722</td></tr></table>

## 4. RESTRUCTURING

In 2016 and 2015, the Predecessor Company had reductions in its workforce due to the decrease in drilling and developmental activities planned for the years. Consequently, in 2016 and 2015 the Predecessor Company incurred approximately $5.2 million and $2.9 million, respectively, in severance costs and accelerated stock-based compensation expense related to the termination of certain employees during the year. These costs were recorded in "Restructuring" on the consolidated statements of operations.

## 5. DIVESTITURES

## HK TMS, LLC

On September 30, 2016, certain wholly-owned subsidiaries of the Successor Company executed an Assignment and Assumption Agreement with an affiliate of Apollo Global Management (Apollo) pursuant to which Apollo acquired one hundred percent (100%) of the common shares (the Membership Interests) of HK TMS, LLC (HK TMS), which transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary and held all of the Successor Company's oil and natural gas properties in the Tuscaloosa Marine Shale (TMS). In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests, which were previously classified as "Mezzanine Equity" on the consolidated balance sheets of HK TMS, from and after such date. Refer to Note 12, "Mezzanine Equity" for further details of the accounting considerations for HK TMS.

Effective with the HK TMS Divestiture, all of the Successor Company's existing 100% owned subsidiaries are joint and several, full and unconditional guarantors of its long-term debt obligations and the Successor Company has no independent assets or operations. As a consequence, the Successor Company has discontinued the presentation of condensed consolidating financial statements which separately presented HK TMS's non-guarantor financial position, statements of operations and statements of cash flows.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. DIVESTITURES (Continued)

## East Texas Assets

On May 9, 2014, the Predecessor Company completed the divestiture of certain non-core assets in East Texas (the East Texas Assets) to a privately-owned company for a total sales price of $424.5 million after closing adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. The effective date of the transaction was April 1, 2014. Proceeds from the sale were recorded as a reduction to the carrying value of the Predecessor Company's full cost pool with no gain or loss recorded.

## 6. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties as of December 31, 2016 (Successor) and 2015 (Predecessor) consisted of the following (in thousands):

<table><tr><td>Subject to depletion</td><td>Successor December 31, 2016</td><td>Predecessor December 31, 2015</td></tr><tr><td>Not subject to depletion:</td><td></td><td></td></tr><tr><td>Exploration and extension wells in progress</td><td>5,159</td><td>55,126</td></tr><tr><td>Other capital costs:</td><td></td><td></td></tr><tr><td>Incurred in 2016(1)</td><td>311,280</td><td>—</td></tr><tr><td>Incurred in 2015</td><td>—</td><td>130,911</td></tr><tr><td>Incurred in 2014</td><td>—</td><td>242,788</td></tr><tr><td>Incurred in 2013 and prior</td><td>—</td><td>1,212,531</td></tr><tr><td>Total not subject to depletion</td><td>316,439</td><td>1,641,356</td></tr><tr><td>Gross oil and natural gas properties</td><td>1,585,473</td><td>8,702,077</td></tr><tr><td>Less accumulated depletion</td><td>(465,849)</td><td>(5,933,688)</td></tr><tr><td>Net oil and natural gas properties</td><td>$1,119,624</td><td>$2,768,389</td></tr></table>

(1) In 2016, with the application of fresh-start accounting, the Company's unevaluated properties were recorded at fair value.

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

With the adoption of fresh-start accounting, the Company recorded its oil and natural gas properties at fair value as of September 9, 2016. The Company's evaluated and unevaluated properties



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 6. OIL AND NATURAL GAS PROPERTIES (Continued)

were assigned values of $1.2 billion and $332.1 million, respectively. Refer to Note 3, "Fresh-start Accounting," for a discussion of the valuation approach used.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. In March 2016, the Predecessor Company transferred the remaining unevaluated Utica and TMS properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool. For the quarter ended March 31, 2016, management concluded that it was no longer probable that capital would be available or approved to continue exploratory drilling activities in the Predecessor Company's Utica or TMS acreage positions in advance of the related lease expirations due to the Predecessor Company's evaluation of strategic alternatives to reduce its debt and preserve liquidity in light of continued low commodity prices, together with a reduction of the Predecessor Company's exploration department and the Predecessor Company's intent to expend capital only on its most economical and proven areas. During the three months ended December 31, 2014, the Predecessor Company also transferred $211.5 million of unevaluated property costs to the full cost pool related to certain non-core areas of the Utica and TMS plays. These costs pertain to acreage that the Predecessor Company did not plan to develop, at the time of evaluation for impairment, in light of the downtrend in oil prices which rendered certain areas to be deemed uneconomical and/or non-strategic.

Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Predecessor Company determined capitalized interest by multiplying the Predecessor Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The capitalized interest amounts were recorded as additions to unevaluated oil and natural gas properties on the consolidated balance sheets. As the costs excluded were transferred to the full cost pool, the associated capitalized interest was also transferred to the full cost pool. For the period from January 1, 2016 through September 9, 2016 (Predecessor) and the year ended December 31, 2015 (Predecessor), the Company capitalized interest costs of $68.2 million and $112.7 million, respectively. The Successor Company's policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 6. OIL AND NATURAL GAS PROPERTIES (Continued)

The ceiling test value of the Company's reserves was calculated based on the following prices:

<table><tr><td></td><td>West Texas Intermediate (per barrel) (1)</td><td>Henry Hub (per MMBtu) (1)</td></tr><tr><td>December 31, 2016</td><td>$ 42.75</td><td>$ 2.481</td></tr><tr><td>December 31, 2015</td><td>50.28</td><td>2.587</td></tr><tr><td>December 31, 2014</td><td>94.99</td><td>4.350</td></tr></table>

(1) Unweighted average of the first day of the 12-months ended spot price, adjusted by lease or field for quality, transportation fees and market differentials.

The Company's net book value of oil and natural gas properties at March 31, June 30 and September 30, 2016 exceeded the ceiling amount. The Company recorded full cost ceiling test impairments before income taxes of $420.9 million ($268.1 million after taxes, before valuation allowance) for the period of September 10, 2016 through September 30, 2016 (Successor) and $754.8 million ($478.2 million after taxes, before valuation allowance) for the six months ended June 30, 2016 (Predecessor). The impairment at September 30, 2016 reflects the differences between the first day of the month average prices for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company's oil and natural gas properties on the fresh-start reporting date of September 9, 2016. The ceiling test impairments at March 31, 2016 and June 30, 2016, were driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. The impairment at March 31, 2016 also reflects the transfer of the remaining unevaluated Utica and TMS properties as discussed further above.

The Predecessor Company's net book value of oil and natural gas properties at March 31, June 30, September 30 and December 31, 2015 exceeded the ceiling amount. The Predecessor Company recorded a full cost ceiling test impairment before income taxes of $2.6 billion ($1.7 billion after taxes, before valuation allowance) for the year ended December 31, 2015. The impairment for the year ended December 31, 2015 (Predecessor) was driven by decreases in the first-day-of-the-month average prices for crude oil used in the ceiling test calculations from $94.99 per barrel at December 31, 2014 to $50.28 per barrel at December 31, 2015.

The Predecessor Company's net book value of oil and natural gas properties at March 31 and December 31, 2014 exceeded the ceiling amount. The Predecessor Company recorded a full cost ceiling test impairment before income taxes of $239.7 million ($151.4 million after taxes) for the year ended December 31, 2014. The impairment for the year ended December 31, 2014 (Predecessor) primarily relates to non-routine transfers of unevaluated properties to the full cost pool, due to the Predecessor Company's shift in drilling, away from the non-strategic areas of the Utica and TMS until economics and return on investment improve, which would include a combination of lower drilling and completion costs and higher commodity prices.

The Company recorded the full cost ceiling test impairments in "Full cost ceiling impairment" in the Company's consolidated statements of operations and in "Accumulated depletion" in the Company's consolidated balance sheets.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 6. OIL AND NATURAL GAS PROPERTIES (Continued)

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, capital spending, and other factors will determine the Company's actual ceiling test calculation and impairment analyses in future periods.

## 7. LONG-TERM DEBT

Long-term debt as of December 31, 2016 (Successor) and 2015 (Predecessor) consisted of the following (in thousands):

<table><tr><td rowspan="2"></td><td colspan="2">Successor</td><td colspan="2">Predecessor</td></tr><tr><td colspan="2">December 31, 2016</td><td colspan="2">December 31, 2015</td></tr><tr><td>Successor senior revolving credit facility</td><td>$ 186,000</td><td></td><td>$ —</td><td></td></tr><tr><td>Predecessor senior revolving credit facility</td><td>—</td><td></td><td>62,000</td><td></td></tr><tr><td>8.625% senior secured second lien notes due 2020(1)</td><td>672,613</td><td></td><td>687,797</td><td></td></tr><tr><td>12.0% senior secured second lien notes due 2022(1)</td><td>106,040</td><td></td><td>111,598</td><td></td></tr><tr><td>13.0% senior secured third lien notes due 2022(3)(8)</td><td>—</td><td></td><td>1,009,585</td><td></td></tr><tr><td>9.25% senior notes due 2022(4)(8)</td><td>—</td><td></td><td>51,887</td><td></td></tr><tr><td>8.875% senior notes due 2021(5)(8)</td><td>—</td><td></td><td>347,671</td><td></td></tr><tr><td>9.75% senior notes due 2020(6)(8)</td><td>—</td><td></td><td>336,470</td><td></td></tr><tr><td>8.0% convertible note due 2020(7)(8)</td><td>—</td><td></td><td>266,629</td><td></td></tr><tr><td></td><td>$ 964,653</td><td></td><td>$ 2,873,637</td><td></td></tr></table>

(1) Amount is net of a $27.4 million unamortized discount at December 31, 2016 (Successor). Amount is net of $12.2 million unamortized debt issuance costs at December 31, 2015 (Predecessor). On February 16, 2017, the Company repurchased approximately 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes with proceeds from the issuance of its new 6.75% senior unsecured notes due 2025. Refer to Note 17, "Subsequent Events," for further details.

(2) Amount is net of a $6.8 million unamortized discount at December 31, 2016 (Successor). Amount is net of $1.2 million unamortized debt issuance costs at December 31, 2015 (Predecessor).

(3) Amount is net of $8.4 million unamortized debt issuance costs at December 31, 2015 (Predecessor).

(4) Amount is net of $0.8 million unamortized debt issuance costs at December 31, 2015 (Predecessor).

(5) Amount is net of a $1.0 million unamortized discount at December 31, 2015 (Predecessor) related to the issuance of the original 2021 Notes. The unamortized premium related to the additional 2021 Notes was approximately $5.5 million at December 31, 2015 (Predecessor). Amount is net of $5.8 million unamortized debt issuance costs at December 31, 2015 (Predecessor).



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

(6) Amount is net of a $1.9 million unamortized discount at December 31, 2015 (Predecessor) related to the issuance of the original 2020 Notes. The unamortized premium related to the additional 2020 Notes was approximately $2.6 million at December 31, 2015 (Predecessor). Amount is net of $4.3 million unamortized debt issuance costs at December 31, 2015 (Predecessor).

(7) Amount is net of a $23.0 million unamortized discount at December 31, 2015 (Predecessor).

(8) These notes were cancelled on September 9, 2016 upon emergence from chapter 11 bankruptcy. Contractual interest expense not accrued or recorded on pre-petition debt as a result of the chapter 11 bankruptcy amounted to $25.2 million for the period from July 27, 2016 to September 9, 2016.

## Successor Senior Revolving Credit Facility

On the Effective Date, the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP facility, discussed below. The Senior Credit Agreement provides for a $1.5 billion senior secured reserve-based revolving credit facility with a current borrowing base of $600.0 million. The maturity date of the Senior Credit Agreement is the earlier of (i) July 28, 2021 and (ii) the 120th day prior to the February 1, 2020 stated maturity date of the Company's 2020 Second Lien Notes (defined below), if such notes have not been refinanced, redeemed or repaid in full on or prior to such 120th day. The first borrowing base redetermination will be on May 1, 2017 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement). Additionally, if the Company has outstanding borrowings or letters of credit or reimbursement obligations in respect of letters of credit and the Consolidated Cash Balance (as defined in the Senior Credit Agreement) exceeds $100.0 million as of the close of business on the most recently ended business day, the Company may also be required to make mandatory prepayments.

Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of the Company's direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) not to exceed 4.75:1.00 initially, determined as of each four fiscal quarter periods and commencing with the fiscal quarter ending September 30, 2016, stepping down to 4.50:1.00 and 4.00:1.00 on September 30, 2017 and March 31, 2019, respectively, and (ii) a Current Ratio (as defined in the Senior Credit



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

Agreement) not to be less than 1.00:1.00, commencing with the fiscal quarter ending December 31, 2016. At December 31, 2016, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

The Senior Credit Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

At December 31, 2016 (Successor), the Company had approximately $186.0 million of indebtedness outstanding, approximately $6.7 million letters of credit outstanding and approximately $407.3 million of borrowing capacity available under the Senior Credit Agreement.

## DIP Facility

In connection with the chapter 11 bankruptcy proceedings, the Predecessor Company entered into a commitment letter pursuant to which the lenders party thereto committed to provide, subject to certain conditions, a $600.0 million debtor-in-possession senior secured, super-priority revolving credit facility (the DIP Facility) and to replace it upon emergence with a $600.0 million senior secured reserve-based revolving credit facility, discussed above. Proceeds from the DIP Facility were used to refinance borrowings under the Predecessor Credit Agreement (defined below). Availability under the DIP Facility was $500.0 million upon interim approval by the Bankruptcy Court, and rose to $600.0 million upon entry of a final order. The DIP Facility was refinanced by the Senior Credit Agreement, upon emergence from chapter 11 bankruptcy. Loans under the DIP Facility bore interest at specified margins over the base rate of 1.75% to 2.75% for ARB-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the utilization of the DIP Facility.

## Predecessor Senior Revolving Credit Facility

On February 8, 2012, the Predecessor Company entered into a senior secured revolving credit agreement (the Predecessor Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. The Predecessor Credit Agreement provided for a $1.5 billion facility with a borrowing base of $700.0 million. Amounts outstanding under the Predecessor Credit Agreement bore interest at specified margins over the base rate of 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% for Eurodollar-based loans. These margins fluctuated based on the utilization of the facility. Proceeds from the DIP Facility were used to refinance borrowings under the Company's Predecessor Credit Agreement.

## 8.625% Senior Secured Second Lien Notes

On May 1, 2015 (Predecessor), the Company issued $700 million aggregate principal amount of its 8.625% second lien senior secured notes due 2020 (the 2020 Second Lien Notes) in a private offering. The 2020 Second Lien Notes were issued at par. The net proceeds from the sale of the 2020 Second Lien Notes were approximately $686.2 million (after deducting offering fees and expenses).

The 2020 Second Lien Notes bear interest at a rate of 8.625% per annum, payable semi-annually on February 1 and August 1 of each year. The 2020 Second Lien Notes will mature on February 1,



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

2020. The 2020 Second Lien Notes are secured by second-priority liens on substantially all of the Company's and its guarantors' assets to the extent such assets secure the Company's Senior Credit Agreement, its 2022 Second Lien Notes (defined below) (the Collateral). Pursuant to the terms of an Intercreditor Agreement, dated May 1, 2015 as amended by those certain Priority Confirmation Jointers, dated September 10, 2015 and December 21, 2015, in connection with the issuance of the Third Lien Notes and the 2022 Second Lien Notes (discussed below), respectively (the Intercreditor Agreement), the security interest in those assets that secure the 2020 Second Lien Notes and the guarantees are contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2020 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness to the extent of the value of such assets. The Collateral does not include any of the assets of the Company's future unrestricted subsidiaries. In accordance with the terms of the Plan, the 2020 Second Lien Notes were unimpaired and reinstated upon the Company's emergence from the chapter 11 bankruptcy.

As discussed in Note 3, "Fresh-start Accounting," on September 9, 2016, the Company adjusted the 2020 Second Lien Notes to fair value of $679.0 million by recording a discount of $21.0 million to be amortized over the remaining life of the 2020 Second Lien Notes, using the effective interest method.

The 2020 Second Lien Notes are governed by an Indenture, dated as of May 1, 2015, by and among the Company, certain subsidiaries of the Company (the Guarantors) and U.S. Bank National Association, as Trustee, (the Trustee), which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2020 Second Lien Notes may declare all outstanding 2020 Second Lien Notes to be due and payable immediately. The 2020 Second Lien Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain future subsidiaries of the Company.

On September 28, 2016 (Successor), the Company, each of its guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2020 Second Lien Note Supplemental Indenture) to the Indenture dated as of May 1, 2015 with respect to the Company's 2020 Second Lien Notes (the 2020 Second Lien Note Indenture). The 2020 Second Lien Note Supplemental Indenture amended the 2020 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2020 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016. The Company paid an aggregate consent fee of approximately $8.6 million to holders of the 2020 Second Lien Notes and recorded an additional discount of approximately $8.6 million. The remaining unamortized discount was $27.4 million at December 31, 2016.

On February 16, 2017 (Successor), the Company paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes pursuant to a tender offer and issued a redemption notice to redeem the remaining 2020 Second Lien



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

Notes. The remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017. The repurchase and redemption of the 2020 Second Lien Notes will be funded with proceeds from the issuance of $850.0 million in new 6.75% senior unsecured notes due 2025. See Note 17, "Subsequent Events," for further details.

## 12.0% Senior Secured Second Lien Notes

On December 21, 2015 (Predecessor), the Company completed the issuance of approximately $112.8 million aggregate principal amount of new 12.0% second lien senior secured notes due 2022 (the 2022 Second Lien Notes) in exchange for approximately $289.6 million principal amount of its then outstanding senior unsecured notes, consisting of $116.6 million principal amount of its 9.75% senior notes due 2020, $137.7 million principal amount of its 8.875% senior notes due 2021 and $35.3 million principal amount of its 9.25% senior notes due 2022. At closing, the Predecessor Company paid all accrued and unpaid interest since the respective interest payment dates of the unsecured notes surrendered in the exchange. The Predecessor Company recorded the issuance of the 2022 Second Lien Notes at par value and also recognized a $174.5 million net gain on the extinguishment of debt, as a $176.7 million gain on the exchanges was partially offset by the write-down of $2.2 million associated with related issuance costs and discounts and premiums for the respective notes. The net gain was recorded in "Gain (loss) on extinguishment of debt" in the consolidated statements of operations.

Interest on the 2022 Second Lien Notes accrues at a rate of 12.0% per annum, payable semi-annually on February 15 and August 15 of each year. The 2022 Second Lien Notes will mature on February 15, 2022. The 2022 Second Lien Notes are secured by second-priority liens on the Collateral. Pursuant to the terms of the Intercreditor Agreement, dated December 21, 2015, the security interest in the Collateral securing the 2022 Second Lien Notes and the guarantees are contractually equal with the liens that secure the 2020 Second Lien Notes and contractually subordinated to liens that secure the Company's Senior Credit Agreement and certain other permitted indebtedness. Consequently, the 2022 Second Lien Notes and the guarantees are effectively subordinated to the Senior Credit Agreement and such other indebtedness and effectively equal to the 2020 Second Lien Notes, in each case to the extent of the value of the Collateral. In accordance with the terms of the Plan, the 2022 Second Lien Notes were unimpaired and reinstated upon the Company's emergence from chapter 11 bankruptcy.

As discussed in Note 3, "Fresh-start Accounting," on September 9, 2016, the Company adjusted the 2022 Second Lien Notes to fair value of $107.2 million by recording a discount of $5.7 million to be amortized over the remaining life of the 2022 Second Lien Notes, using the effective interest method.

On September 28, 2016 (Successor), the Company, each of its guarantors and U.S. Bank National Association, as trustee, entered into a supplemental indenture (the 2022 Second Lien Note Supplemental Indenture) to the Indenture dated as of December 21, 2015 with respect to the Company's 2022 Second Lien Notes (the 2022 Second Lien Note Indenture). The 2022 Second Lien Note Supplemental Indenture amended the 2022 Second Lien Note Indenture to modify the incurrence of indebtedness, lien and restricted payments covenants. The 2022 Second Lien Note Supplemental Indenture became operative upon the consummation of the consent solicitation on September 30, 2016. The Company paid an aggregate consent fee of approximately $1.4 million to holders of the 2022 Second Lien Notes and recorded an additional discount of approximately $1.4 million. The remaining unamortized discount was $6.8 million at December 31, 2016.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

At any time prior to August 15, 2018, the Company may redeem the 2022 Second Lien Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The 2022 Second Lien Notes will be redeemable, in whole or in part, on or after August 15, 2018 at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest:

<table><tr><td>Year</td><td>Percentage</td></tr><tr><td>2018</td><td>112.000</td></tr><tr><td>2019</td><td>106.000</td></tr><tr><td>2020 and thereafter</td><td>100.000</td></tr></table>

Additionally, the Company may redeem up to 35% of the 2022 Second Lien Notes on or prior to August 15, 2018 for a redemption price of 112,000% of the principal amount thereof, plus accrued and unpaid interest, utilizing net cash proceeds from certain equity offerings. In addition, upon a change of control of the Company, holders of the 2022 Second Lien Notes will have the right to require the Company to repurchase all or any part of their 2022 Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount of the 2022 Second Lien Notes repurchased, plus any accrued and unpaid interest.

The 2022 Second Lien Notes were issued in accordance with exemptions from the registration requirements of the Securities Act of 1933, as amended afforded by Rule 144A and Regulation S under the Securities Act.

## 13.0% Senior Secured Third Lien Notes

On September 10, 2015, the Predecessor Company issued approximately $1.02 billion aggregate principal amount of new 13.0% senior secured third lien notes due 2022 (the Third Lien Notes) in a private placement in exchange for approximately $497.2 million principal amount of its then outstanding 9.75% senior notes due 2020, $774.7 million principal amount of its then outstanding 8.875% senior notes due 2021 and $294.4 million principal amount of its then outstanding 9.25% senior notes due 2022 in privately negotiated transactions with certain holders of its senior unsecured notes. The Predecessor Company recorded the issuance of the Third Lien Notes at par and also recognized a $535.1 million net gain on the extinguishment of debt, as a $548.2 million gain on the exchanges was partially offset by the write-down of $13.1 million associated with related issuance costs and discounts and premiums for the respective notes. The net gain was recorded in "Gain (loss) on extinguishment of debt" in the consolidated statements of operations for the three months ended September 30, 2015 (Predecessor).

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Third Lien Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

## 9.25% Senior Notes

On August 13, 2013, the Predecessor Company issued at par $400.0 million aggregate principal amount of 9.25% senior notes due 2022 (the 2022 Notes). The net proceeds from the offering were approximately $392.1 million (after deducting offering fees and expenses). During the first quarter of



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

2016, the Predecessor Company repurchased $15.5 million principal amount of 2022 Notes for cash at prevailing market prices at the time of the transactions and recognized an $11.1 million net gain on the extinguishment of debt.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2022 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

## 8.875% Senior Notes

On November 6, 2012, the Predecessor Company issued $750.0 million aggregate principal amount of its 8.875% senior notes due 2021 (the 2021 Notes), at a price to the initial purchasers of 99.247% of par. The net proceeds from the offering were approximately $725.6 million (after deducting offering fees and expenses). On January 14, 2013, the Predecessor Company issued an additional $600.0 million aggregate principal amount of the 2021 Notes at a price to the initial purchasers of 105% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after offering fees and expenses).

During the first quarter of 2016, the Predecessor Company repurchased $51.8 million principal amount of the 2021 Notes for cash at prevailing market prices at the time of the transactions and recognized a $47.5 million net gain on the extinguishment of debt.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2021 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

## 9.75% Senior Notes

On July 16, 2012, the Predecessor Company issued $750.0 million aggregate principal amount of 9.75% senior notes due 2020 issued at 98.646% of par (the 2020 Notes). The net proceeds from the offering were approximately $723.1 million (after deducting offering fees and expenses). On December 19, 2013, the Predecessor Company issued an additional $400.0 million aggregate principal amount of the 2020 Notes at a price to the initial purchasers of 102.750% of par. The net proceeds from the sale of the additional 2020 Notes were approximately $406.3 million (after deducting offering fees and expenses).

During the first quarter of 2016, the Predecessor Company repurchased $24.5 million principal amount of the 2020 Notes for cash at prevailing market prices at the time of the transactions and recognized a $22.8 million net gain on the extinguishment of debt.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the 2020 Notes were cancelled. Refer to Note 2, "Reorganization," for further details.

## 8.0% Convertible Note

On February 8, 2012, the Predecessor Company issued to HALRES, LLC (HALRES), a note in the principal amount of $275.0 million due 2017 (the Convertible Note) together with five year warrants (February 2012 Warrants) for an aggregate purchase price of $275.0 million. On March 9, 2015, the Predecessor Company entered into an amendment (the HALRES Note Amendment) to its Convertible Note, which extended the maturity date of the Convertible Note by three years and adjusted the conversion price of the Convertible Note from $22.50 per share to $12.20 per share. The



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

Predecessor Company accounted for the HALRES Note Amendment as a debt extinguishment and recorded a net gain of $7.3 million in "Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants" in the consolidated statements of operations for the year ended December 31, 2015 (Predecessor).

On September 9, 2016, and upon emergence from chapter 11 bankruptcy, the Convertible Note and February 2012 Warrants were cancelled. Refer to Note 2, "Reorganization," for further details.

## Debt Maturities

Aggregate maturities required on long-term debt at December 31, 2016 (Successor) due in future years are as follows (in thousands, excluding discounts and debt issuance costs):



(1) On February 16, 2017 (Successor), the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025. A portion of the net proceeds from the issuance of the new 6.75% senior unsecured notes were used to fund the repurchase of the validly tendered 2020 Second Lien Notes. These transactions are not included in the table above. See Note 17, "Subsequent Events," for more details.

## Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. For the period from January 1, 2016 through September 9, 2016, the Predecessor Company expensed $7.9 million of debt issuance costs in conjunction with debt repurchases, decreases in the borrowing base under the Predecessor Credit Agreement, and refinancing of the Predecessor Credit Agreement. At December 31, 2015 (Predecessor), the Company had approximately $40.3 million of debt issuance costs capitalized related to its Predecessor senior secured and unsecured debt. As part of the Company's reorganization, all debt issuance costs related to the Company's Predecessor debt were extinguished. The debt issuance costs for the Company's Predecessor Credit Agreement were presented in "Debt issuance costs, net", and the debt issuance costs for the Company's senior unsecured debt were presented in "Long-term debt, net" within total liabilities on the consolidated balance sheet at December 31, 2015 (Predecessor).

## 8. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS (Continued)

its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of December 31, 2016 (Successor) and 2015 (Predecessor) (in thousands):

<table><tr><td rowspan="3"></td><td colspan="5">Successor</td></tr><tr><td colspan="5">December 31, 2016</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Receivables from derivative contracts</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities from derivative contracts</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

Derivative contracts listed above as Level 2 include collars, swaps and swaptions that are carried at fair value. The Company records the net change in the fair value of these positions in "Net gain (loss) on derivative contracts" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS (Continued)

changes in the forward curves. See Note 9, "Derivative and Hedging Activities," for additional discussion of derivatives.

Derivative contracts listed above as Level 3 include extendable collars that are carried at fair value. The significant unobservable inputs for these Level 3 contracts include unpublished forward strip prices and market volatilities. The following table sets forth a reconciliation of changes in the fair value of the Company's extendable collar contracts classified as Level 3 in the fair value hierarchy (in thousands):

<table><tr><td rowspan="2"></td><td colspan="3">Significant Unobservable Inputs (Level 3)</td></tr><tr><td>Successor December 31, 2016</td><td>Predecessor December 31, 2015</td><td></td></tr><tr><td>Beginning Balance</td><td>$ (185)</td><td>$ (1,319)</td><td></td></tr><tr><td>Net gain (loss) on derivative contracts</td><td>185</td><td>1,134</td><td></td></tr><tr><td>Ending Balance</td><td>$ —</td><td>$ (185)</td><td></td></tr><tr><td></td><td>Successor</td><td>Predecessor</td><td></td></tr><tr><td></td><td>Period from September 10, 2016 through December 31, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td><td>December 31, 2015</td></tr><tr><td>Change in unrealized gains (losses) included in earnings related to derivatives still held at December 31, 2016 (Successor), September 9, 2016 (Predecessor) and December 31, 2015 (Predecessor)</td><td>$ —</td><td>$ 137</td><td>$ (185)</td></tr></table>

The Company's derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company's fixed interest rate, long-term debt instruments as of December 31, 2016.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS (Continued)

(Successor) and 2015 (Predecessor) (excluding discounts, premiums and debt issuance costs) (in thousands):

<table><tr><td rowspan="3">Debt</td><td colspan="2">Successor</td><td colspan="2">Predecessor</td></tr><tr><td colspan="2">December 31, 2016</td><td colspan="2">December 31, 2015</td></tr><tr><td>Principal Amount</td><td>Estimated Fair Value</td><td>Principal Amount</td><td>Estimated Fair Value</td></tr><tr><td>8.625% senior secured second lien notes</td><td>700,000</td><td>$ 733,250</td><td>$ 700,000</td><td>$ 479,500</td></tr><tr><td>12.0% senior secured second lien notes</td><td>112,826</td><td>123,827</td><td>112,826</td><td>77,286</td></tr><tr><td>13.0% senior secured third lien notes \( ^{(1)} \)</td><td>—</td><td>—</td><td>1,017,970</td><td>333,385</td></tr><tr><td>9.25% senior notes \( ^{(1)} \)</td><td>—</td><td>—</td><td>52,694</td><td>14,422</td></tr><tr><td>8.875% senior notes \( ^{(1)} \)</td><td>—</td><td>—</td><td>348,944</td><td>95,506</td></tr><tr><td>9.75% senior notes \( ^{(1)} \)</td><td>—</td><td>—</td><td>340,035</td><td>93,068</td></tr><tr><td>8.0% convertible note \( ^{(1)} \)</td><td>—</td><td>—</td><td>289,669</td><td>87,393</td></tr><tr><td></td><td>$ 812,826</td><td>$ 857,077</td><td>$ 2,862,138</td><td>$ 1,180,560</td></tr></table>

(1) These notes were cancelled on September 9, 2016 upon emergence from chapter 11 bankruptcy.

The fair value of the Company's fixed interest debt instruments was calculated using Level 2 criteria at December 31, 2016 (Successor) and 2015 (Predecessor). The fair value of the Company's senior notes is based on quoted market prices from trades of such debt. The fair value of the Company's convertible note was based on published market prices and risk-free rates.

On September 9, 2016, the Company emerged from chapter 11 bankruptcy and adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company's assets and liabilities were recorded at their fair values as of the fresh-start reporting date, September 9, 2016. See Note 3, "Fresh-start Accounting," for a detailed discussion of the fair value approaches used by the Company.

During the three months ended March 31, 2016 and the year ended December 31, 2014, the Predecessor Company recorded non-cash impairment charges of $28.1 million and $35.6 million, respectively, related to its gas gathering systems. See Note 1, "Summary of Significant Events and Accounting Policies," for a discussion of the valuation approach used and the classification of the estimate within the fair value hierarchy.

As discussed in Note 7, "Long-term Debt," and in Note 13, "Stockholders' Equity," on May 6, 2015, the HALRES Note Amendment and the Warrant Amendment became effective. The fair value estimates for the Convertible Note and the February 2012 Warrants include the use of observable inputs such as the Predecessor Company's stock price, expected volatility, and credit spread and the risk-free rate. The use of these observable inputs results in the fair value estimates being classified as Level 2.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company's initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 10, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. When derivative contracts are available at terms (or prices) acceptable to the Company, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company's hedge policies and objectives may change significantly as its operational profile changes and/or commodities prices change. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of its derivative contracts as they are secured under the Company's Senior Credit Agreement or are uncollateralized trades.

The Company's crude oil and natural gas derivative positions at any point in time may consist of swaps, swaptions, costless put/call "collars," extendable costless collars and deferred put options. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. Swaptions are swap contracts that may be extended annually at the option of the counterparty on a designated date. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Extendable collars are costless put/call contracts that may be extended annually at the option of the counterparty on a designated date. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

At December 31, 2016 (Successor), the Company had 22 open commodity derivative contracts summarized in the following tables: two natural gas collar arrangements and 20 crude oil collar arrangements.

At December 31, 2015 (Predecessor), the Company had 36 open commodity derivative contracts summarized in the following tables: one natural gas collar arrangement, 16 crude oil collar arrangements, 13 crude oil swaps, five crude oil swaptions and one crude oil extendable collar.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the consolidated balance sheets as assets or liabilities. The following table



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2016 (Successor) and 2015 (Predecessor) (in thousands):

<table><tr><td rowspan="2"></td><td colspan="3">Asset derivative contracts</td><td colspan="3">Liability derivative contracts</td></tr><tr><td colspan="2">Successor</td><td colspan="2">Predecessor</td><td>Successor</td><td>Predecessor</td></tr><tr><td>Derivatives not designated as hedging contracts under ASC 815</td><td>Balance sheet location</td><td>December 31, 2016</td><td>December 31, 2015</td><td>Balance sheet location</td><td>December 31, 2016</td><td>December 31. 2015</td></tr><tr><td>Commodity contracts</td><td>Current assets—receivables from derivative contracts</td><td>$ 5,923</td><td>$ 348,861</td><td>Current liabilities—liabilities from derivative contracts</td><td>$ (16,434)</td><td>$ —</td></tr><tr><td>Commodity contracts</td><td>Other noncurrent assets—receivables from derivative contracts</td><td>—</td><td>16,614</td><td>Other noncurrent liabilities—liabilities from derivative contracts</td><td>(486)</td><td>(290)</td></tr><tr><td colspan="3">Total derivatives not designated as hedging contracts under ASC 815</td><td>$ 5,923</td><td>$ 365,475</td><td>$ (16,920)</td><td>$ (290)</td></tr></table>

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's consolidated statements of operations (in thousands):

<table><tr><td rowspan="2"></td><td colspan="6">Amount of gain or (loss) recognized in income on derivative contracts for the</td></tr><tr><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="4">Predecessor</td></tr><tr><td>Derivatives not designated as hedging contracts under ASC 815</td><td>Location of gain or (loss) recognized in income on derivative contracts</td><td>Successor Period from January 1, 2016 through September 9, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Commodity contracts:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unrealized gain (loss) on commodity contracts</td><td>Other income (expenses)—net gain (loss) on derivative contracts</td><td>$ (112,449)</td><td>$ (263,732)</td><td>$ (129,282)</td><td>$506,526</td><td></td></tr><tr><td>Realized gain (loss) on commodity contracts</td><td>Other income (expenses)—net gain (loss) on derivative contracts</td><td>84,709</td><td>245,734</td><td>439,546</td><td>12,430</td><td></td></tr><tr><td>Total net gain (loss) on derivative contracts</td><td></td><td>$ (27,740)</td><td>$ (17,998)</td><td>$ 310,264</td><td>$518,956</td><td></td></tr></table>

At December 31, 2016 (Successor) and 2015 (Predecessor), the Company had the following open crude oil and natural gas derivative contracts:

<table><tr><td rowspan="3">Period</td><td rowspan="3">Instrument</td><td rowspan="3">Commodity</td><td colspan="5">Successor</td></tr><tr><td colspan="4">December 31, 2016</td><td></td></tr><tr><td>Volume in Mmbtu/s/ Bbl&#x27;s</td><td colspan="2">Floors</td><td colspan="2">Ceilings</td></tr><tr><td>January 2017 - December 2017</td><td>Collars</td><td>Natural Gas</td><td>3,650,000</td><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Weighted Average Price</td></tr><tr><td>January 2017 - December 2017</td><td>Collars</td><td>Crude Oil</td><td>6,843,750</td><td>47.00 - 60.00</td><td>51.39</td><td>52.00 - 76.84</td><td>58.75</td></tr><tr><td>January 2018 - December 2018(1)</td><td>Collars</td><td>Crude Oil</td><td>730,000</td><td>53.00</td><td>53.00</td><td>58.00</td><td>58.00</td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

<table><tr><td rowspan="3">Period</td><td rowspan="3">Instrument</td><td rowspan="3">Commodity</td><td colspan="6">Predecessor</td></tr><tr><td colspan="4">December 31, 2015</td><td colspan="2">Ceilings</td></tr><tr><td>Volume in Mmbtu&#x27;s/ Bbl&#x27;s</td><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Weighted Average Price</td><td></td></tr><tr><td>January 2016 - June 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>Collars</td><td>Crude Oil</td><td>182,000</td><td>$90.00</td><td>$ 90.00</td><td>$96.85</td><td>$ 96.85</td><td></td></tr><tr><td>January 2016 - December 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>Collars</td><td>Natural Gas</td><td>732,000</td><td>4.00</td><td>4.00</td><td>4.22</td><td>4.22</td><td></td></tr><tr><td>January 2016 - December 2016(2)</td><td></td><td></td><td></td><td>60.00 - 4,392,000</td><td>90.00</td><td>71.91</td><td>64.00 - 95.10</td><td>77.71</td></tr><tr><td>January 2016 - December 2016(3)</td><td></td><td></td><td></td><td></td><td>62.00 - 91.73</td><td>85.43</td><td></td><td></td></tr><tr><td></td><td>Swaps</td><td>Crude Oil</td><td>4,758,000</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>January 2017 - December 2017</td><td></td><td></td><td></td><td>50.00 - 1,368,750</td><td>60.00</td><td>57.33</td><td>70.00 - 76.84</td><td>74.16</td></tr></table>

(1) Subsequent to December 31, 2016, the Company entered into crude oil collars at floors of $50.00 per Bbl and ceilings of $60.00 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2018, which are not included in the table above.

(2) Includes an outstanding crude oil collar which may be extended by the counterparty at a floor of $60.00 per Bbl and a ceiling of $75.00 per Bbl for a total of 365,000 Bbls for the year ended December 31, 2017.

(3) Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.25 per Bbl for a total of 730,000 Bbls for the year ended December 31, 2017. Also includes certain outstanding crude oil swaps which may be extended by the counterparty at a price of $88.00 per Bbl totaling 912,500 Bbls for the year ended December 31, 2017. Includes an outstanding crude oil swap which may be extended by the counterparty at a price of $88.87 per Bbl totaling 547,500 Bbls for the year ended December 31, 2017.

The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company's derivative contracts at December 31, 2016 (Successor) and 2015 (Predecessor) (in thousands):

<table><tr><td rowspan="2">Offsetting of Derivative Assets and Liabilities</td><td colspan="2">Derivative Assets</td><td colspan="2">Derivative Liabilities</td></tr><tr><td>Successor December 31, 2016</td><td>Predecessor December 31, 2015</td><td>Successor December 31, 2016</td><td>Predecessor December 31,2015</td></tr><tr><td>Gross amounts presented in the consolidated balance sheet</td><td>$ 5,923</td><td>$ 365,475</td><td>$ (16,920)</td><td>$ (290)</td></tr><tr><td>Amounts not offset in the consolidated balance sheet</td><td>(5,283)</td><td>(53)</td><td>5,075</td><td>52</td></tr><tr><td>Net amount</td><td>$ 640</td><td>$ 365,422</td><td>$ (11,845)</td><td>$ (238)</td></tr></table>

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

## 10. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (ARO) when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 10. ASSET RETIREMENT OBLIGATIONS (Continued)

For gas gathering systems and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in "Oil and natural gas properties" or "Other operating property and equipment" during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in "Depletion, depreciation and accretion" expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis or straight-line basis.

The Company recorded the following activity related to its ARO liability (in thousands, inclusive of the current portion) (in thousands):

<table><tr><td>Liability for asset retirement obligation as of December 31, 2014 (Predecessor)</td><td>$ 38,477</td></tr><tr><td>Liabilities settled and divested</td><td>(324)</td></tr><tr><td>Additions</td><td>3,209</td></tr><tr><td>Accretion expense</td><td>1,797</td></tr><tr><td>Revisions in estimated cash flows</td><td>3,857</td></tr><tr><td>Liability for asset retirement obligations as of December 31, 2015 (Predecessor)</td><td>$ 47,016</td></tr><tr><td>Liabilities settled and divested</td><td>(180)</td></tr><tr><td>Additions</td><td>1,044</td></tr><tr><td>Acquisitions</td><td>75</td></tr><tr><td>Accretion expense</td><td>1,414</td></tr><tr><td>Liability for asset retirement obligations as of September 9, 2016 (Predecessor)</td><td>$ 49,369</td></tr><tr><td>Fair value fresh-start adjustment</td><td>$ (16,883)</td></tr><tr><td>Liability for asset retirement obligations as of September 9, 2016 (Successor)</td><td>$ 32,486</td></tr><tr><td>Liabilities settled and divested(1)</td><td>(1,211)</td></tr><tr><td>Additions</td><td>513</td></tr><tr><td>Accretion expense</td><td>587</td></tr><tr><td>Liability for asset retirement obligations as of December 31, 2016 (Successor)</td><td>$ 32,375</td></tr></table>

(1) See Note 5, "Divestitures," for additional information on the Company's divestiture activities.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 11. COMMITMENTS AND CONTINGENCIES

## Commitments

The Company leases corporate office space in Houston, Texas and Denver, Colorado as well as a number of other field office locations. In addition, the Company has lease commitments for certain equipment under long-term operating lease agreements. The office and equipment operating lease agreements expire on various dates through 2024. Rent expense was approximately $1.4 million for the period of September 10, 2016 through December 31, 2016 (Successor) and $5.9 million for the period of January 1, 2016 through September 9, 2016 (Predecessor). Rent expense was approximately $8.6 million and $8.1 million for the years ended December 31, 2015 and 2014 (Predecessor), respectively. In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. Approximate future minimum lease payments for subsequent annual periods for all non-cancelable operating leases as of December 31, 2016 (Successor) are as follows (in thousands):



As of December 31, 2016 (Successor), the Company has the following active drilling rig commitments (in thousands):



As of December 31, 2016 (Successor), termination of the Company's active drilling rig commitments would require early termination penalties of $12.5 million, which would be in lieu of paying the remaining active drilling rig commitments of $25.0 million.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 11. COMMITMENTS AND CONTINGENCIES (Continued)

In past years, with the sustained decline in crude oil prices, the Company stacked certain drilling rigs and amended other previous drilling rig contracts. In the future, the Company expects to incur stacking charges/early termination fees on certain drilling rig commitments as follows (in thousands):



The Company has entered into an agreement with a private operator for the right to purchase up to 15,040 net acres located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations. The Ward County Assets are divided into two tracts: the Southern Tract, comprising 6,720 net acres, and the Northern Tract, comprising 8,320 net acres, with separate options for each tract. Pursuant to the terms of the agreement, the Company paid $5.0 million and is drilling a commitment well on the Southern Tract. The Company has until June 15, 2017 to exercise the option on either the Southern Tract acreage or on all 15,040 net acres, in each case for $11,000 per acre. If the Company initially elects only to exercise its option on the Southern Tract, the Company would need to pay $5.0 million on or before June 15, 2017 and drill a commitment well on the Northern Tract by September 1, 2017 to earn an option to acquire the Northern Tract acreage for $11,000 per acre by December 31, 2017. This option purchase not included in the tables above.

The Company has entered into various long-term gathering, transportation and sales contracts in its Bakken/Three Forks formations in North Dakota which are not included in the tables above. As of December 31, 2016 (Successor), the Company had in place eight long-term crude oil contracts and five long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its Bakken/Three Forks production for periods ranging from one to ten years from the date of first production. The Company believes that there are sufficient available reserves and supplies in the Bakken/Three Forks formations to meet its commitments, as the proved reserves from this area represent approximately 76% of its total proved reserves. Historically, the Company has been able to meet its delivery commitments.

## Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company's management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company's consolidated operating results, financial position or cash flows.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. MEZZANINE EQUITY

On June 16, 2014 (Predecessor), funds and accounts managed by affiliates of Apollo contributed $150 million in cash to HK TMS, a Delaware limited liability company, which was then wholly owned by the Company and held all of the Company's acreage in the TMS formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. At the closing, the Predecessor Company also contributed $50 million in cash to HK TMS. Holders of the HK TMS preferred shares were to receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS' option to pay such dividends "in-kind" through the issuance of additional preferred shares. The preferred shares were expected to be automatically redeemed and cancelled when the holders receive cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. On September 30, 2016, certain wholly-owned subsidiaries of the Successor Company executed an Assignment and Assumption Agreement with an affiliate of Apollo pursuant to which 100% of the Membership Interests in HK TMS were assigned to Apollo. In exchange for the assignment, Apollo assumed all obligations relating to such Membership Interests. See Note 5, "Divestitures," for further information regarding the HK TMS Divestiture.

On June 1, 2015 (Predecessor), HK TMS and Apollo entered into an amendment to the original agreement (the HK TMS Amendment) which, among other things, i) committed HK TMS to drill a minimum of 6.5 net wells in each of the five consecutive twelve month periods beginning December 31, 2015 and ii) allowed for the redemption of preferred shares at the Redemption Price between March 1, 2016 and June 30, 2016 at the election of Apollo to the extent there was available cash above the minimum cash balance, which is discussed further below. For any commitment period in which HK TMS did not meet its drilling obligation, HK TMS would have been required to use available cash, above the minimum cash balance, to redeem preferred shares at the Redemption Price.

The preferred shares were classified as "Redeemable noncontrolling interest" and included in "Mezzanine equity" between total liabilities and stockholders' equity on the consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares were considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value. The accretion was presented as a deemed dividend and recorded in "Redeemable noncontrolling interest" on the consolidated balance sheets and within "Preferred dividends and accretion on redeemable noncontrolling interest" on the consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in mezzanine equity was recognized as charges against retained earnings and reduced income available to common shareholders in the calculation of earnings per share.

HK TMS was required to maintain a minimum cash balance equal to two quarterly dividend payments, of approximately $3.5 million each, plus $10.0 million, which was presented on the consolidated balance sheets in "Restricted cash" at December 31, 2015 (Predecessor).

In March 2015 (Predecessor), Apollo delivered a withdrawal notice to HK TMS indicating their election not to acquire additional preferred shares, referred to as the Tranche Rights, in HK TMS (the Withdrawal Notice). Upon issuance of the Withdrawal Notice, HK TMS incurred a fee escalating from $2.50 per share to $20.00 per share for the next eight full fiscal quarters for any preferred shares then outstanding, which began in the quarter ended June 30, 2015 (the Withdrawal Exit Fee). The Withdrawal Exit Fee would have been payable upon redemption of the preferred shares and was



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. MEZZANINE EQUITY (Continued)

recorded at fair value within "Other noncurrent liabilities" on the consolidated balance sheets at December 31, 2015 (Predecessor).

For purposes of estimating the fair values of the original and amended transaction components, an income approach was used that estimated fair value based on the anticipated cash flows associated with the Company's proved reserves, discounted using a weighted average cost of capital rate. The estimation of the fair value of these components includes the use of unobservable inputs, such as estimates of proved reserves, the weighted average cost of capital (discount rate), estimated future revenues, and estimated future capital and operating costs. The use of these unobservable inputs results in the fair value estimates being classified as Level 3. Although the Company believes the assumptions and estimates used in the fair value calculation of the original and amended transaction components are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating the fair value of the original and amended transaction components are inherently uncertain and require management judgment.

The following table sets forth a reconciliation of the changes in fair value of the Tranche Rights and embedded derivative classified as Level 3 in the fair value hierarchy (in thousands):

<table><tr><td></td><td>Tranche rights</td><td>Embedded derivative</td></tr><tr><td>Balances at December 31, 2014 (Predecessor)</td><td></td><td></td></tr><tr><td></td><td>$ (2,634)</td><td>$ 5,963</td></tr><tr><td>Change in fair value</td><td></td><td></td></tr><tr><td></td><td>2,634</td><td>137</td></tr><tr><td>Balances at December 31, 2015 (Predecessor)</td><td></td><td></td></tr><tr><td></td><td>—</td><td>6,100</td></tr><tr><td>Change in fair value</td><td></td><td></td></tr><tr><td></td><td>—</td><td>(5,734)</td></tr><tr><td>Balance at September 9, 2016 (Predecessor)</td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ 366</td></tr><tr><td>Fair value fresh-start adjustment</td><td></td><td></td></tr><tr><td></td><td>—</td><td>(366)</td></tr><tr><td>Balance at September 9, 2016 (Successor) and at December 31, 2016 (Successor)</td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ —</td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. MEZZANINE EQUITY (Continued)

The Company recorded the following activity related to the preferred shares in "Mezzanine equity" on the consolidated balance sheets for the years ended December 31, 2016 (Successor) and 2015 (Predecessor) (in thousands, except share amounts):

<table><tr><td rowspan="2"></td><td colspan="3">Redeemable noncontrolling interest</td></tr><tr><td>Shares</td><td>Amount</td><td></td></tr><tr><td>Balances at December 31, 2014 (Predecessor)</td><td>153,025</td><td>$ 117,166</td><td></td></tr><tr><td>Dividends paid in-kind</td><td></td><td></td><td></td></tr><tr><td></td><td>12,614</td><td>12,614</td><td></td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td>—</td><td>53,561</td><td></td></tr><tr><td>Deemed dividend for change in fair value due to the HK TMS Amendment</td><td>—</td><td>645</td><td></td></tr><tr><td>Balances at December 31, 2015 (Predecessor)</td><td></td><td></td><td></td></tr><tr><td></td><td>165,639</td><td>$ 183,986</td><td></td></tr><tr><td>Dividends paid in-kind</td><td></td><td></td><td></td></tr><tr><td></td><td>9,329</td><td>9,329</td><td></td></tr><tr><td>Accretion of redeemable noncontrolling interest</td><td>—</td><td>26,576</td><td></td></tr><tr><td>Balances at September 9, 2016 (Predecessor)</td><td></td><td></td><td></td></tr><tr><td></td><td>174,968</td><td>$ 219,891</td><td></td></tr><tr><td>Fair value fresh-start adjustment</td><td>—</td><td>$ (178,821)</td><td></td></tr><tr><td>Balances at September 9, 2016 (Successor)</td><td></td><td></td><td></td></tr><tr><td></td><td>174,968</td><td>$ 41,070</td><td></td></tr><tr><td>Dividends paid in-kind</td><td></td><td></td><td></td></tr><tr><td></td><td>791</td><td>791</td><td></td></tr><tr><td>HK TMS Divestiture(l)</td><td></td><td></td><td></td></tr><tr><td></td><td>(175,759)</td><td>(41,861)</td><td></td></tr><tr><td>Balance at December 31, 2016 (Successor)</td><td>—</td><td>$ —</td><td></td></tr></table>

(1) See Note 5, "Divestitures," for additional information on the HK TMS Divestiture.

For the period of September 10, 2016 through September 30, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor), HK TMS issued 791 and 9,329 additional preferred shares to Apollo for dividends paid-in-kind, respectively. For the year ended December 31, 2015 (Predecessor), HK TMS issued 12,614 additional preferred shares to Apollo for dividends paid in-kind. For the year ended December 31, 2014 (Predecessor), HK TMS paid approximately $3.5 million in cash dividends and issued 3,025 additional preferred shares for dividends paid-in-kind. These dividends were presented within "Preferred dividends and accretion on redeemable noncontrolling interest" on the consolidated statements of operations. Upon the election of in-kind dividends, HK TMS was required to pay a fee of $5.00 per preferred share then outstanding (PIK exit fee). Such fees would have been due upon redemption of the preferred shares. For the years ended December 31 2015 and 2014 (Predecessor), HK TMS incurred PIK exit fees totaling $3.1 million and $0.8 million, respectively, which were recorded at fair value within "Other noncurrent liabilities" on the consolidated balance sheets.

HK TMS was not included in the chapter 11 bankruptcy filings or the Restructuring Support Agreement discussed in Note 2, "Reorganization." On September 30, 2016, Apollo acquired one hundred percent of the common shares of HK TMS and assumed all obligations relating to the Membership Interests. For additional information regarding the divestiture see Note 5, "Divestitures."



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY

## Common Stock

On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of common stock in total to the Predecessor Company's existing common stockholders, Third Lien Noteholders, Unsecured Noteholders, and the Convertible Noteholder. Refer to Note 2, "Reorganization," for further details.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for (i) the total number of shares of all classes of capital stock that the Successor Company has the authority to issue is 1,001,000,000 of which 1,000,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share, (ii) a classified board structure, (iii) the right of removal of directors with or without cause by stockholders, and (iv) a restriction on the Successor Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code.

During the second quarter of 2015, the Predecessor Company entered into several exchange agreements with holders of the Predecessor Company's senior unsecured notes in which they agreed to exchange an aggregate $258.0 million principal amount of their senior notes for approximately 29.0 million shares of the Predecessor Company's common stock. The Predecessor Company recorded the issuance of common shares at fair value on the various dates the debt for equity exchanges occurred.

On March 18, 2015, the Predecessor Company entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with BMO Capital Markets Corp., Jefferies LLC and MLV & Co. LLC (collectively, the Managers). Pursuant to the terms of the Equity Distribution Agreement, the Predecessor Company sold, by means of ordinary brokers' transactions through the facilities of the NYSE at market prices, a total of approximately 1.9 million shares of the Predecessor Company's common stock for net proceeds of approximately $15.0 million, after deducting offering expenses. The shares sold were registered under the Securities Act pursuant to a Registration Statement on Form S-3 (No. 333-188640), which was filed with the SEC and became effective March 13, 2015. The Predecessor Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Predecessor Credit Agreement and for general corporate purposes.

On May 22, 2014, upon stockholder approval, the Predecessor Company filed a Certificate of Amendment of the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to increase its authorized common stock by approximately 670.0 million shares for a total of 1.34 billion authorized shares of common stock.

## 5.75% Series A Convertible Perpetual Preferred Stock

On June 18, 2013, the Predecessor Company completed its offering of 345,000 shares of its Predecessor 5.75% Series A Convertible Perpetual Preferred Stock (the Predecessor Series A Preferred Stock) at a public offering price of $1,000 per share (the Liquidation Preference). The Predecessor Company filed a Certificate of Designations, Preferences, Rights and Limitations of 5.75% Series A Convertible Preferred Stock on June 17, 2013 (the Series A Designation). The net proceeds to the Predecessor Company from the offering of the Predecessor Series A Preferred Stock were



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

approximately $335.2 million, after deducting the underwriting discount and offering expenses. The Predecessor Company used the net proceeds from the offering to repay a portion of the then outstanding borrowings under its Predecessor Credit Agreement.

Holders of the Predecessor Series A Preferred Stock were entitled to receive, when, as and if declared by the Predecessor Company's board of directors, cumulative dividends at the rate of 5.75% per annum (the dividend rate) on the Liquidation Preference per share of the Predecessor Series A Preferred Stock, payable quarterly in arrears on each dividend payment date. Dividends were paid in cash or, where freely transferable by any non-affiliate recipient thereof, in common stock of the Predecessor Company or a combination thereof, and were payable on March 1, June 1, September 1 and December 1 of each year and commenced on September 1, 2013. In January 2016, the Predecessor Company announced that quarterly dividends on the Predecessor Series A Preferred Stock were suspended due to the weakened market conditions as a result of low commodity prices. During the years ended December 31, 2015 and 2014 (Predecessor), the Company incurred cumulative, declared dividends of $18.0 million by paying $8.2 million in cash and issuing approximately 1.4 million shares of common stock and $19.8 million by paying $5.0 million in cash and issuing approximately 0.7 million shares of common stock, respectively, reflected as cash and non-cash dividends. As of September 9, 2016 (Predecessor) and December 31, 2015 (Predecessor), cumulative, undeclared dividends on the Predecessor Series A Preferred Stock amounted to approximately $9.9 million and $1.2 million, respectively.

On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor Series A Preferred Stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests. Refer to Note 2, "Reorganization," for further details.

## Warrants

On September 9, 2016, upon the emergence from chapter 11 bankruptcy, all existing February 2012 warrants were cancelled and the Successor Company issued 3.8 million new warrants to the Unsecured Noteholders and 0.9 million new warrants to the Convertible Noteholder. The warrants in aggregate can be exercised to purchase 4.7 million shares of the Successor Company's common stock at an exercise price of $14.04 per share. The Company allocated approximately $16.7 million of the Enterprise Value to the warrants which is reflected in "Successor Additional paid-in capital" on the consolidated balance sheet at December 31, 2016 (Successor). The holders are entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. See Note 2, "Reorganization," for further details.

In February 2012, in conjunction with the issuance of the Convertible Note, the Predecessor Company issued the February 2012 Warrants to purchase 7.3 million shares of the Predecessor Company's common stock at an exercise price of $22.50 per share of common stock. The Predecessor Company allocated $43.6 million to the February 2012 Warrants which is reflected in "Predecessor Additional paid-in capital" on the consolidated balance sheet at December 31, 2015 (Predecessor), net of $0.6 million in issuance costs. The February 2012 Warrants entitled the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

On March 9, 2015, in conjunction with the HALRES Note Amendment, the Predecessor Company entered into an amendment to the February 2012 Warrants, the Warrant Amendment, which extended



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

the term of the February 2012 Warrants from February 8, 2017 to February 8, 2020 and adjusted the exercise price from $22.50 to $12.20 per share. The Warrant Amendment was approved by the Predecessor Company's stockholders on May 6, 2015, in accordance with the rules of the NYSE. The Predecessor Company expensed approximately $14.1 million for the change in the fair value of the February 2012 Warrants immediately before and after the Warrant Amendment in "Gain (loss) on extinguishment of Convertible Note and modification of February 2012 Warrants" in the consolidated statements of operations for the year ended December 31, 2015 (Predecessor). See Note 6, "Long-term debt," for further discussion of the HALRES Note Amendment and the Warrant Amendment.

## Incentive Plans

On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (Predecessor Incentive Plan). On May 6, 2015, shareholders last approved an increase in authorized shares under the Predecessor Incentive Plan from 8.3 million to 16.3 million. As of December 31, 2015, a maximum of 6.3 million shares of Predecessor common stock remained reserved for issuance under the Predecessor Incentive Plan.

Immediately prior to emergence from chapter 11 bankruptcy, the Predecessor Incentive Plan was cancelled and all share-based compensation awards granted thereunder were either vested or cancelled and Predecessor Company's Board adopted the 2016 Long-Term Incentive Plan (the 2016 Incentive Plan). An aggregate of 10.0 million shares of the Successor Company's common stock were available for grant pursuant to awards under the 2016 Incentive Plan in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards. As of December 31, 2016 (Successor), a maximum of 1.7 million shares of the Successor Company's common stock remained reserved for issuance under the 2016 Incentive Plan.

The Company accounts for share-based payment accruals under authoritative guidance on stock compensation. The guidance requires all share-based payments to employees and directors, including grants of stock options, and restricted stock, to be recognized in the financial statements based on their fair values. For awards granted under the 2016 Incentive Plan subsequent to emerging from chapter 11 bankruptcy and in conjunction with the early adoption of ASU 2016-09, the Successor Company has elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited.

For the period from September 10, 2016 through December 31, 2016 (Successor) and the period from January 1, 2016 through September 9, 2016 (Predecessor) the Company recognized $21.5 million and $4.9 million, respectively, of share-based compensation expense. For the years ended December 31, 2015 and 2014 (Predecessor), the Company recognized $14.5 million and $18.7 million, respectively, of share-based compensation expense. Share-based compensation expense is recorded as a component of "General and administrative" on the consolidated statements of operations.

## Performance Share Units

As of December 31, 2015 (Predecessor), the Company had outstanding performance share units (PSU) under the Predecessor Incentive Plan covering 0.3 million shares of common stock granted to senior management in 2014. The PSU provided that the number of shares of Predecessor common stock received upon vesting would vary if the market price of the Predecessor Company's common



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

stock exceeded certain pre-established target thresholds as measured by the average of the adjusted closing price of a share of the Predecessor Company's common stock during the sixty trading days preceding the third anniversary of issuance, or the measurement date. The Company had reserved for issuance under the Predecessor Incentive Plan the maximum number of shares that participants might have the right to receive upon vesting of the PSU, or 0.6 million shares of common stock.

No PSUs were granted during the period from January 1, 2016 through September 9, 2016 (Predecessor) or in 2015 (Predecessor). The weighted average grant date fair value of PSUs granted in 2014 (Predecessor) was $4.9 million. At December 31, 2015 (Predecessor) the unrecognized compensation expense related to non-vested PSUs totaled $1.9 million. The weighted average remaining vesting period as of December 31, 2015 (Predecessor) was 1.2 years.

Immediately prior to emergence from chapter 11 bankruptcy, all outstanding PSUs under the Predecessor Incentive Plan were cancelled. Refer to Note 2, "Reorganization," for further details.

The following table sets forth the PSU transactions for the period from January 1, 2016 through September 9, 2016 (Predecessor) and the years ended December 31, 2015 and 2014 (Predecessor):

<table><tr><td></td><td>Number of Shares</td><td>Weighted Average Grant Date Fair Value Per Share</td><td>Aggregate Intrinsic Value(1) (In thousands)</td></tr><tr><td>Unvested outstanding shares at December 31, 2013 (Predecessor)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>320,830</td><td>15.40</td><td></td></tr><tr><td>Vested</td><td>—</td><td>—</td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2014 (Predecessor)</td><td>320,830</td><td>15.40</td><td>—</td></tr><tr><td>Granted</td><td>—</td><td>—</td><td></td></tr><tr><td>Vested</td><td>—</td><td>—</td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2015 (Predecessor)</td><td>320,830</td><td>15.40</td><td>—</td></tr><tr><td>Granted</td><td>—</td><td>—</td><td></td></tr><tr><td>Vested</td><td>—</td><td>—</td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td></tr><tr><td>Cancelled(2)</td><td>(320,830)</td><td>15.40</td><td></td></tr><tr><td>Unvested outstanding shares at September 9, 2016 (Predecessor)</td><td>—</td><td>—</td><td>—</td></tr></table>

(1) The intrinsic value of PSUs was calculated as the average closing market price on December 31, 2015 and 2014 (Predecessor) of the underlying stock multiplied by the number of PSUs that would be convertible. There were no vested PSUs as of December 31, 2015 and 2014 (Predecessor).

(2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding PSUs under the Predecessor Incentive Plan were cancelled.






# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

The assumptions used in calculating the Monte Carlo simulation model fair value of the Company's PSUs for the year ended December 31, 2014 (Predecessor) are disclosed in the following table:

<table><tr><td></td><td>Predecessor Year Ended December 31, 2014</td></tr><tr><td>Weighted average value per PSUs granted during the period</td><td>$15.40</td></tr><tr><td>Assumptions:</td><td></td></tr><tr><td>Stock price volatility \( ^{(1)} \)</td><td>48.00%</td></tr><tr><td>Risk free rate of return</td><td>0.68%</td></tr><tr><td>Expected term</td><td>3 years</td></tr></table>

(1) Due to the Company's limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available.

## Stock Options

From time to time, the Company grants stock options under its incentive plans covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date.

No options were granted from the period January 1, 2016 through September 9, 2016 (Predecessor). The weighted average grant date fair value of options granted in 2015 and 2014 (Predecessor) was $4.9 million, and $13.2 million, respectively. At December 31, 2015 (Predecessor), the unrecognized compensation expense related to non-vested stock options totaled $6.2 million. The weighted average remaining vesting period as of December 31, 2015 (Predecessor) was 1.3 years.

Immediately prior to emergence from chapter 11 bankruptcy, all outstanding stock options under the Predecessor Incentive Plan were cancelled. Refer to Note 2, "Reorganization," for further details.

The weighted average grant date fair value of options granted during the period from September 10, 2016 through December 31, 2016 (Successor) was $32.3 million. At December 31, 2016 (Successor), the Company had $26.5 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.7 years.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

The following table sets forth the stock option transactions for the period from September 10, 2016 through December 31, 2016 (Successor), January 1, 2016 through September 9, 2016 (Predecessor) and the years ended December 31, 2015 and 2014 (Predecessor):

<table><tr><td></td><td>Number</td><td>Weighted Average Exercise Price Per Share</td><td>Aggregate Intrinsic Value(1) (In thousands)</td><td>Weighted Average Remaining Contractual Life (Years)</td></tr><tr><td>Outstanding at December 31, 2013 (Predecessor)</td><td>2,083,237</td><td>35.75</td><td>—</td><td>9.0</td></tr><tr><td>Granted</td><td>1,936,764</td><td>14.70</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(235,269)</td><td>31.05</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2014 (Predecessor)</td><td>3,784,732</td><td>25.25</td><td>724</td><td>8.7</td></tr><tr><td>Granted</td><td>1,922,467</td><td>5.36</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(847,066)</td><td>22.97</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2015 (Predecessor)</td><td>4,860,133</td><td>17.80</td><td>—</td><td>8.4</td></tr><tr><td>Granted</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(695,302)</td><td>21.17</td><td></td><td></td></tr><tr><td>Cancelled(2)</td><td>(4,164,831)</td><td>17.23</td><td></td><td></td></tr><tr><td>Outstanding at September 9, 2016 (Predecessor)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Outstanding at September 9, 2016 (Successor)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>5,319,400</td><td>9.22</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2016 (Successor)</td><td>5,319,400</td><td>9.22</td><td>631</td><td>9.7</td></tr></table>

(1) The intrinsic value of stock options was calculated as the amount by which the closing market price on December 31, 2016 (Successor) and December 31, 2015 and 2014 (Predecessor) of the underlying stock exceeded the exercise price of the option. No stock options were exercised during the period from September 10, 2016 through December 31, 2016 (Successor), the period from January 1, 2016 through September 9, 2016 (Predecessor), or the years ended December 31, 2015 and 2014 (Predecessor).






# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

Options outstanding at December 31, 2016 (Successor) consisted of the following:

<table><tr><td rowspan="2">Range of Grant Prices Per Share</td><td colspan="3">Outstanding</td><td colspan="5">Exercisable(1)</td></tr><tr><td>Number</td><td>Weighted Average Exercise Price per Share</td><td>Weighted Average Remaining Contractual Life (Years)</td><td>Number</td><td>Weighted Average Exercise Price per Share</td><td>Aggregate Intrinsic Value</td><td>Weighted Average Remaining Contractual Life (Years)</td><td></td></tr><tr><td>$8.93</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>319,400</td><td>$</td><td>8.93</td><td>10.0</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>$9.24</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>5,000,000</td><td></td><td>9.24</td><td>9.7</td><td>—</td><td>—</td><td>—</td><td>—</td></tr></table>

(1) At December 31, 2016 (Successor), none of the Company's options were exercisable due to service performance conditions.

The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Company's stock options for the period from September 10, 2016 through December 31, 2016 (Successor) and the years ended December 31, 2015 and 2014 (Predecessor) are set forth in the following table:

<table><tr><td rowspan="2"></td><td colspan="2">Predecessor</td></tr><tr><td>Successor</td><td>Years Ended December 31,</td></tr><tr><td>Weighted average value per option granted during the period</td><td></td><td></td></tr><tr><td></td><td>Period from September 10, 2016 through December 31, 2016</td><td>2015 2014</td></tr><tr><td>Weighted average value per option granted during the period</td><td>$6.07</td><td>$2.56 $6.80</td></tr><tr><td>Assumptions:</td><td></td><td></td></tr><tr><td>Stock price volatility(1)</td><td>56.29%</td><td>56.45% 51.48%</td></tr><tr><td>Risk free rate of return</td><td>1.34%</td><td>1.66% 1.56%</td></tr><tr><td>Expected term</td><td>6 years</td><td>5 years 5 years</td></tr></table>

(1) Due to the Company's limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available.

## Restricted Stock

From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six months from the date of grant. For certain shares granted under the 2016 Incentive Plan, subsequent to emergence from chapter 11 bankruptcy, half vested immediately on the date of the grants and the remaining half will vest on the first anniversary of the date of grants.

No restricted shares were granted from the period January 1, 2016 through September 9, 2016 (Predecessor). The weighted average grant date fair value of the shares granted in 2015 and 2014 (Predecessor) was $8.5 million and $23.7 million, respectively. At December 31, 2015 (Predecessor), the unrecognized compensation expense related to non-vested restricted stock totaled $11.1 million. The weighted average remaining vesting period as of December 31, 2015 (Predecessor) was 1.5 years.

Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock awards granted under the Predecessor Incentive Plan were vested. Refer to Note 2, "Reorganization," for further details.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. STOCKHOLDERS' EQUITY (Continued)

The weighted average grant date fair value of shares granted during the period from September 10, 2016 through December 31, 2016 (Successor) was $27.3 million. At December 31, 2016 (Successor), the Company had $11.5 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 0.9 years.

The following table sets forth the restricted stock transactions for the period from September 10, 2016 through December 31, 2016 (Successor), January 1, 2016 through September 9, 2016 (Predecessor) and the years ended December 31, 2015 and 2014 (Predecessor):

<table><tr><td></td><td>Number of Shares</td><td>Weighted Average Grant Date Fair Value Per Share</td><td>Aggregate Intrinsic Value(1) (In thousands)</td></tr><tr><td>Unvested outstanding shares at December 31, 2013 (Predecessor)</td><td></td><td></td><td></td></tr><tr><td>Granted</td><td>528,676</td><td>35.80</td><td>10,204</td></tr><tr><td>Vested</td><td>1,877,608</td><td>12.60</td><td></td></tr><tr><td>Forfeited</td><td>(246,232)</td><td>34.05</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2014 (Predecessor)</td><td>(91,141)</td><td>23.05</td><td></td></tr><tr><td>Granted</td><td>2,068,911</td><td>15.55</td><td>18,413</td></tr><tr><td>Vested</td><td>2,047,785</td><td>4.15</td><td></td></tr><tr><td>Forfeited</td><td>(858,708)</td><td>16.24</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2015 (Predecessor)</td><td>(387,583)</td><td>12.86</td><td></td></tr><tr><td>Granted</td><td>2,870,405</td><td>7.55</td><td>3,617</td></tr><tr><td>Vested</td><td>—</td><td>—</td><td></td></tr><tr><td>Accelerated vesting(2)</td><td>(436,256)</td><td>18.50</td><td></td></tr><tr><td>Forfeited</td><td>(1,917,072)</td><td>5.39</td><td></td></tr><tr><td>Unvested outstanding shares at September 9, 2016 (Predecessor)</td><td>(517,077)</td><td>6.31</td><td></td></tr><tr><td>Unvested shares outstanding at September 9, 2016 (Successor)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>2,991,202</td><td>9.14</td><td></td></tr><tr><td>Vested</td><td>(1,253,125)</td><td>9.24</td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td></tr><tr><td>Unvested shares outstanding at December 31, 2016 (Successor)</td><td>1,738,077</td><td>9.06</td><td>16,234</td></tr></table>



(1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2016 (Successor) and December 31, 2015 and 2014 (Predecessor) of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $11.6 million for the period from September 10, 2016 to December 31, 2016 (Successor). The total fair value of shares vested was $0.9 million, $5.2 million, and $5.1 million for the period from January 1, 2016 through September 9, 2016 (Predecessor) and the years ended December 31, 2015 and 2014 (Predecessor).

(2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock under the Predecessor Incentive Plan were vested.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 14. INCOME TAXES

Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands):

<table><tr><td rowspan="2"></td><td colspan="4">Predecessor</td></tr><tr><td>Successor Period from September 10, 2016 through December 31, 2016</td><td>Period from January 1, 2016 through September 9, 2016</td><td colspan="2">Years Ended December 31,</td></tr><tr><td>Current:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ (5,000)</td><td>$ 8,666</td><td>$ (8,580)</td><td>$ 1,295</td></tr><tr><td>State</td><td>256</td><td>—</td><td>(506)</td><td>(219)</td></tr><tr><td>Total current income tax benefit (provision)</td><td>(4,744)</td><td>8,666</td><td>(9,086)</td><td>1,076</td></tr><tr><td>Deferred:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>52,223</td><td>(22,491)</td><td>(39,331)</td><td>2,653</td></tr><tr><td>State</td><td>(52,223)</td><td>22,491</td><td>39,331</td><td>(2,653)</td></tr><tr><td>Total deferred income tax benefit (provision)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total income tax benefit (provision)</td><td>$ (4,744)</td><td>$ 8,666</td><td>$ (9,086)</td><td>$ 1,076</td></tr></table>

The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States Federal corporate income tax rate of 35% for each period as follows (in thousands):

<table><tr><td rowspan="2"></td><td colspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td colspan="2">Years Ended December 31, 2015</td><td>2014</td><td></td></tr><tr><td>Expected tax benefit (provision)</td><td>$ 166,057</td><td>$ (1,152)</td><td>$ 669,737</td><td>$ (110,208)</td><td></td></tr><tr><td>State income tax expense, net of federal benefit</td><td>6,243</td><td>(43)</td><td>41,003</td><td>(4,615)</td><td></td></tr><tr><td>Share-based compensation</td><td>—</td><td>(14,803)</td><td>—</td><td>—</td><td></td></tr><tr><td>Net operating loss limitation under IRC Section 382</td><td>(161,704)</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>HK TMS Divestiture</td><td>(157,767)</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Adjustments attributable to reorganization</td><td>—</td><td>275,460</td><td>—</td><td>—</td><td></td></tr><tr><td>Debt related costs</td><td>—</td><td>(4,089)</td><td>(7,102)</td><td>(5,467)</td><td></td></tr><tr><td>Cancellation of indebtedness income</td><td>—</td><td>103,268</td><td>(89,081)</td><td>—</td><td></td></tr><tr><td>Increase (reduction) in deferred tax asset</td><td></td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td></td><td>—</td><td>14,429</td><td>(6,369)</td><td>19,233</td></tr><tr><td>Change in valuation allowance and related items</td><td>202,592</td><td>(262,995)</td><td>(598,429)</td><td>102,068</td></tr><tr><td>IRC section 108 attribute reduction</td><td>(56,483)</td><td>(101,342)</td><td>(13,744)</td><td>—</td></tr><tr><td>Other</td><td>(3,682)</td><td>(67)</td><td>(5,101)</td><td>65</td></tr><tr><td>Total income tax benefit (provision)</td><td>$ (4,744)</td><td>$ 8,666</td><td>$ (9,086)</td><td>$ 1,076</td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 14. INCOME TAXES (Continued)

The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):

<table><tr><td></td><td>Successor
December 31, 2016</td><td>Predecessor
December 31, 2015</td></tr><tr><td>Deferred noncurrent income tax assets:</td><td></td><td></td></tr><tr><td>Net operating loss carry-forwards</td><td></td><td></td></tr><tr><td>Share-based compensation expense</td><td>$ 155,393</td><td>$ 555,044</td></tr><tr><td></td><td>3,430</td><td>15,027</td></tr><tr><td>Asset retirement obligations</td><td></td><td></td></tr><tr><td>Investment in unconsolidated entities</td><td>11,233</td><td>14,616</td></tr><tr><td></td><td>—</td><td>59,429</td></tr><tr><td>Book-tax differences in property basis</td><td></td><td></td></tr><tr><td></td><td>647,574</td><td>234,900</td></tr><tr><td>Unrealized hedging transactions</td><td>3,937</td><td>—</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>330</td><td>19,376</td></tr><tr><td>Gross deferred noncurrent income tax assets</td><td></td><td></td></tr><tr><td></td><td>821,897</td><td>898,392</td></tr><tr><td>Valuation allowance</td><td></td><td></td></tr><tr><td></td><td>(821,897)</td><td>(761,493)</td></tr><tr><td>Deferred noncurrent income tax assets</td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ 136,899</td></tr><tr><td>Deferred noncurrent income tax liabilities:</td><td></td><td></td></tr><tr><td>Change in accounting method</td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ (4,057)</td></tr><tr><td>Unrealized hedging transactions</td><td></td><td></td></tr><tr><td></td><td>—</td><td>(132,842)</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Deferred noncurrent income tax liabilities</td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ (136,899)</td></tr><tr><td>Net noncurrent deferred income tax assets (liabilities)</td><td></td><td></td></tr></table>

At December 31, 2015, the Company early adopted ASU 2015-07 on a prospective basis and accordingly, presented all deferred tax assets and liabilities as noncurrent on the consolidated balance sheet as of December 31, 2015.

Under the Plan, a substantial portion of the Company's pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (IRC), provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $844 million, which will reduce the value of the Company's U.S. net operating losses and other assets. The actual reduction in tax attributes does not occur until the first day of the Company's tax year subsequent to the date of emergence, or January 1, 2017. The estimated results of the attribute reduction have been reflected in the Company's ending balance of deferred tax assets for the year ended December 31, 2016 (Successor). The Successor Company also has various state NOL carryforwards that are subject to reduction as a result of the CODI being excluded from taxable






# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 14. INCOME TAXES (Continued)

IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company's emergence from chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The limitation under the IRC is based on the value of the corporation as of the emergence date. The ownership changes and resulting annual limitation will result in the expiration of an estimated $462 million of net operating losses generated prior to the emergence date. The expiration of these tax attributes was fully offset by a corresponding decrease in the Company's U.S. valuation allowance, which results in no net tax provision.

The amount of consolidated U.S. net operating losses (NOLs) available as of December 31, 2016 (Successor) after attribute reduction on January 1, 2017 and Section 382 limitation is estimated to be approximately $444 million. These NOLs will expire in the years 2019 through 2036.

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. A significant item of objective negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2016 driven primarily by the full cost ceiling impairments over that period which limits the ability to consider other subjective evidence such as the Company's anticipated future growth. As a result of the Company's analysis, it was concluded that as of December 31, 2016 a valuation allowance should continue to be applied against the Company's net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2016 (Successor) of $821.9 million, an increase of $60.4 million from December 31, 2015 (Predecessor). The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized.

ASC 740, Income Taxes (ASC 740) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no recognized tax benefits for the period of September 10, 2016 through December 31, 2016 (Successor) and January 1, 2016 through September 9, 2016 (Predecessor) and the years ended December 31, 2015 or 2014 (Predecessor).

Generally, the Company's income tax years 2013 through 2016 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statute expiration period for federal purposes.

The Company recognizes interest and penalties accrued to unrecognized benefits in "Interest expense and other, net" in its consolidated statements of operations. For the period of September 10, 2016 through December 31, 2016 (Successor) and January 1, 2016 through September 9, 2016



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 14. INCOME TAXES (Continued)

(Predecessor) and the years ended December 31, 2015 and 2014 (Predecessor) the Company recognized no interest and penalties.

During the first quarter of 2014 (Predecessor), the Internal Revenue Service commenced an audit of GeoResources' tax returns for the years ending December 31, 2010 through August 1, 2012. The audit closed during April 2015 (Predecessor) resulting in a favorable adjustment to the Company of $0.1 million.

## 15. EARNINGS PER SHARE

On September 9, 2016, upon emergence from chapter 11 bankruptcy, the Predecessor Company's equity was cancelled and new equity was issued. Refer to Note 2, "Reorganization," for further details.

The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Basic:</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss) available to common stockholders</td><td>$ (479,984)</td><td>$ (32,794)</td><td>$ (2,006,958)</td><td>$ 282,942</td></tr><tr><td>Weighted average basic number of common shares outstanding</td><td>91,228</td><td>120,513</td><td>107,531</td><td>83,155</td></tr><tr><td>Basic net income (loss) per common share</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 3.40</td></tr><tr><td>Diluted:</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income (loss) available to common stockholders</td><td>$ (479,984)</td><td>$ (32,794)</td><td>$ (2,006,958)</td><td>$ 282,942</td></tr><tr><td>Interest on Convertible Note, net</td><td>—</td><td>—</td><td>—</td><td>15,302</td></tr><tr><td>Series A preferred dividends</td><td>—</td><td>—</td><td>—</td><td>19,838</td></tr><tr><td>Net income (loss) available to common stockholders after assumed conversions</td><td>$ (479,984)</td><td>$ (32,794)</td><td>$ (2,006,958)</td><td>$ 318,082</td></tr><tr><td>Weighted average basic number of common shares outstanding</td><td>91,228</td><td>120,513</td><td>107,531</td><td>83,155</td></tr><tr><td>Common stock equivalent shares representing shares issuable upon:</td><td></td><td></td><td></td><td></td></tr><tr><td>Exercise of stock options</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>75</td></tr><tr><td>Exercise of February 2012 Warrants</td><td>—</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>784</td></tr><tr><td>Exercise of Warrants</td><td>Anti-dilutive</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Vesting of restricted shares</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>310</td></tr><tr><td>Vesting of performance units</td><td>—</td><td>—</td><td>—</td><td>73</td></tr></table>



<table><tr><td>Conversion of Convertible Note</td><td>—</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>12,875</td></tr><tr><td>Conversion of Series A Preferred Stock</td><td>—</td><td>Anti-dilutive</td><td>Anti-dilutive</td><td>11,209</td></tr><tr><td>Weighted average diluted number of common shares outstanding</td><td>91,228</td><td>120,513</td><td>107,531</td><td>108,481</td></tr><tr><td>Diluted net income (loss) per common share</td><td>$ (5.26)</td><td>$ (0.27)</td><td>$ (18.66)</td><td>$ 2.93</td></tr></table>



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 15. EARNINGS PER SHARE (Continued)

Common stock equivalents, including stock options, restricted shares and warrants totaling 11.2 million shares for the period from September 10, 2016 through December 31, 2016 (Successor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive. Common stock equivalents, including stock options, restricted shares, warrants, convertible debt and preferred stock totaling 43.6 million shares for the period from January 1, 2016 through September 9, 2016 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

On January 24, 2017 (Successor), the Company entered into a stock purchase agreement with certain accredited investors to sell approximately 5,518 shares of 8% automatically convertible preferred stock, each share of which is convertible into 10,000 shares of common stock (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued). Refer to Note 17, "Subsequent Events," for further details.

Common stock equivalents, including stock options, restricted shares, warrants, convertible debt and preferred stock totaling 47.1 million shares were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive for the year ended December 31, 2015 (Predecessor) due to the net loss.

Common stock equivalents, including stock options, restricted shares and warrants, totaling 6.2 million shares were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive for the year ended December 31, 2014 (Predecessor).



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 16. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following (in thousands):

<table><tr><td rowspan="2"></td><td>Successor</td><td>Predecessor</td></tr><tr><td>December 31, 2016</td><td>December 31, 2015</td></tr><tr><td>Accounts receivable:</td><td></td><td></td></tr><tr><td>Oil, natural gas and natural gas liquids revenues</td><td>$ 86,433</td><td>$ 55,129</td></tr><tr><td>Joint interest accounts</td><td>39,828</td><td>67,626</td></tr><tr><td>Accrued settlements on derivative contracts</td><td>18,599</td><td>47,011</td></tr><tr><td>Affiliated partnership</td><td>268</td><td>176</td></tr><tr><td>Other</td><td>2,634</td><td>3,682</td></tr><tr><td></td><td>$ 147,762</td><td>$ 173,624</td></tr><tr><td>Prepaids and other:</td><td></td><td></td></tr><tr><td>Prepaids</td><td>$ 6,704</td><td>$ 4,585</td></tr><tr><td>Inventory</td><td>—</td><td>4,635</td></tr><tr><td>Other</td><td>54</td><td>50</td></tr><tr><td></td><td>$ 6,758</td><td>$ 9,270</td></tr><tr><td>Accounts payable and accrued liabilities:</td><td></td><td></td></tr><tr><td>Trade payables</td><td>$ 24,364</td><td>$ 47,261</td></tr><tr><td>Accrued oil and natural gas capital costs</td><td>32,967</td><td>54,651</td></tr><tr><td>Revenues and royalties payable</td><td>79,147</td><td>64,002</td></tr><tr><td>Accrued interest expense</td><td>31,146</td><td>88,499</td></tr><tr><td>Accrued employee compensation</td><td>3,428</td><td>2,829</td></tr><tr><td>Accrued lease operating expenses</td><td>14,077</td><td>20,036</td></tr><tr><td>Drilling advances from partners</td><td>422</td><td>7,964</td></tr><tr><td>Income taxes payable</td><td>250</td><td>9,172</td></tr><tr><td>Affiliated partnership</td><td>323</td><td>365</td></tr><tr><td>Other</td><td>60</td><td>306</td></tr></table>



## 17. SUBSEQUENT EVENTS

## Issuance of 2025 Senior Notes and Repurchase of 2020 Second Lien Notes

On February 16, 2017 (Successor), the Company issued $850.0 million aggregate principal amount of new 6.75% senior unsecured notes due 2025 (the 2025 Notes) in a private placement exempt from registration under the Securities Act of 1933, as amended (Securities Act), afforded by Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bear interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2017. The 2025 Notes will mature on February 15, 2025. Proceeds from the private placement were approximately $835.1 million after deducting initial purchasers' discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase of the outstanding 2020 Second Lien Notes, and will use an additional amount of the net proceeds to redeem the remaining amount of such notes, discussed further below, and for general corporate purposes.

The 2025 Notes are governed by an Indenture, dated as of February 16, 2017, (the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 17. SUBSEQUENT EVENTS (Continued)

Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain future subsidiaries of the Company.

In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the Initial Purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing.

At any time prior to February 15, 2020, the Company may redeem the 2025 Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make-whole premium, together with accrued and unpaid interest, if any, to the redemption date. The 2025 Notes will be redeemable, in whole or in part, on or after February 15, 2020 at redemption prices equal to the principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest (if any) on the 2025 Notes redeemed during the twelve month period indicated beginning on February 15 of the years indicated below:

<table><tr><td>Year</td><td>Percentage</td></tr><tr><td>2020</td><td>105.063</td></tr><tr><td>2021</td><td>103.375</td></tr><tr><td>2022</td><td>101.688</td></tr><tr><td>2023 and thereafter</td><td>100.000</td></tr></table>

Additionally, the Company may redeem up to 35% of the 2025 Notes prior to February 15, 2020 for a redemption price of 106.75% of the principal amount thereof, plus accrued and unpaid interest, utilizing net cash proceeds from certain equity offerings. In addition, upon a change of control of the Company, holders of the 2025 Notes will have the right to require the Company to repurchase all or any part of their 2025 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2025 Notes repurchased, plus any accrued and unpaid interest.

On February 9, 2017 (Successor), the Company commenced a cash tender offer for any and all of its 2020 Second Lien Notes and on February 15, 2017, the Company received approximately $289.2 million or 41% of the outstanding aggregate principal amount of the 2020 Second Lien Notes which were validly tendered (and not validly withdrawn). As a result, on February 16, 2017 (Successor), the Company paid approximately $303.5 million for approximately $289.2 million principal amount of 2020 Second Lien Notes, a make-whole premium of $13.2 million plus accrued and unpaid interest of approximately $1.1 million to repurchase such notes and issued a redemption notice to redeem the remaining 2020 Second Lien Notes. The remaining $410.8 million aggregate principal amount of 2020 Second Lien Notes will be repurchased through the guaranteed delivery procedures or redeemed at a



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 17. SUBSEQUENT EVENTS (Continued)

price of 104.313% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date. The redemption date is expected to be March 20, 2017.

## Pending Divestiture of East Texas Eagle Ford Assets

On January 24, 2017 (Successor), certain of the Company's subsidiaries entered into an Agreement of Sale and Purchase with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of its oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total sales price of $500.0 million (the El Halcón Divestiture). The effective date of the proposed sale is January 1, 2017, and the Company expects to close the transaction in early March 2017. The sale properties include approximately 80,500 net acres prospective for the Eagle Ford formation in East Texas and the related gas gathering assets.

The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the agreement, Hawkwood paid into escrow a deposit of $32.5 million at signing, which amount will be applied to the sales price if the transaction closes.

The completion of the El Halcón Divestiture is subject to customary closing conditions. The parties may terminate the sale agreement if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or $100.0 million, or the transaction has not closed on or before March 20, 2017. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that the Company will sell the El Halcón Assets on the terms or timing described or at all. If the El Halcón Divestiture closes, the Company intends to use the net proceeds to repay borrowings outstanding under its Senior Credit Agreement and for general corporate purposes.

## Private Placement of Automatically Convertible Preferred Stock

On January 24, 2017 (Successor), the Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% automatically convertible preferred stock, par value $0.0001 per share, each share of which is convertible into 10,000 shares of common stock, par value $0.0001 per share (or a proportionate number of shares of common stock with respect to any fractional shares of preferred stock issued), for gross proceeds of approximately $400.1 million, equivalent to a placement at $7.25 per common share. The Company used the net proceeds from the sale of the preferred stock to partially fund the Pecos County Acquisition.

The preferred stock was offered and sold in a private placement exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2) to "accredited investors" (as defined in Rule 501(a) under the Securities Act).

Each share of preferred stock will be convertible into a number of shares of common stock determined by dividing the liquidation preference of the preferred stock, which is equal to the liquidation price plus the amount of any accrued and unpaid dividends through the date of conversion, by the conversion price. The aggregate liquidation preference of the preferred stock is $400.1 million. Accordingly, until such date each share of preferred stock will automatically convert into 10,000 shares



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 17. SUBSEQUENT EVENTS (Continued)

of common stock at an initial conversion price of $7.25 per share of common stock and each fractional share of preferred stock will be initially convertible into a proportionate number of shares of common stock. The preferred stock will convert automatically on the 20th calendar day after the Company mails a definitive information statement to holders of its common stock notifying them that holders of a majority of its outstanding common stock consented to the issuance of common stock upon conversion of the preferred stock on as of January 24, 2017 (Successor). The initial conversion price is subject to adjustment in certain circumstances, including stock splits, stock dividends, rights offerings, or combinations of its common stock. No dividend will be paid on the preferred stock if it converts into common stock on or before June 1, 2017. The common stock issuable upon a conversion of the preferred stock represents approximately 37% of the Company's outstanding common stock as of December 31, 2016 on an as-converted basis.

The Company agreed to file a registration statement to register the resale of shares of common stock issuable upon conversion of the preferred stock and to pay penalties in the event such registration is not effective by June 27, 2017.

## Acquisition of Southern Delaware Basin Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Successor), Halcón Energy Properties, Inc., a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it agreed to acquire a total of 20,901 net acres and related assets in the Southern Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total purchase price of $705.0 million (the Pecos County Acquisition). The effective date of the acquisition was November 1, 2016, and the Company closed the transaction on February 28, 2017.

The purchase price was subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. The Company funded the Pecos County Acquisition with the net proceeds from the private placement of its preferred stock and borrowings under its Senior Credit Agreement.

Following the agreement with Samson, the Company agreed to acquire additional interests in the acreage from a non-operating owner for approximately $22.3 million. This incremental acquisition includes 594 additional net acres and is expected to close in early March 2017.



# SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

## Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates shown herein for the years ended December 31, 2016 (Successor), 2015 (Predecessor) and 2014 (Predecessor) have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves report incorporated herein are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. Mr. Henson, a Licensed Professional Engineer in the State of Texas (No. 73964), has been practicing consulting petroleum engineering at Netherland, Sewell since 1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas (No. 441), has been a practicing petroleum geoscience consultant at Netherland, Sewell since 1989 and has over ten years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Netherland, Sewell has reported to the Company, that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Company's board of directors has established an independent reserves committee composed of three outside directors, all of whom have experience in energy company reserve evaluations. The Company's independent engineering firm reports jointly to the reserves committee and to the Senior Vice President of Corporate Reserves. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to the board of directors as to whether to approve the report prepared by the independent engineering firm. Ms. Tina Obut, the Company's Senior Vice President of Corporate Reserves is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. She graduated from Marietta College with a Bachelor of Science degree in Petroleum Engineering, received a Master of Science degree in Petroleum and Natural Gas.



The reserves information in this Annual Report on Form 10-K represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company's control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company's proved reserves will decline as reserves are produced.

The following table illustrates the Company's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2016, 2015 and 2014 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $42.75 per barrel, $50.28 per barrel and $94.99 per barrel, respectively. The natural gas prices as of December 31, 2016, 2015 and 2014 are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $2.481 per MMBtu, $2.587 per MMBtu and $4.350 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.

<table><tr><td rowspan="2"></td><td colspan="4">Proved Reserves</td></tr><tr><td>Oil (MBbls)</td><td>Natural Gas (MMcf)</td><td>Natural Gas Liquids (MBbls)</td><td>Equivalent (MBoe)</td></tr><tr><td>Proved reserves, December 31, 2013 (Predecessor)</td><td>114,510</td><td>69,748</td><td>9,832</td><td>135,967</td></tr><tr><td>Extensions and discoveries</td><td>61,312</td><td>31,937</td><td>5,984</td><td>72,619</td></tr><tr><td>Purchase of minerals in place</td><td>942</td><td>767</td><td>45</td><td>1,115</td></tr><tr><td>Production</td><td>(12,787)</td><td>(8,812)</td><td>(1,113)</td><td>(15,369)</td></tr><tr><td>Sale of minerals in place</td><td>(14,487)</td><td>(8,125)</td><td>(1,789)</td><td>(17,630)</td></tr><tr><td>Revision of previous estimates</td><td>6,084</td><td>18,147</td><td>3,327</td><td>12,435</td></tr><tr><td>Proved reserves, December 31, 2014 (Predecessor)</td><td>155,574</td><td>103,662</td><td>16,286</td><td>189,137</td></tr><tr><td>Extensions and discoveries</td><td>10,117</td><td>6,838</td><td>1,215</td><td>12,472</td></tr><tr><td>Purchase of minerals in place</td><td>36</td><td>17</td><td>4</td><td>43</td></tr><tr><td>Production</td><td>(12,019)</td><td>(10,123)</td><td>(1,457)</td><td>(15,163)</td></tr><tr><td>Sale of minerals in place</td><td>(5)</td><td>(2)</td><td>(1)</td><td>(6)</td></tr><tr><td>Revision of previous estimates</td><td>(33,010)</td><td>(21,950)</td><td>(3,010)</td><td>(39,679)</td></tr><tr><td>Proved reserves, December 31, 2015 (Predecessor)</td><td>120,693</td><td>78,442</td><td>13,037</td><td>146,804</td></tr><tr><td>Extensions and discoveries</td><td>15,279</td><td>7,532</td><td>1,722</td><td>18,256</td></tr><tr><td>Purchase of minerals in place</td><td>1,114</td><td>654</td><td>113</td><td>1,336</td></tr><tr><td>Production</td><td>(10,368)</td><td>(9,571)</td><td>(1,597)</td><td>(13,560)</td></tr><tr><td>Sale of minerals in place</td><td>(1,319)</td><td>(258)</td><td>(7)</td><td>(1,369)</td></tr><tr><td>Revision of previous estimates</td><td>(5,799)</td><td>3,439</td><td>2,373</td><td>(2,853)</td></tr></table>






<table><tr><td rowspan="2"></td><td colspan="4">Proved Developed Reserves</td></tr><tr><td>Oil (MBbls)</td><td>Natural Gas (MMcf)</td><td>Natural Gas Liquids (MBbls)</td><td>Equivalent (MBoe)</td></tr><tr><td>December 31, 2016 (Successor)</td><td>67,983</td><td>51,525</td><td>9,337</td><td>85,908</td></tr><tr><td>December 31, 2015 (Predecessor)</td><td>66,123</td><td>49,201</td><td>7,561</td><td>81,885</td></tr><tr><td>December 31, 2014 (Predecessor)</td><td>62,770</td><td>47,851</td><td>6,681</td><td>77,427</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Proved Undeveloped Reserves</td></tr><tr><td>Oil (MBbls)</td><td>Natural Gas (MMcf)</td><td>Natural Gas Liquids (MBbls)</td><td>Equivalent (MBoe)</td></tr><tr><td>December 31, 2016 (Successor)</td><td>51,617</td><td>28,713</td><td>6,304</td><td>62,706</td></tr><tr><td>December 31, 2015 (Predecessor)</td><td>54,570</td><td>29,241</td><td>5,476</td><td>64,919</td></tr><tr><td>December 31, 2014 (Predecessor)</td><td>92,804</td><td>55,811</td><td>9,605</td><td>111,710</td></tr></table>

The Company's reserves have been estimated using deterministic methods. The total proved reserve increase of 1.8 MMBoE during 2016 is the result of an increase in proved developed reserves of 4.0 MMBoE offset by a decrease of 2.2 MMBoE in proved undeveloped (PUD) reserves.

During 2016, the increase in proved developed reserves is primarily associated with extension and infill drilling in the Bakken / Three Forks and El Halcón areas and positive performance revisions in the Bakken / Three Forks area partially offset by negative revisions due to lower SEC prices. The decrease in PUD reserves is primarily due to the conversion of PUD reserves to proved developed reserves from infill drilling and the removal of PUDs that no longer met the SEC five year development requirement, partially offset by the addition of PUD reserves.

During 2015, the Predecessor Company added 12.5 MMBoE in proved reserves by drilling extensions and infill development primarily in the Bakken / Three Forks and El Halcón areas. Extensions and discoveries were offset by negative revisions due to the sustained decline in commodity prices, resulting in an overall negative revision of 39.7 MMBoE.

During 2014, the Predecessor Company added 72.6 MMBoE in proved reserves by drilling extensions and infill development in the Bakken / Three Forks and El Halcón areas and an additional 12.4 MMBoE in positive revisions driven by better performance in the Bakken / Three Forks area. Sales of 17.6 MMBoE of proved reserves are primarily attributable to the divestiture of the East Texas Assets.

At December 31, 2016, the Successor Company's estimated PUD reserves were approximately 62.7 MMBoE, a 2.2 MMBoE net decrease over the previous year's estimate of 64.9 MMBoE. The following details the changes in PUD reserves for 2016 (MBoe):

<table><tr><td>Beginning proved undeveloped reserves at December 31, 2015 (Predecessor)</td><td>64,919</td></tr><tr><td>Undeveloped reserves transferred to developed</td><td>(7,510)</td></tr><tr><td>Revisions</td><td>(9,314)</td></tr><tr><td>Purchases</td><td>526</td></tr><tr><td>Divestitures</td><td>(246)</td></tr><tr><td>Extension and discoveries</td><td>14,331</td></tr><tr><td>Ending proved undeveloped reserves at December 31, 2016 (Successor)</td><td>62,706</td></tr></table>

The decrease in PUD reserves was due to a negative revision associated with the decline in the unweighted 12-month average prices of oil and natural gas during 2016. Negative revisions of approximately 9 MMBoE were largely associated with PUD locations in the Bakken/Three Forks and El Halcón areas that became uneconomic at the lower unweighted 12-month average prices of oil and natural gas as of December 31, 2016 (Successor), or were removed because they no longer met the






SEC five year development requirement as we have reduced our capital spending since the prior year as a result of the sustained decline in oil and natural gas prices. Further reductions of approximately 8 MMBoE in PUD reserves were the direct result of development through our drilling program and the associated transfer of those reserves to proved developed reserves, primarily in the Bakken/Three Forks and El Halcón areas.

As of December 31, 2016 all of the Successor Company's PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2016, approximately $181.7 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line open hole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic EURs from individual producing wells. The Company's management team has been a leader in data gathering and evaluation in these areas and was instrumental in developing consortiums that allow various operators to exchange data. The Company relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves.

## Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depletion, depreciation and accretion (in thousands):

<table><tr><td rowspan="2"></td><td colspan="2">Successor</td><td colspan="2">Predecessor</td></tr><tr><td>December 31, 2016</td><td>December 31, 2015</td><td>December 31, 2014</td><td></td></tr><tr><td>Evaluated oil and natural gas properties \( ^{(1)} \)</td><td>$ 1,269,034</td><td>$ 7,060,721</td><td>$ 6,390,820</td><td></td></tr><tr><td>Unevaluated oil and natural gas properties</td><td>316,439</td><td>1,641,356</td><td>1,829,786</td><td></td></tr><tr><td></td><td>1,585,473</td><td>8,702,077</td><td>8,220,606</td><td></td></tr><tr><td>Accumulated depletion \( ^{(1)} \)</td><td>(465,849)</td><td>(5,933,688)</td><td>(2,953,038)</td><td></td></tr><tr><td></td><td>$ 1,119,624</td><td>$ 2,768,389</td><td>$ 5,267,568</td><td></td></tr></table>

(1) Amounts do not include costs for the Company's gas gathering systems and related support equipment.



## Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="3">Predecessor</td></tr><tr><td>Period from January 1, 2016 through September 9, 2016</td><td>Years Ended December 31, 2015</td><td>2014</td></tr><tr><td>Property acquisition costs, proved \( ^{(1)} \)</td><td>—</td><td>$ (127)</td><td>$ (582)</td><td>$ 16,037</td></tr><tr><td>Property acquisition costs, unproved</td><td>5,070</td><td>3</td><td>268</td><td>220,044</td></tr><tr><td>Exploration and extension well costs</td><td>13,865</td><td>67,216</td><td>194,683</td><td>1,107,549</td></tr><tr><td>Development costs</td><td>45,765</td><td>135,939</td><td>285,194</td><td>374,252</td></tr><tr><td>Total costs</td><td>$ 64,700</td><td>$ 203,031</td><td>$ 479,563</td><td>$ 1,717,882</td></tr></table>

(1) Proved property acquisition costs in 2016 and 2015 primarily reflect the impact of purchase price adjustments.

## Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractive Activities—Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

• future costs and selling prices will probably differ from those required to be used in these calculations;

• due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

• future net revenues may be subject to different rates of income taxation.

At December 31, 2016, 2015 and 2014, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.



The Standardized Measure is as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Years Ended December 31,</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td></td><td colspan="3">(In thousands)</td></tr><tr><td>Future cash inflows</td><td>$ 4,726,490</td><td>$ 5,406,179</td><td>$ 14,439,301</td></tr><tr><td>Future production costs</td><td>(2,290,079)</td><td>(2,414,629)</td><td>(4,804,728)</td></tr><tr><td>Future development costs</td><td>(771,070)</td><td>(813,814)</td><td>(2,795,208)</td></tr><tr><td>Future income tax expense</td><td>—</td><td>—</td><td>(1,979,245)</td></tr><tr><td>Future net cash flows before 10% discount</td><td>1,665,341</td><td>2,177,736</td><td>4,860,120</td></tr><tr><td>10% annual discount for estimated timing of cash flows</td><td>(861,824)</td><td>(1,067,171)</td><td>(1,603,750)</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 803,517</td><td>$ 1,110,565</td><td>$ 3,256,370</td></tr></table>

## Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company's proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016:

<table><tr><td rowspan="3"></td><td colspan="3">Years Ended December 31,</td></tr><tr><td>2016</td><td>2015</td><td>2014</td></tr><tr><td colspan="3">(In thousands)</td></tr><tr><td>Beginning of year</td><td>$ 1,110,565</td><td>$ 3,256,370</td><td>$ 2,745,995</td></tr><tr><td>Sale of oil and natural gas produced, net of production costs</td><td>(275,816)</td><td>(375,137)</td><td>(893,117)</td></tr><tr><td>Purchase of minerals in place</td><td>9,626</td><td>946</td><td>22,142</td></tr><tr><td>Sales of minerals in place</td><td>(18,816)</td><td>(96)</td><td>(475,096)</td></tr><tr><td>Extensions and discoveries</td><td>67,433</td><td>94,679</td><td>1,298,611</td></tr><tr><td>Changes in income taxes, net</td><td>—</td><td>170,546</td><td>(151,690)</td></tr><tr><td>Changes in prices and costs</td><td>(302,064)</td><td>(2,452,581)</td><td>64,467</td></tr><tr><td>Previously estimated development costs incurred</td><td>66,087</td><td>295,258</td><td>424,504</td></tr><tr><td>Net changes in future development costs</td><td>46,981</td><td>456,726</td><td>(10,774)</td></tr><tr><td>Revisions of previous quantities</td><td>20,192</td><td>(718,932)</td><td>226,499</td></tr><tr><td>Accretion of discount</td><td>111,056</td><td>342,692</td><td>276,485</td></tr><tr><td>Changes in production rates and other</td><td>(31,727)</td><td>40,094</td><td>(271,656)</td></tr><tr><td>End of year</td><td>$ 803,517</td><td>$ 1,110,565</td><td>$ 3,256,370</td></tr></table>



## SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized company subsequent to September 9, 2016. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the reorganized company prior to, and including, September 9, 2016.

The following table presents selected quarterly financial data derived from the Company's unaudited consolidated interim financial statements. The following data is only a summary and should be read with the Company's historical consolidated financial statements and related notes contained in this document (in thousands, except per share amounts).

<table><tr><td rowspan="2"></td><td colspan="3">Predecessor</td><td colspan="3">Successor</td></tr><tr><td>Quarter Ended March 31</td><td>Quarter Ended June 30</td><td>Period from July 1, 2016 through September 9, 2016</td><td>Period from September 10, 2016 through September 30, 2016</td><td>Quarter Ended December 31</td><td></td></tr><tr><td>2016</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total operating revenues</td><td>$ 81,349</td><td>$ 106,147</td><td>$ 79,347</td><td>$ 23,107</td><td>$ 130,255</td><td></td></tr><tr><td>Income (loss) from operations</td><td>(592,384)</td><td>(261,458)</td><td>2,225</td><td>(433,725)</td><td>17,926</td><td></td></tr><tr><td>Net income (loss)</td><td>(539,999)</td><td>(374,303)</td><td>926,260</td><td>(450,692)</td><td>(28,501)</td><td></td></tr><tr><td>Net income (loss) available to common stockholders(1)</td><td>(566,862)</td><td>(382,353)</td><td>916,421</td><td>(451,483)</td><td>(28,501)</td><td></td></tr><tr><td>Net income (loss) per share of common stock:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ (4.72)</td><td>$ (3.17)</td><td>$ 7.58</td><td>$ (4.96)</td><td>$ (0.31)</td><td></td></tr><tr><td>Diluted</td><td>$ (4.72)</td><td>$ (3.17)</td><td>$ 6.06</td><td>$ (4.96)</td><td>$ (0.31)</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="5">Predecessor</td></tr><tr><td>March 31</td><td>June 30</td><td>September 30</td><td>December 31</td><td></td></tr><tr><td>2015</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total operating revenues</td><td>$ 136,194</td><td>$ 168,024</td><td>$ 129,939</td><td>$ 116,121</td><td></td></tr><tr><td>Income (loss) from operations</td><td>(626,169)</td><td>(954,387)</td><td>(528,685)</td><td>(635,265)</td><td></td></tr><tr><td>Net income (loss)</td><td>(587,641)</td><td>(1,088,612)</td><td>147,075</td><td>(393,443)</td><td></td></tr><tr><td>Net income (loss) available to common stockholders(2)</td><td>(601,193)</td><td>(1,104,581)</td><td>123,528</td><td>(424,712)</td><td></td></tr><tr><td>Net income (loss) per share of common stock:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Diluted</td><td>$ (7.16)</td><td>$ (10.13)</td><td>$ 1.05</td><td>$ (3.56)</td><td></td></tr><tr><td></td><td>$ (7.16)</td><td>$ (10.13)</td><td>$ 0.88</td><td>$ (3.56)</td><td></td></tr></table>

(1) The volatility in "Net income (loss) available to common stockholders" is substantially due to a) the Company's reorganization and associated fresh-start accounting, (b) the Company's full cost ceiling impairments, c) the gains on the extinguishment of debt and d) the



Company's realized and unrealized gains and losses on its derivative contracts. See footnotes for additional information.

(2) The volatility in "Net income (loss) available to common stockholders" is substantially due to a) the Company's full cost ceiling impairments, b) the gains on the extinguishment of debt and c) the Company's realized and unrealized gains and losses on its derivative contracts. See footnotes for additional information.



## ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

## ITEM 9A. CONTROLS AND PROCEDURES

## Management's Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(f) and 15d-15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

## Management's Report on Internal Control over Financial Reporting

Management has assessed, and our independent registered public accounting firm, Deloitte & Touche LLP, has audited, our internal control over financial reporting as of December 31, 2016. The unqualified reports of management and Deloitte & Touche LLP thereon are included in Item 8. Consolidated Financial Statements and Supplementary Data of this Annual Report on Form 10-K and are incorporated by reference herein.

## Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the three months ended December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

## ITEM 9B. OTHER INFORMATION

None.



## PART III

## ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

## The Board of Directors

Our business and affairs are managed under the direction of our board of directors, or board. Our bylaws specify that we shall not have less than one nor more than fifteen directors, and our board currently has nine members. Under our bylaws and our certificate of incorporation, each director holds office until the next annual meeting of stockholders at which such director's class stands for re-election and serves until the director's successor is duly elected and qualified, or until such director's earlier death, resignation or removal. Our certificate of incorporation provides that our board is classified into three classes: Class A, Class B and Class C, each class having a three-year term of office.

On July 27, 2016, the Company and certain of its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the "Bankruptcy Court") to pursue a joint prepackaged plan of reorganization (the "Reorganization Plan"). On September 8, 2016, the Bankruptcy Court entered an order confirming the Reorganization Plan and on September 9, 2016, the Plan became effective (the "Reorganization Plan Effective Date") and the Company emerged from chapter 11 bankruptcy. We refer to this transaction as the "Reorganization."

In connection with the Reorganization and in accordance with the Reorganization Plan, upon the Reorganization Plan Effective Date, Floyd C. Wilson, William J. Campbell, James W. Christmas, Michael L. Clark, Thomas R. Fuller, Darryl L. Schall, Ronald D. Scott, Eric G. Takah and Nathan W. Walton, were appointed as directors.

The following table sets forth the names and ages of all of our current directors, the positions and offices with us held by such persons, the years in which their current terms as directors expire and the length of their continuous service as a director:

<table><tr><td>Name</td><td>Director Since</td><td>Age</td><td>Position</td><td>Expiration of Term</td></tr><tr><td>Floyd C. Wilson</td><td>Feb. 2012</td><td>70</td><td>Chairman of the Board, Chief Executive Officer and President</td><td>2017</td></tr><tr><td>William J. Campbell</td><td>Sep. 2016</td><td>58</td><td>Director</td><td>2018</td></tr><tr><td>James W. Christmas</td><td>Feb. 2012</td><td>68</td><td>Lead Director</td><td>2018</td></tr><tr><td>Michael L. Clark</td><td>Sep. 2016</td><td>45</td><td>Director</td><td>2018</td></tr><tr><td>Thomas R. Fuller</td><td>Feb. 2012</td><td>69</td><td>Director</td><td>2017</td></tr><tr><td>Darryl L. Schall</td><td>Sep. 2016</td><td>56</td><td>Director</td><td>2019</td></tr><tr><td>Ronald D. Scott</td><td>Sep. 2016</td><td>58</td><td>Director</td><td>2018</td></tr><tr><td>Eric G. Takah.</td><td>Sep. 2016</td><td>50</td><td>Director</td><td>2019</td></tr><tr><td>Nathan W. Walton</td><td>Sep. 2016</td><td>39</td><td>Director</td><td>2019</td></tr></table>

Floyd C. Wilson has served as Chairman, Chief Executive Officer and President since February 2012. Mr. Wilson served as Chairman of the Board and Chief Executive Officer of Petrohawk Energy Corporation from May 2004 until BHP Billiton acquired Petrohawk in August 2011. Mr. Wilson also served as President of Petrohawk from May 2004 until September 2009. Mr. Wilson was the Chairman and Chief Executive Officer of 3TEC Energy Corporation from August 1999 until its merger with Plains Exploration & Production Company in June 2003. Mr. Wilson founded W/E Energy Company L.L.C., formerly known as 3TEC Energy Company L.L.C. in 1998 and served as its President until August 1999. Mr. Wilson began his career in the energy business in Houston, Texas in 1970 as a completion engineer. He moved to Wichita, Kansas in 1976 to start an oil and gas operating company, one of several private energy ventures which preceded the formation of Hugoton Energy Corporation in 1987, where he served as Chairman, President and Chief Executive Officer. In 1994, Hugoton



completed an initial public offering and was merged into Chesapeake Energy Corporation in 1998. Mr. Wilson's qualifications to serve on the board include his role as the Company's Chief Executive Officer and President, his extensive technical experience and wealth of knowledge in the energy industry as well as his many years of service in a leadership role, as a director, chief executive officer and president of oil and natural gas exploration and production companies provide significant contributions to the Company's board.

William J. Campbell has served as a director since the Reorganization in September 2016 and currently serves as Chairman of the Compensation Committee and as a member of the Nominating and Corporate Governance Committee. Mr. Campbell is the Managing Director and Co-owner of CB Energy, LLC, an independent oil and gas exploration company founded in 1997. He has over thirty two years of experience in the legal, investment and energy industries with a diverse background in management, finance, legal, land and marketing. Since 2006, Mr. Campbell has served as owner and managing director of PPPCo-CB Energy, LLC, a Houston, Texas-based private oil and gas exploration and production company. From 1991 to 1996, Mr. Campbell served as Principal, Vice President and Corporate Counsel of Houston, Texas-based Fremont Energy Corporation, a Bechtel Family company, where Mr. Campbell managed the company's domestic and international energy asset portfolio and directed the company's commercial, banking, and legal activities, and from 1985 through 1991, Mr. Campbell served as Counsel and Manager for Bechtel Investments, Inc. in Houston, Texas, managing its oil and gas marketing and land/legal operations. Mr. Campbell was also the first representative of Bechtel in the J.P. Morgan Corporate Finance Program, New York, New York (1988). In addition, Mr. Campbell represented Bechtel's outside oil and gas interests by serving as a Director on the boards of BeCField Drilling Services, the then largest independent horizontal and directional drilling company in the United States, CurveDrill, Inc. and PetroSource Corporation, a refining and marketing company with annual revenues over $500 million. Mr. Campbell started his professional career at the Houston, Texas law firm of Reynolds, Allen & Cook. Mr. Campbell has a Doctorate of Jurisprudence (J.D.) and holds a Bachelor of Business Administration Degree (BBA) in Petroleum Land Management/Finance from the University of Texas in Austin, Texas. Mr. Campbell is active in community and civic affairs. His service includes: The Kinkaid School Board of Trustees of Houston since 2007, and its Advancement, Finance & Building Committees since 2002; the Board of Directors of the Houston Country Club from 2005 to 2007; the Institute for Molecular Medicine as a Founding Trustee and Scientific Advisory Board Member since 2001; the Development Board of the University of Texas Health Science Center since 1991- Chair Emeritus 2002-2003; the Advisory Boards of Tanglewood Bank, NA and the Amegy Bank of Texas, N.A. since 1998; the Endowment Board, Jr. Warden and Senior Council Representative of St. Martin's Episcopal Church since 2004; the Board of Directors and Treasurer of the Daniel and Edith Ripley Foundation since 2005; the Board of Directors of the Bayou City Pump Inc. since 2010; the Board of Directors of Erin Energy Corporation and its Audit and Compensation Committees since 2011; the Advance Team Board of M.D. Anderson since 2005; the Texas Children's Hospital Individuals Committee since 2005; the Memorial Hermann System Board of Directors and its Finance and Chairman-Govenance Committees and Memorial Hermann Foundation since 2011 and a Member of the Texas Bar Association. Mr. Campbell's qualifications to serve on the board include over thirty years of experience in the legal, investment and energy industries, management of domestic and international energy asset portfolios and extensive professional background provide valuable contributions to the Company's board.

James W. Christmas has served as a director since February 2012 and currently serves as Lead Independent Director, a position he has held since January 2015, as Chairman of the Audit Committee and as a member of the Compensation Committee. Mr. Christmas began serving as a director of Petrohawk Energy Corporation on July 12, 2006, effective upon the merger of KCS Energy, Inc. ("KCS") into Petrohawk. He continued to serve as a director, and as Vice Chairman of the Board of Directors, for Petrohawk until BHP Billiton acquired all of Petrohawk in August 2011. He also served on the Audit Committee and the Nominating and Corporate Governance Committee. Mr. Christmas



served as a member of the Board of Directors of Petrohawk, a wholly-owned subsidiary of BHP Billiton, and as chair of the Financial Reporting Committee of such board until September 2014. He also serves on the Advisory Board of the Tobin School of Business of St. John's University. Mr. Christmas serves as a director of Rice Energy, as chairman of its audit committee and a member of its compensation committee, and as a director, chairman of the audit committee and a member of the nominating committee of Yuma Energy. He served as President and Chief Executive Officer of KCS from 1988 until April 2003 and Chairman of the Board and Chief Executive Officer of KCS until its merger into Petrohawk. Mr. Christmas was a Certified Public Accountant in New York and was with Arthur Andersen & Co. from 1970 until 1978 before leaving to join National Utilities & Industries ("NUI"), a diversified energy company, as Vice President and Controller. He remained with NUI until 1988, when NUI spun out its unregulated activities that ultimately became part of KCS. As an auditor and audit manager, controller and in his role as CEO of KCS, Mr. Christmas was directly or indirectly responsible for financial reporting and compliance with SEC regulations, and as such has extensive experience in reviewing and evaluating financial reports, as well as in evaluating executive and board performance and in recruiting directors. Mr. Christmas's qualifications to serve on the board include his experience as an executive, service as director and committee member combined with his extensive audit, accounting and financial reporting experience provide significant contributions to the Company's board.

Michael L. Clark has served as a director since the Reorganization in September 2016 and currently serves as Chairman of the Nominating and Corporate Governance Committee and as a member of the Audit Committee and Compensation Committee. Mr. Clark is a Chartered Financial Analyst (CFA) Charterholder with over seventeen years of investing experience focusing on basic materials and oilfield services and equipment equities. Mr. Clark was a Retired Partner of SIR Capital Management, LLC from 2014 until his departure in 2016 and from 2008 to 2013 served as a Portfolio Manager and Partner. Prior to that, Mr. Clark valued energy equities as a Portfolio Manager at Satellite Asset Management, LLC from 2005 to 2007 and as an Equity Research Analyst at SAC Capital Management, LLC from 2003 to 2005 and at Merrill Lynch from 1997 to 2002. Mr. Clark began his career at Deloitte & Touche, LLP, progressing to Senior Auditor within its Securities Industry Auditing Group and is a Certified Public Accountant licensed in New York State. He graduated cum laude from the University of Pennsylvania with a Bachelor of Arts in Economics and earned a Masters of Business Administration in Finance and Economics with Distinction (Top 10%) from New York University's Stern School of Business. Mr. Clark's qualifications to serve on the board include his wealth of accounting, financial and investment knowledge and experience in the energy industry provide significant contributions to the Company's board.

Thomas R. Fuller has served as a director since February 2012 and currently serves as Chairman of the Reserves Committee and as a member of the Nominating and Corporate Governance Committee. Mr. Fuller served as a director at Petrohawk Energy Corporation from March 6, 2006 until BHP Billiton acquired Petrohawk in August 2011. Mr. Fuller served on Petrohawk's Reserves Committee and was the Chairman of the Nominating and Corporate Governance Committee. Since December 1988, Mr. Fuller has been a principal of Diverse Energy Management Co. (or related "Diverse" companies), a private upstream acquisition, drilling and production company which also invests in other energy-related companies. Mr. Fuller has earned degrees from the University of Wyoming and the Louisiana State University School of Banking of the South and is a Registered Professional Engineer in Texas. He has 48 years of experience as a petroleum engineer, specializing in economic and reserves evaluation. He has served as an employee, officer, partner or director of various companies, including ExxonMobil, First City National Bank, Hillin Oil Co., Diverse Energy Management Co. and Rimco Royalty Partners. In February 2015, Mr. Fuller became a director of Azure Midstream Partners LP and serves as a member of its Audit Committee. Mr. Fuller also serves as a director of privately held Azure Midstream Holdings. Mr. Fuller also has extensive experience in energy-related merger and acquisition transactions, having generated and closed over 90 producing



property acquisitions during his career. As a primary lending officer to many independent energy companies, Mr. Fuller has extensive experience in analyzing and evaluating financial, business and operational strategies for energy companies. Mr. Fuller's qualifications to serve on the board include decades of petroleum engineering, energy-related acquisitions and analytical experience and experience in energy company reserve evaluations provide significant contributions to the Company's board.

Darryl L. Schall has served as a director since the Reorganization in September 2016 and currently serves as a member of the Nominating and Corporate Governance Committee. Mr. Schall is currently an advisor to Ares Management LLC. Mr. Schall previously served as a Partner and Portfolio Manager in the Ares Private Equity Group, where he was responsible for managing Ares' special situations strategy until his retirement in January 2017. Prior to joining Ares in 2009, Mr. Schall worked at Tudor Investment Corporation, where he focused on managing distressed and high yield investments. Previously, Mr. Schall was a Managing Director and Director of High Yield Research at Trust Company of the West, where he focused on managing portfolios of distressed and high yield debt. In addition, Mr. Schall was a Senior Research Analyst and Senior Vice President at Dabney/Resnick & Wagner, Inc., a boutique investment firm specializing in high yield and distressed debt. Previously, Mr. Schall was an Investment Banking Associate of the Corporate Finance Department of Drexel Burnham Lambert Inc. and was a Supervising Senior Accountant with KPMG Peat Marwick. Mr. Schall holds a B.A., cum laude, from the University of California, Los Angeles, in History and an M.B.A. from the University of Chicago. Mr. Schall also is a Certified Public Accountant. Mr. Schall's qualifications to serve on the board include his vast experience managing investment portfolios and extensive knowledge financial and accounting matters provide valuable contributions to the Company's board.

Ronald D. Scott has served as a director since the Reorganization in September 2016 and currently serves as a member of the Reserves Committee. Mr. Scott has over thirty years oil and gas industry experience. Most recently, from 2013 to 2016, Mr. Scott served as President and CEO of True Oil Company, a private equity backed oil and gas firm. Prior to that, from 1996 to 2012, he served as President and Chief Operating Officer of Midland, Texas-based Henry Petroleum and its successor companies, Henry Resources and HPC Energy. During this time, Mr. Scott successfully led the sale and re-start of multiple companies. Beginning his career with Exxon Corporation, from 1983 to 1995, Mr. Scott held various supervisory and managerial assignments in Engineering, Operations, Planning and Financial Accounting and Reporting. In addition to the Permian Basin, he had assignments covering operational areas in the Gulf Coast/Gulf of Mexico region, California and the Rocky Mountains. Mr. Scott was the Technical Manager for Exxon's multi-billion dollar onshore operations in the Western United States and prior to joining Henry Petroleum. Mr. Scott serves as a Director of Blackbrush Oil and Gas and Pardus Oil and Gas and as the Vice President of the Board of the Henry Foundation, a founding member of Educate Midland and on the Chamber of Commerce. Mr. Scott holds Master and Bachelor of Science degrees in Engineering from New Mexico State University and is a Registered Petroleum Engineer in the State of Texas. Mr. Scott's qualifications to serve on the board include his more than thirty years in the oil and gas industry, leadership experience and technical expertise as a petroleum engineer provide significant contributions to the Company's board.

Eric G. Takahaa has served as a director since the Reorganization in September 2016 and currently serves as a member of the Audit Committee. Prior to his retirement in 2016, Mr. Takahaa served as a Portfolio Manager, Senior Vice President and Director of the Corporate and High Yield Group at Franklin Templeton Investments. He also served as a member of the firm's Fixed Income Policy Committee, which helped guide investment strategies for multi-sector fixed income accounts. At Franklin Templeton Investments, Mr. Takahaa managed multiple fixed income portfolios, with a focus on those with corporate credit investments, as well as overseeing and directing the firm's group of high yield and investment grade credit analysts as they formulated investment recommendations. He originally joined Franklin Templeton Investments in 1989, and served as a research analyst covering a



number of different industries. Mr. Takaha currently serves as Treasurer and on the Board of the Redwood City Educational Foundation, on the Finance Committee for Make A Wish (San Francisco), on the Investment Sub-Committee for Catholic Charities (San Francisco) and as a mentor in the Friends for Youth organization. He received his B.S. from the University of California Berkeley in 1989 and his M.B.A from Stanford University in 1996. Mr. Takaha is a Chartered Financial Analyst (CFA) Charterholder since 1993 and serves as a member of the CFA Society of San Francisco, the CFA Institute and the Standard Business School Alumni Association. Mr. Takaha's qualifications to serve on the board include his extensive experience overseeing investment strategies, expertise in financial matters and knowledge of financial markets provide valuable contributions to the Company's board.

Nathan W. Walton has served as a director since the Reorganization in September 2016 and currently serves on the Reserves Committee. Mr. Walton is a Partner in the Ares Private Equity Group and joined the firm in 2006. Additionally, he serves on the Investment Committee for Ares EIF funds. Mr. Walton has experience managing investments in, and serving on the Boards of Directors of, companies operating in various industries, including in the oil and natural gas exploration and production industry. Currently, Mr. Walton serves on the Boards of Directors of Clayton Williams Energy, Inc. and the parent company of BlackBrush Oil & Gas, L.P. Mr. Walton holds a B.A. from Princeton University in Politics and an M.B.A. from the Stanford Graduate School of Business. Mr. Walton's qualifications to serve on the board include vast knowledge of the oil and natural gas exploration and production industry, his directorship experience and investment expertise in the energy industry provide significant contributions to the Company's board.

## Meetings of Our Board of Directors and Committees of the Board

Our board of directors has the responsibility for establishing our broad corporate policies and for our overall performance. However, the board is not involved in our day-to-day operations. The board is kept informed of our business through discussions with our Chairman and Chief Executive Officer and other officers, by reviewing analyses and reports provided to it on a regular basis, and by participating in board and committee meetings. Our board held 11 meetings during 2016, including telephonic meetings, and acted by unanimous written consent 7 times, and all directors attended at least 75% of the total meetings of the board and the committees on which such director served during the fiscal year.

Our board currently has four standing committees: Audit, Compensation, Nominating and Corporate Governance, and Reserves. Actions taken by our committees are reported to the full board. Each committee conducts an annual evaluation of its duties and is expected to conduct an annual review of its charter. Each committee has authority to retain, set the compensation for, and terminate consultants, outside counsel and other advisers as that committee determines to be appropriate.

Audit Committee. The members of our Audit Committee are James W. Christmas, Michael L. Clark and Eric G. Takaha, with Mr. Christmas serving as the chairman. Our board has determined that all members of our Audit Committee are financially literate within the meaning of SEC rules, under the current listing standards of the NYSE and in accordance with our audit committee charter. Our board has also determined that all members of the Audit Committee are independent, within the meaning of SEC and NYSE regulations for independence for audit committee members, under our corporate governance guidelines, and in accordance with our audit committee charter. The board has also determined that each member of the Audit Committee is an "audit committee financial expert" (as defined under SEC rules) because each possesses: (i) an understanding of generally accepted accounting principles in the United States of America and financial statements; (ii) the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; (iii) experience analyzing and evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by our financial statements; (iv) an understanding



of internal control over financial reporting; and (v) an understanding of audit committee functions. Each of Messrs. Christmas, Clark and Takaha has acquired these attributes by his educational background and by having held various positions that provided relevant experience, as described in his biographical information under "The Board of Directors" above.

The Audit Committee is responsible for oversight of Company risks relating to accounting matters, financial reporting and related legal and regulatory compliance. The Audit Committee annually considers the qualifications and evaluates the performance of our independent auditor and selects and engages our independent auditor. The Audit Committee meets quarterly with representatives of the independent auditor and is available to meet at the request of the independent auditor. During these meetings, the Audit Committee receives reports regarding our books of accounts, accounting procedures, financial statements, audit policies and procedures, internal accounting and financial controls, and other matters within the scope of the Audit Committee's duties. The Audit Committee reviews the plans for and the results of audits for us and our subsidiaries. The Audit Committee reviews the independence of the independent auditor, and considers and authorizes the fees for both audit and non-audit services provided by the independent auditor. In 2016, our Audit Committee held 4 meetings.

Compensation Committee. The members of our Compensation Committee are William J. Campbell, James W. Christmas and Michael L. Clark, with Mr. Campbell serving as the chairman. Our board has determined that each member of the Compensation Committee meets the NYSE standards for independence, and is a "non-employee director" as defined in Rule 16b-3 under the Exchange Act, an "outside director" as defined for purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended, and the enhanced independence requirements set forth in Rule 10C-1 under the Exchange Act.

The Compensation Committee is entrusted with the overall responsibility for establishing, implementing and monitoring the compensation for our executive officers (our chief executive officer and president, each executive vice president, and each senior vice president). The Compensation Committee also administers our 2016 Long-Term Incentive Plan, or Plan, and approves restricted stock, stock option, and performance awards and other stock-based grants for our executive officers. In 2016, our Compensation Committee held 6 meetings, including telephonic meetings and acted by unanimous written consent one time.

Our Compensation Committee engaged Longnecker & Associates, Inc. ("Longnecker"), an outside independent compensation consulting firm, to assist the board and the Compensation Committee in crafting our total compensation program for our executive officers for 2016 and to assist the board in determining compensation for our non-employee directors. In connection with its engagement, Longnecker was tasked with, among other things, making recommendations to the Compensation Committee regarding an appropriate compensation peer group, assisting the Compensation Committee in establishing a competitive executive compensation program and making recommendations and providing analysis regarding the compensation of our executive officers, including the named executive officers, discussed below under the heading "Executive Compensation."

Nominating and Corporate Governance Committee. The members of our Nominating and Corporate Governance Committee are William J. Campbell, Michael L. Clark, Thomas R. Fuller and Darryl L. Schall, with Mr. Clark serving as the chairman. Our board has determined that all members of the Nominating and Corporate Governance Committee are independent pursuant to the NYSE rules, under our corporate governance guidelines, and in accordance with our nominating and corporate governance committee charter.

Our Nominating and Corporate Governance Committee is responsible for identifying qualified candidates to be presented to our board of directors for nomination as directors, ensuring that our board of directors and our organizational documents are structured in a way that best serves our



practices and objectives, and developing and recommending a set of corporate governance principles. The Nominating and Corporate Governance Committee may consider candidates for our board of directors from any reasonable source, including a search firm engaged by the Nominating and Corporate Governance Committee, recommendations of the board of directors, management or, in accordance with the procedures set forth in our bylaws, our stockholders. In 2016, our Nominating and Corporate Governance Committee held 4 meetings, including telephonic meetings and acted by unanimous written consent 3 times.

Reserves Committee. The members of our Reserves Committee are Thomas R. Fuller, Ronald D. Scott and Nathan W. Walton, with Mr. Fuller serving as the chairman. Our Reserves Committee is composed solely of non-employee directors who are independent under our corporate governance guidelines and in accordance with our reserves committee charter. Our Reserves Committee assists our board with oversight in the preparation by independent petroleum engineers of annual and any special reserve reports and/or audits of the estimated amounts of our consolidated hydrocarbon reserves and related information. The Reserves Committee selects, engages and determines funding for the independent petroleum engineers who evaluate our hydrocarbon reserves and also determines their independence from the Company in accordance with, among other things, the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. In 2016, our Reserves Committee held 5 meetings, including telephonic meetings.

## Corporate Governance Matters

Corporate Governance Web Page and Available Documents. We maintain a corporate governance page on our website at www.halcomresources.com where you can find the following documents:

• our corporate governance guidelines;

• our code of ethics;

• our code of conduct;

• our insider trading policy and guidelines with respect to certain transactions in Company securities; and

• the charters of our Audit, Compensation, Nominating and Corporate Governance, and Reserves Committees.

Notwithstanding any reference to our website contained in this report, the information you may find on our website is not part of this report. We will also provide a printed copy of these documents, without charge, to stockholders who request copies in writing from Quentin R. Hicks, Senior Vice President, Finance & Investor Relations, Halcón Resources Corporation, 1000 Louisiana St., Suite 6700, Houston, Texas 77002.

Nomination Process. The Nominating and Corporate Governance Committee will consider stockholder nominees for election as directors. Any stockholder nominations must be received by us not less than sixty (60) days nor more than ninety (90) days prior to the annual meeting; provided however, that in the event that less than seventy (70) days notice or prior public disclosure of the date of the meeting is given or made to stockholders, notice by the stockholder, to be timely, must be received no later than the close of business on the tenth (10th) day following the day on which such notice of the date of the meeting was mailed or such public disclosure was made, whichever first occurs. Nominations should be delivered to the Nominating and Corporate Governance Committee at the following address: Halcón Resources Corporation Nominating and Corporate Governance Committee, c/o Halcón Resources Corporation, Attention: Corporate Secretary, 1000 Louisiana St., Suite 6700, Houston, Texas 77002. The stockholder's nomination notice must set forth: (i) as to each person whom the stockholder proposes to nominate for election or re-election as a director: (a) the



name, age, business address and residence address of the person; (b) the principal occupation or employment and business experience of the person for at least the previous five years; (c) the class and number of shares of our capital stock which are beneficially owned by the person; and (d) any other information relating to the person that is required to be disclosed in solicitations for proxies for election of directors pursuant to the rules and regulations of the SEC under Section 14 of the Exchange Act; and (ii) as to the stockholder giving the notice: (a) the name and record address of the stockholder; and (b) the class and number of shares of our capital stock beneficially owned by the stockholder. Such submission must be accompanied by the written consent of the proposed nominee to be named as a nominee and to serve as a director, if elected. We may require any proposed nominee to furnish such other information as may reasonably be required by us to determine the eligibility of such proposed nominee to serve as a director.

In considering possible candidates for election as a director, the Nominating and Corporate Governance Committee is guided by the principles that each director should be an individual of high character and integrity and have:

• independence;

• wisdom;

• an understanding and general acceptance of our corporate philosophies;

• business or professional knowledge and experience that can address our challenges and opportunities, and contribute meaningfully to the deliberations of our board of directors;

• a proven record of accomplishment with an excellent organization;

• an inquiring mind;

• a willingness to speak one's mind;

• an ability to challenge and stimulate management; and

• a willingness to commit time and energy to our business affairs.

In addition to considering possible candidates for election as directors, the Nominating and Corporate Governance Committee may, in its discretion, review the qualifications and backgrounds of existing directors and other nominees (without regard to whether a nominee has been recommended by stockholders), as well as the overall composition of our board, and recommend the slate of directors to be nominated for election at the ensuing annual meeting of stockholders. Currently, we do not employ or pay a fee to any third party to identify or evaluate, or assist in identifying or evaluating, potential director nominees.

The charter of our Nominating and Corporate Governance Committee provides that the Committee will evaluate our corporate governance effectiveness and recommend such revisions as it deems appropriate to improve our corporate governance. The areas of evaluation may include such matters as the size and independence requirements of our board of directors, board committees, management succession and planning, and regular meetings of our non-employee directors without management in executive sessions.

Board Diversity. Our board does not have a formal written policy with regard to the consideration of diversity in identifying director nominees. Our Nominating and Corporate Governance Committee charter, however, requires the committee to review the composition of the board as a whole and recommend, if necessary, measures to be taken so that our board not only contains the required number of independent directors, but also reflects the balance of knowledge, experience, skills, expertise, integrity, analytical ability and diversity as a whole that the committee deems appropriate. This review includes an assessment as to our board's current and anticipated need for directors with



specific qualities, skills, experience or backgrounds; the availability of highly qualified candidates; committee workloads and membership needs; and anticipated director retirements.

Leadership Structure. Our board currently combines the role of Chairman with the role of Chief Executive Officer, or CEO, and maintains a separate empowered lead independent director position ("Lead Director") to further strengthen our governance structure. Our board believes this provides an efficient and effective leadership model for the Company. Combining the Chairman and CEO roles fosters clear accountability, effective decision-making and alignment on corporate strategy while reducing the potential for fractured leadership that can undermine successful implementation of policy.

Our board believes that the Company is strengthened by the chairmanship of Mr. Wilson, who provides strategic, operational and technical expertise, vision and a proven ability to lead the Company. Our board believes that, under present circumstances, the interests of the Company and its stockholders are best served by the leadership and direction of Mr. Wilson as Chairman, CEO and President. Our board recognizes that no single leadership model is right for all companies and at all times and that, depending on the circumstances, other leadership models, such as a separate independent chairman of the board, might be appropriate.

Mr. James W. Christmas, who is an independent and non-management director, has served as our Lead Director since January 21, 2015. A Lead Director is elected annually by our board and serves as a key component of our governance structure, subject to oversight by the independent members of our board. The Lead Director's responsibilities and authority generally include:

• presiding over all executive sessions of the independent directors and all other board meetings at which the Chairman is not present;

• calling special meetings of the independent directors when necessary and appropriate;

• coordinating the agenda for, and moderating sessions of, the board's independent directors;

• serving as a liaison between the Chairman and the independent directors;

• consulting with the Chairman regarding specific agenda items and additional materials for board meetings suggested by independent board members;

• approving the scheduling of regular and, where feasible, special meetings of the board to ensure that there is sufficient time for discussion of all agenda items;

• facilitating communications among the other members of the board;

• consulting with the chairs of the board committees and soliciting their participation to avoid diluting their authority or responsibilities; and

• performing other duties as the board may from time to time delegate.

Our corporate governance guidelines currently provide that non-management directors must meet at regularly scheduled executive sessions without management. Mr. Christmas, as Lead Director, presided over the executive sessions of our non-management directors during 2016. During 2016, our non-management directors held 4 executive sessions without management present, and Mr. Christmas presided over each executive session.

Risk Oversight. It is the job of our CEO and President, Chief Financial Officer, Chief Legal Officer, and other members of our senior management to identify, assess, and manage our exposure to risk. In conjunction with our risk oversight program, senior management has retained outside consultants to assist in identifying, assessing, analyzing and developing plans to mitigate enterprise risks. Our board plays an important role in overseeing management's performance of these functions. Our board has approved the charter of its Audit Committee, which lists the primary responsibilities of the Audit Committee. Those responsibilities require the Audit Committee to discuss with management our



major financial risk exposures and the steps management has taken to monitor and control such exposures, including the substance of any significant litigation, contingencies or claims that had, or may have, a significant impact on the financial statements. The Audit Committee is also required to discuss with management and review the mechanisms, guidelines and policies that govern the processes by which risk assessment and management are undertaken.

Each of the board's other committees also oversees the management of risks that fall within such committee's area of responsibility. Our Compensation Committee incorporates risk considerations, including the risk of loss of key personnel, as it evaluates the performance of our CEO and President and other executive officers, reviews management development and determines compensation structure and amounts. Our Nominating and Corporate Governance Committee focuses on issues and risks relating to board composition, leadership structures, succession planning and corporate governance matters. The focus of our Reserves Committee is on the integrity of the process of selecting our independent petroleum engineers and whether reports prepared by our independent petroleum engineers are prepared in accordance with the accepted or required petroleum engineering standards.

Our board receives reports from its committees regarding the risks considered in their respective areas to ensure that our board has a broad view of our strategy and overall risk management process. In performing its risk oversight function, each committee has full access to management, as well as the ability to engage advisors. Each committee's charter is available on our website at www.halconresources.com.

Communications with Directors. Our board welcomes communications from our stockholders and other interested parties. Stockholders and any other interested parties may send communications to our board, to any committee of our board, to the Lead Director, or to any director in particular to: c/o Halcón Resources Corporation, Attention: Corporate Secretary, 1000 Louisiana St., Suite 6700, Houston, Texas 77002. Any correspondence addressed to our board, to any committee of our board, to the Lead Director, or to any one of the directors in care of our offices is required to be forwarded to the addressee or addressees without review by any person to whom such correspondence is not addressed.

Directors' Attendance at Stockholder Meetings. Our corporate governance guidelines provide that our directors are encouraged, but not required, to attend annual meetings of our stockholders.

## Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers and persons who beneficially own more than 10% of our common stock to file certain reports with the SEC concerning their beneficial ownership of our equity securities. The SEC's regulations also require that a copy of all such Section 16(a) forms filed must be furnished to us by the executive officers, directors and greater than 10% stockholders. To our knowledge based solely on a review of copies of reports filed under Section 16(a) during the 2016 fiscal year and furnished to us, our directors, executive officers and holders of 10% or more of our shares timely filed reports required by Section 16(a).

## Code of Conduct and Code of Ethics

The Company's Code of Conduct and Code of Ethics for the Chief Executive Officer and Senior Financial Officers can be found on the Company's website located at www.halconresources.com. Any stockholder may request a printed copy of such materials by submitting a written request to the Company's Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least twelve months after the initial disclosure of such waiver.



## Management

The following table sets forth the names and ages of all of our executive officers, the positions and offices with us currently held by such persons and the months and years in which continuous service began:

<table><tr><td>Name</td><td>Executive Officer Since</td><td>Age</td><td>Position</td></tr><tr><td>Floyd C. Wilson</td><td>Feb. 2012</td><td>70</td><td>Chairman of the Board, Chief Executive Officer and President</td></tr><tr><td>Stephen W. Herod</td><td>May 2012</td><td>57</td><td>Executive Vice President, Corporate Development</td></tr><tr><td>Mark J. Mize</td><td>Feb. 2012</td><td>45</td><td>Executive Vice President, Chief Financial Officer and Treasurer</td></tr><tr><td>David S. Elkouri</td><td>May 2012</td><td>63</td><td>Executive Vice President and Chief Legal Officer</td></tr><tr><td>Jon C. Wright</td><td>May 2012</td><td>47</td><td>Executive Vice President, Operations</td></tr><tr><td>Quentin R. Hicks</td><td>Aug. 2013</td><td>42</td><td>Senior Vice President, Finance and Investor Relations</td></tr><tr><td>Leah R. Kasparek</td><td>May 2012</td><td>47</td><td>Senior Vice President, Human Resources and Administration</td></tr><tr><td>Tina S. Obut</td><td>Feb. 2013</td><td>52</td><td>Senior Vice President, Corporate Reserves</td></tr><tr><td>Joseph S. Rinando, III</td><td>May 2012</td><td>45</td><td>Senior Vice President, Chief Accounting Officer and Controller</td></tr></table>

Our executive officers are appointed to serve until the meeting of the board of directors following the next annual meeting of stockholders and until their successors have been elected and qualified. The following paragraphs contain certain information about each of our executive officers other than Mr. Wilson, whose biographical information is included under the heading "The Board of Directors" above.

Stephen W. Herod has served as our Executive Vice President, Corporate Development since September 9, 2016, having previously served as our President from May 2012. Mr. Herod served as Executive Vice President—Corporate Development and Assistant Secretary of Petrohawk Energy Corporation from August 2005 until BHP Billiton acquired Petrohawk in August 2011. Mr. Herod served as Vice President—Corporate Development of Petrohawk from May 2004 until August 2005. Prior to joining Petrohawk, he was employed by PHAWK, LLC from its formation in June 2003 until May 2004. He served as Executive Vice President—Corporate Development for 3TEC Energy Corporation from December 1999 until its merger with Plains Exploration & Production Company in June 2003 and as Assistant Secretary from May 2001 until June 2003. Mr. Herod served as a director of 3TEC from July 1997 until January 2002. Mr. Herod served as the Treasurer of 3TEC from 1999 until 2001. From July 1997 to December 1999, Mr. Herod was Vice President—Corporate Development of 3TEC. Mr. Herod served as President and a director of Shore Oil Company from April 1992 until the merger of Shore with 3TEC's predecessor in June 1997. He joined Shore's predecessor as Controller in February 1991. Mr. Herod was employed by Conquest Exploration Company from 1984 until 1991 in various financial management positions, including Operations Accounting Manager. From 1981 to 1984, Superior Oil Company employed Mr. Herod as a financial analyst. Mr. Herod has a Bachelor of Science degree in finance and management from Oklahoma State University.

Mark J. Mize has served as Executive Vice President, Chief Financial Officer and Treasurer since February 2012. Mr. Mize served as Executive Vice President—Chief Financial Officer and Treasurer of Petrohawk Energy Corporation from August 2007 until BHP Billiton acquired Petrohawk in August 2011. Mr. Mize served as the Chief Ethics Officer and Insider Trading Compliance Officer for Petrohawk until June 2009. Additionally, he served as Vice President, Chief Accounting Officer and Controller at Petrohawk from July 2005 until August 2007. Mr. Mize first joined Petrohawk in



November 2004 as Controller. Prior to working at Petrohawk, Mr. Mize was the Manager of Financial Reporting of Cabot Oil & Gas Corporation, a public oil and gas exploration company, from January 2003 to November 2004. Prior to his employment at Cabot Oil & Gas Corporation, he was an Audit Manager with PricewaterhouseCoopers LLP from 1996 to 2002. Mr. Mize is a Certified Public Accountant and has a Bachelor degree in Accounting from the University of Houston.

David S. Elkouri has served as Executive Vice President and Chief Legal Officer since April 2014. Mr. Elkouri served as Executive Vice President, General Counsel from May 2012 to April 2014. Mr. Elkouri served as Executive Vice President—General Counsel and Secretary of Petrohawk Energy Corporation from 2007 until BHP Billiton acquired Petrohawk in August 2011. He also served as Chief Ethics Officer and Insider Trading Compliance Officer of Petrohawk. From 2004 to 2007, he served as lead outside counsel for Petrohawk. Prior to that, Mr. Elkouri served as lead outside counsel for 3TEC Energy Corporation from 1999 to 2003. He also served as lead outside counsel for Hugoton Energy Corporation from 1994 to 1998. Mr. Elkouri is a co-founder of Hinkle Law Firm LLC where he practiced for 20 years prior to joining Petrohawk. Mr. Elkouri is a graduate of the University of Kansas School of Law where he served as a Research Editor of the Kansas Law Review.

Jon C. Wright has served as Executive Vice President, Operations since September 2016. Mr. Wright served as Senior Vice President, Operations from December 2014 to September 2016 and as Vice President, Operations from May 2012 to December 2014. Mr. Wright served as W. Rockies Operations Manager at Newfield Exploration from 2009 until 2012. Mr. Wright also served as Lead, Production for W. Oklahoma and Lead Drilling for Woodford Shale from 2005 until 2009. Prior to that, Mr. Wright was a Senior Drilling Engineer at BP from 2004 to 2005. He also served as Drilling Engineer from 2001 to 2004. From 1997 to 2001, he held various drilling positions for Conoco. Mr. Wright has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and a Master of Business Administration degree from Rice University.

Quentin R. Hicks has served as Senior Vice President, Finance and Investor Relations since January 2016. Mr. Hicks served as Vice President, Finance from August 2013 to January 2016. Mr. Hicks initially joined Halcoln as Director of Financial Planning in August 2012 after GeoResources merged with Halcoln. While with GeoResources, Mr. Hicks served as Director of Acquisitions and Financial Planning from 2011 to 2012. From 2004 to 2011, he worked in investment banking with Bear Stearns, Sanders Morris Harris and most recently Madison Williams, where he was a Director in their energy investment banking practice. Prior to that, Mr. Hicks worked as Manager of Financial Reporting for Continental Airlines. He began his career in 1998 working as an auditor for Ernst and Young LLP. Mr. Hicks graduated from Texas A&M University with a Bachelor of Business Administration and a Master of Science degree in accounting. In addition, he holds a Masters of Business Administration degree in finance from Vanderbilt University. Mr. Hicks is a Certified Public Accountant.

Leah R. Kasparek has served as Senior Vice President, Human Resources and Administration since December 2014. Ms. Kasparek served as Vice President, Human Resources from May 2012 to December 2014. Ms. Kasparek initially joined Halcoln as Director of Human Resources in February 2012. Prior to joining Halcoln, Ms. Kasparek held numerous HR leadership positions across multiple industries including oil and gas, utilities and manufacturing. Ms. Kasparek served as Director of Human Resources at Southwestern Energy from 2009 to January 2012. She served as Vice President of Human Resources for CenterPoint Energy from 2004 until 2008. From 1996 to 2004, Ms. Kasparek was employed by Anheuser-Busch Companies and served as Vice President of Human Resources from 2001 until 2004. Ms. Kasparek has a Bachelor of Arts degree from the University of Southwestern Louisiana and a law degree from the University of Houston Law Center.



Tina S. Obut has served as Senior Vice President, Corporate Reserves since December 2014. Ms. Obut served as Vice President, Corporate Reserves from February 2013 to December 2014. Ms. Obut served as Senior Manager of Petroleum Resources at BHP Billiton Petroleum from 2011 to 2012. Prior to that, she served as Senior Vice President, Corporate Reserves for Petrohawk Energy Corporation from 2006 until its sale to BHP Billiton in 2011. From 2004 to 2006, Ms. Obut served as Manager of Reservoir Engineering Evaluations at El Paso Production Company. In addition, she held various engineering, managerial and executive positions at Mission Resources, Ryder Scott Company and Chevron from 1989 to 2006. Ms. Obut has a Bachelor of Science degree in Petroleum Engineering from Marietta College, a Master of Science degree in Petroleum and Natural Gas Engineering from Penn State and a Master of Business Administration degree from the University of Houston. Ms. Obut is a Licensed Professional Engineer in the State of Texas (#82050).

Joseph S. Rinando, III has served as Senior Vice President, Chief Accounting Officer and Controller since December 2014. Mr. Rinando served as Vice President and Chief Accounting Officer from May 2012 to December 2014. Mr. Rinando initially joined Halcón as Director of Finance in February 2012. Mr. Rinando served as Vice President and Chief Financial Officer of Wilson Industries, a Schlumberger company, from 2010 to 2012. Prior to joining Wilson, he served as Executive Vice President and Chief Financial Officer for Foxxe Energy Services, LLC, a private-equity owned international drilling rig contractor, from 2009 to 2010. Prior to Foxxe, Mr. Rinando served as Vice President and Corporate Controller of Smith International, Inc. from 2006 until 2009 and as Director of Financial Reporting from 2003 to 2006. From 1995 to 2003, he was in the Energy Practice of PricewaterhouseCoopers, LLP, most recently as an Audit Senior Manager, serving clients focused on exploration and production, natural gas transmission, power and utilities, petrochemicals and refining, and drilling. Mr. Rinando graduated Summa Cum Laude with a Bachelor of Business Administration degree in Accounting from Lamar University and is a Certified Public Accountant in the State of Texas.

## ITEM 11. EXECUTIVE COMPENSATION

The following discussion of executive compensation contains descriptions of various employment-related agreements and employee benefit plans. These descriptions are qualified in their entirety by reference to the full text of the referenced agreements and plans, which have been filed by us as exhibits to our reports on Forms 10-K, 10-K/A, 10-Q and 8-K filed with the SEC.

## Our Compensation Policies and Process

## Our Compensation Committee

Our compensation programs for senior management are overseen by the Compensation Committee of our board. The Compensation Committee is composed entirely of independent directors. Until the Reorganization Plan Effective Date, our Compensation Committee consisted of Michael A. Vlasic (Chairman), Tucker S. Bridwell, Daniel A. Rioux and Mark A. Welsh IV. From and after the Reorganization Plan Effective Date, our Compensation Committee consisted of William J. Campbell (Chairman), James W. Christmas and Michael L. Clark.

The Compensation Committee operates pursuant to delegated authority from our board as specified in the Compensation Committee's Charter. The primary duties and responsibilities of the Compensation Committee pursuant to its charter are to establish and implement our compensation policies and programs for senior management, including the named executive officers. The Compensation Committee has the authority to select and engage the services of a compensation consultant, independent legal counsel and such other advisors as the Compensation Committee determines appropriate to carry out its functions, and has the sole authority to engage, obtain the advice of, oversee, terminate and determine funding for such independent professional advisers. A copy of the Compensation Committee charter is available on our website at www.halcomresources.com under



the section entitled "Investor Relations—Corporate Governance." The Compensation Committee also reviews and assesses the adequacy of its charter, at least annually, and recommends any proposed changes to our board for approval.

The Chairman of the Compensation Committee works with certain members of our management, including our Senior Vice President, Human Resources and Administration, to establish an agenda for each meeting of the Compensation Committee and, with the assistance of outside advisors, to prepare meeting materials. Typically our Chief Executive Officer and President, and our Senior Vice President, Human Resources and Administration, as well as outside advisors, may be invited to attend all or a portion of a Compensation Committee meeting depending on the nature of the matters to be discussed. Only members of the Compensation Committee vote on items before the Compensation Committee; however, the Compensation Committee and board often solicit the views of senior management on compensation matters, in particular as they relate to the compensation of other members of senior management.

## Our Compensation Philosophy and Program Design

Our success depends on the continued contributions of our senior management and other key employees. Our compensation program is intended to recruit, motivate and retain the talent required to successfully manage and grow our business and to achieve our short and long-term business strategy by providing compensation that is competitive in relation to our peers while fostering an atmosphere of teamwork, recognizing overall business results and individual merit, and supporting the attainment of our strategic objectives by tying the interests of senior management and key employees to those of our stockholders. The design of our compensation program is intended to provide compensation that balances short-term and long-term goals through the use of annual cash incentives and grants of long-term equity incentives; and provides a mix of fixed and at-risk compensation that is related to our overall performance and the creation of stockholder value.

Each element of compensation is reviewed and considered with the other elements of compensation to ensure that it is consistent with the objectives of both that particular element of compensation and our overall compensation program and, that individually and collectively, our compensation practices do not encourage inappropriate, unnecessary or excessive risk taking.

## Our Independent Compensation Consultant

For 2016, the Compensation Committee engaged Longnecker to advise on executive compensation and, in that capacity to, among other things, make recommendations regarding an appropriate compensation peer group, to assist the Compensation Committee in establishing a competitive executive compensation program and to make recommendations and provide analysis regarding the compensation of senior management. In accordance with the rules of the NYSE, the Compensation Committee annually considers the independence of Longnecker from Company management based upon various factors, including the magnitude of any fees the consultant received from the Company for services or products provided to the Company relative to the firm's annual gross revenues; whether the individuals that advise the Compensation Committee participate directly or by collaboration with others in the firm in the provision of any services or products to the Company; whether the consultant provided any products or services to any executive officer of the Company; and whether the individuals that advise the Compensation Committee own any Company securities. After considering these various factors, the Compensation Committee determined that Longnecker was independent of Company management during the relevant periods covered by this report. No conflicts of interest or issues involving the independence of Longnecker arose during the periods covered by this report.

Representatives of Longnecker report directly to the Compensation Committee and, in carrying out its duties, may work with our Senior Vice President, Human Resources and Administration when



preparing materials for the Compensation Committee. Longnecker attends Compensation Committee meetings, meets with the Compensation Committee independently without the presence of management and provides third-party data, analysis, advice and expertise on executive compensation and executive compensation programs. Longnecker generates reports that include a compilation of compensation data based upon our compensation peer group and particularized data for industry participants to the extent Longnecker determined that such additional data would prove useful in our compensation process. Additionally, at the direction of the Compensation Committee, Longnecker also reviews materials prepared by certain members of senior management and advises the Compensation Committee on the matters included in the materials, including the consistency of management proposals with the Committee's compensation philosophy, programs and objectives and the degree to which such proposals conformed with compensation peer group data and peer company practices. The Company relied upon this data, Longneckers' analyses of the data and its recommendations in establishing our compensation peer group, compensation programs and in establishing specific compensation amounts for our senior management, including the named executive officers. Longnecker also advises the Compensation Committee regarding terms of employment agreements negotiated with senior management.

## Our Compensation Peer Group

We review the compensation and benefit practices, as well as levels of pay, of a compensation peer group of companies selected by the Compensation Committee, with the advice and assistance of Longnecker, from U.S. onshore focused oil and natural gas exploration and development companies when considering our compensation program and the compensation that we pay senior management. With Longnecker's assistance, we annually review, evaluate and update our compensation peer group for benchmarking purposes to provide ongoing comparability for compensation purposes. Adjustments to our compensation peer group are made due to business combinations or sales of peer group companies, as well as when necessary, in the opinion of our Compensation Committee, to better reflect the companies that compete with us for management talent and share common characteristics with our business, including assets, production levels, revenues, oil and natural gas reserves and production mix, market capitalization and enterprise value.

Our compensation peer group for 2016 consisted of the following ten companies:

• SandRidge Energy, Inc.

• Sanchez Energy Corporation

• Bonanza Creek Energy, Inc.

• Stone Energy Corporation

• Resolute Energy Corporation

• Northern Oil and Gas, Inc.

• Newfield Exploration Co.

• Gulfport Energy Corporation

• Oasis Petroleum Inc.

• Magnum Hunter Resources Corporation

## Elements of Compensation

The principal elements of our executive compensation program are base salary, annual cash incentives, long-term equity incentives and post-termination severance (under certain circumstances), and other benefits and perquisites, consisting of life and health insurance benefits, a qualified 401(k) savings plan, the reimbursement of certain club dues for our Chief Executive Officer and President and our Chief Financial Officer and limited tax gross ups for life insurance, parking and country club memberships. As discussed below, in March 2016, we also paid one-time retention bonuses to senior management to retain their services through the Reorganization.

Currently, we target total compensation at approximately the 50 \( ^{th} \)  percentile of our compensation peer group but may change targets from time to time depending on various factors, including the competitive environment for talent and the recommendations of the Compensation Committee's



independent compensation consultant. Also, from time to time, the Compensation Committee will vary the mix of compensation utilized, depending upon our Compensation Committee's current view of the most efficacious method to provide incentives under current market conditions, taking into account the compensation practices of our compensation peer group and the advice of our independent compensation consultant.

With respect to annual cash incentives, our Compensation Committee typically establishes performance metrics near the beginning of each year that it utilizes as a guideline in conjunction with its determination of annual cash incentives (i.e., cash bonuses) for senior management following year-end, which may include measures relating to leverage and liquidity, operational efficiency and financial performance. As a general matter, these measures of performance collectively aggregate approximately 50% of the overall weighting that factors into annual cash incentive determinations and 50% is based on other factors the Compensation Committee deems relevant and appropriate, including individual performance. However, regardless of the relative weighting of these factors, the actual amount of any annual cash incentive award is entirely discretionary. Our Compensation Committee believes retaining discretion over the amount of such awards is necessary in light of the dynamic nature of the Company's activities, the potential for rapid changes in the business environment and the limitations inherent in quantitative measures of performance.

## Impacts of Our Reorganization on Compensation

Some aspects of the compensation of the Company's executives during 2016 were directly related to market conditions and the Company's financial position at the time. The compensation necessary to retain the management team during this time period was deliberate in order to ensure the Company had the appropriate resources to review and make appropriate strategic decisions about the reorganization and work through the reorganization in a strategic way that optimized the best results for a viable entity following emergence from chapter 11 bankruptcy. Certain aspects of the compensation structure during 2016 was of a non-recurring nature.

On March 9, 2016, the Company announced it had engaged PJT Partners as financial advisor and Weil, Gotshal & Manges, LLP as legal advisor to assist the Company in exploring opportunities to materially reduce its indebtedness while preserving liquidity. The retention of our management team while the Company considered possible scenarios to improve its balance sheet and capital structure, was critical to the potential long-term success and viability of the Company. Accordingly in March 2016, the Predecessor Compensation Committee recommended and the Predecessor board subsequently approved, a key employee retention program ("KERP") pursuant to which the Company made a one-time cash retention payment to certain executive officers and key employees. The KERP was implemented with the objective of incentivizing such executive officers and key employees to continue employment with the Company during this period of uncertainty. The KERP was formulated with the input and based on the recommendations of Longnecker, after consultation with the Company's external advisors, PJT Partners and Weil, Gotshal & Manges, LLP. Pursuant to the KERP, key employees receiving retention payments entered into a key employee retention agreement with the Company pursuant to which they agreed to continue their employment with the Company for a period of no less than twelve months from the date thereof or they will forfeit, and be required to repay, the full amount of the retention payment they receive (less any taxes withheld), provided that their employment is not terminated prior to such date by the Company without cause or by them with good reason, such as due to a material reduction in base salary or permanent relocation of their principal place of employment.

Pursuant to the terms of the Reorganization Plan, any restricted shares of common stock issued pursuant to the Halcón Resources Corporation First Amended and Restated 2012 Long-Term Incentive Plan were vested immediately prior to the Reorganization Plan Effective Date and all outstanding awards of performance shares and options were cancelled. Upon the Reorganization Plan Effective



Date, all outstanding common stock was cancelled and the holders thereof received a pro rata amount of 4% of our newly issued shares of common stock. The other 96% of our common stock issued upon our emergence went to our creditors in accordance with the Reorganization Plan. As a consequence, our senior management's equity in the reorganized company, along with all of our other pre-emergence common stockholders, was diluted substantially. The terms of the Reorganization Plan provided for 10% of our newly issued shares of common stock to be reserved for issuance as awards under a management incentive plan. On the Reorganization Plan Effective Date, the Halcón Resources Corporation 2016 Long-Term Incentive Plan was approved and adopted by our existing board and exit awards allocated as determined by the CEO were awarded in the form of restricted common stock and stock options. The awards are intended to align the interests of our key executives with those of our equity holders by providing a significant equity interest in the Company, conditioning certain equity awards upon continued employment with us and providing an "at-risk" component of compensation linked directly to increases in shareholder value.

Each of the elements of our compensation program is discussed in greater detail below.

## Base Salary

We review base salaries for our senior management annually to determine if any modification is appropriate. We consider several factors, including a comparison to base salaries paid for comparable positions in our compensation peer group, the relationship among base salaries paid within our Company and individual experience and contributions. Our intent is to fix base salaries at levels that we believe are consistent with our compensation program design objectives.

For 2016, in light of the current market conditions and the pending hiring of advisors to consider reorganization, the prior Compensation Committee determined to leave base salaries for the named executive officers unchanged from 2015.

## Annual Cash Incentives

Annual cash incentives for senior management are typically reviewed following the end of the year. Our Compensation Committee awarded annual cash incentives to Mr. Wilson, Mr. Herod and Mr. Mize in the amounts of $275,000, $165,000 and $146,667, respectively, which amounts reflected prorated awards for the period following the Reorganization Plan Effective Date through year-end.

## Long-term Incentives

Long-term incentives comprise a significant portion of an executive's compensation package. Long-term incentives are consistent with our objective of providing an "at-risk" component of compensation. Providing long-term incentive award opportunities for senior management and key employees align their interests with those of our stockholders. Historically, we have awarded grants of restricted stock, stock options and performance units, to certain members of senior management, including the named executive officers. Each of these awards is discussed in more detail below. Historically, we have utilized this combination because of the differing risk and reward characteristics of these awards. From time to time, we may utilize a different mix of these awards or utilize other forms of awards, each of which is permitted under the Plan and discussed in more detail below, depending upon the Compensation Committee's current view of the most efficacious method to provide incentives under current market conditions and taking into account the practices of our compensation peer group. The amounts granted will vary each year and are based on performance of senior management, our analysis of compensation peer group data and the total compensation package of each member of senior management, as discussed in more detail below.

The long-term incentive information related to the named executive officers during fiscal year 2016 is included in the Summary Compensation Table set forth below. Additional information on long-term



incentive awards for 2016 is shown in the Grants of Plan-Based Awards in 2016 table and the Outstanding Equity Awards at December 31, 2016 table, each of which is set forth below. As noted above, our Compensation Committee elected not to award long-term equity incentives to the named executive officers during its annual compensation review held in February 2016; however, as discussed above, exit awards were made upon the Reorganization Plan Effective Date in accordance with the terms of the Reorganization Plan to senior management, including the named executive officers under the 2016 Long-term Incentive Plan. These awards included a mix of restricted stock and stock options, with approximately two-thirds of the award, by dollar value, in the form of stock options having an exercise price equal to the greater of (1) the per share value based on the Company's post-Reorganization equity value of $650.0 million or (2) the weighted average trading price of the newly issued common stock for the seven (7) trading days commencing on the first trading day immediately following the Reorganization Plan Effective Date (assuming the new common shares were then publicly traded) with the vesting period of such stock options being over 3 years in equal annual installments provided the recipient remains employed by the Company as of the respective annual vesting dates and the remaining one-third of the award, by dollar value, in the form of restricted stock granted on the first full day of trading of the new common shares following the Reorganization Plan Effective Date, of which 50% vested in full on the date of grant and the remaining 50% would vest on the first anniversary of the grant, in each case provided the recipient remains employed by the Company as of such vesting date.

## 2016 Long-Term Incentive Plan

We grant equity awards under our 2016 Long-Term Incentive Plan, which for purposes of this discussion we referred to as the "Plan." The Plan became effective upon the Reorganization Plan Effective Date and originally provided for a total of 10 million shares of common stock.

As of February 28, 2017, a total of 1,733,067 shares of common stock had been granted as restricted stock and were outstanding, 5,313,200 shares were reserved for the exercise of outstanding stock options and 1,703,733 shares of our common stock remained available for issuance pursuant to the Plan. The Plan permits granting awards in a wide variety of forms, including options to purchase our common stock, shares of restricted stock, restricted stock units (granting the recipient the right to receive common stock), shares of incentive stock (common stock issued without a restriction period), stock appreciation rights, performance units (settled in common stock or cash) and performance bonuses (settled in common stock or cash). We currently utilize as awards under the Plan only restricted stock and stock options. No more than 10 million shares of common stock may underlie awards to a single recipient in any calendar year, and performance bonuses may not exceed $5 million to any recipient in any calendar year.

The Plan will expire on September 9, 2026. No grants will be made under the Plan after that date, but all grants made on or prior to such date will continue in effect thereafter subject to the terms of the award and of the Plan. Our board may, in its discretion, terminate the Plan at any time. The termination of the Plan would not affect the rights of participants or their successors under any awards outstanding and not exercised in full on the date of termination. The board may at any time, and from time to time, amend the Plan in whole or in part. Any amendment that must be approved by our stockholders in order to comply with the terms of the Plan, applicable law or the rules of the principal securities exchange, association or quotation system on which our common stock is then traded or quoted will not be effective unless and until such approval has been obtained. The board is not permitted, without the further approval of the stockholders, to make any alteration or amendment that would materially increase the benefits accruing to participants under the Plan, increase the aggregate number of shares that may be issued pursuant to the provisions of the Plan, change the class of individuals eligible to receive awards under the Plan or extend the term of the Plan.



## Stock Options

An important objective of our long-term incentive program is to strengthen the relationship between the long-term value of our stock price and the potential financial gain for employees. Stock options provide participants with the opportunity to purchase our common stock at a price fixed on the grant date regardless of future market price. A stock option becomes valuable only if our common stock price increases above the option exercise price and the holder of the option remains employed during the period required for the option to vest, thus providing an incentive for an option holder to remain employed by us. Stock options link the option holder's compensation to stockholders' interests by providing an incentive to increase the market price of our stock.

Option grants to senior management are generally considered annually, typically in February, after our year-end results become available, while grants to other eligible officers and employees are generally considered in December of each year. Our practice is that the exercise price for each stock option is the market value on the date of grant, which is normally the date that our Compensation Committee approves the award at a meeting of the Compensation Committee or a trading day after our release of earnings or other material nonpublic information. Our current policy provides for grants to be made or priced only during a trading window and within such window only at such time as there is no material non-public information regarding the Company. Under the Plan, the stock option price may not be less than the fair market value (the closing market price) of the shares on the date of grant. With respect to employees who are not executive officers, the Compensation Committee typically delegates the authority to make such grants to our chief executive officer but specifies the total number of shares that may be subject to grants and the other material terms of the grants. All proposed stock options to new-hire employees are required to be approved by our Compensation Committee. Alternatively, our Compensation Committee may authorize in writing, in advance of any fiscal quarter, the number of shares underlying stock options that may be granted to new-hire employees for the following fiscal quarter and provide that our chief executive officer may allocate such stock options at his discretion.

Stock options generally vest and become exercisable one-third annually after the original grant date. In certain instances, however, stock options may vest on an accelerated basis, such as in the event an executive's employment is terminated by us without cause or by the executive with good reason, in the event that the executive terminates his or her employment within a certain period following a transaction that effects a change in the control of our Company, or in the event of the executive's death or disability while employed by us. Under these circumstances all stock options held by the executive may automatically vest and become exercisable in accordance with the terms outlined in his or her stock option award agreement or employment agreement, if applicable. The employment agreements that we have entered into with the named executive officers provide for all stock options held by each executive to automatically vest and become exercisable in the event his or her employment is terminated by us without cause, by the executive for good reason or with or without good reason within a two-year period following a change of control of our Company.

There is a limited term in which an executive can exercise stock options, known as the "option term." The option term is generally ten years from the date of grant, which is the maximum term of an option permitted under the Plan. At the end of the option term, the right to purchase shares pursuant to any unexercised option expires.

Information relating to the stock options issued to the named executive officers during 2016 are shown in the table below entitled "Grants of Plan-Based Awards in 2016".

## Restricted Stock Awards

Restricted stock awards are shares of our common stock that are awarded with the restriction that the executive remain with us through certain "vesting" dates. Prior to the restrictions thereon lapsing,



the participant may not sell, transfer, pledge, assign or take any similar action with respect to the shares of restricted stock which the participant owns. Despite the restrictions, each participant will have full voting rights and will receive any dividends or other distributions, if any, with respect to the shares of restricted stock which the participant owns. Once the restrictions lapse with respect to shares of restricted stock, the participant owning such shares will hold freely-transferable shares, subject only to any restrictions on transfer contained in our certificate of incorporation, bylaws and insider trading policies, as well as any applicable federal or state securities laws.

Restricted stock awards provide the opportunity for capital accumulation and more predictable long-term incentive value. The purpose of granting restricted stock awards is to encourage ownership and retention of our senior management and result in business decisions that may drive stock price appreciation. Recognizing that our business is subject to significant fluctuations in commodity prices that may cause the market value of our common stock to fluctuate, we also intended the awards to provide an incentive for senior management to remain with us throughout commodity price and business cycles.

Restricted stock awards generally vest one-third annually after the original award date. As a consequence, the recipients do not become unconditionally entitled to retain any of the shares of restricted stock until one year following the date of grant, subject to certain exceptions related to termination of employment. Any unvested restricted stock awards generally are forfeited if the executive terminates employment with us. In certain instances, however, restricted stock awards may vest on an accelerated basis, such as in the event of the executive's employment is terminated by us without cause or by the executive with good reason, in the event that the executive terminates his or her employment within a certain period following a transaction that effects a change in the control of our Company, or in the event of the executive's death or disability while employed by us. Under these circumstances all restricted stock awards held by the executive may automatically vest in accordance with the terms outlined in the restricted stock award agreement or the employment agreement, if applicable. The employment agreements that we have entered into with the named executive officers provide for all restricted stock awards held by an executive to automatically vest in the event his or her employment is terminated by us without cause, by the executive for good reason or by the executive with or without good reason within a two-year period following a change of control of our Company.

The restricted stock grants to the named executive officers during fiscal year 2016 are shown below in the table entitled "Grants of Plan-Based Awards in 2016."

## Retirement Benefits

We do not maintain a defined benefit pension plan or retiree medical program that covers members of senior management. Retirement benefits to our senior management, including the named executive officers, are currently provided solely through a tax-qualified profit sharing and 401(k) plan (our "Savings Plan"), in which eligible full-time employees may participate. Pursuant to the Savings Plan, employees may elect to reduce their current annual compensation up to the lesser of 75% or the statutorily prescribed limit of $18,000 in calendar year 2016 (plus up to an additional $6,000 in the form of "catch-up" contributions for participants age 50 and above), and have the amount of any reduction contributed to the Savings Plan. Our Savings Plan is intended to qualify under sections 401(a) and 401(k) of the Internal Revenue Code of 1986, as amended (the "Code"), so that contributions by us or our employees to the Savings Plan and income earned on contributions are not taxable to employees until withdrawn from the Savings Plan and so that contributions will be deductible by us when made. We match 100% of the amount an employee contributes to the Savings Plan, up to a maximum contribution of 10%. Members of senior management participate in the Savings Plan on the same basis as other eligible employees.



## Table of Contents

The Savings Plan provides for various investment options, for which the participant has sole discretion in determining how both the employer and employee contributions are invested. The independent trustee of the Savings Plan then invests the assets of the Savings Plan as directed by participants. The Savings Plan does not provide our employees the option to invest directly in our securities. The Savings Plan offers in-service withdrawals in the form of after-tax account distributions and age 59.5 distributions.

We believe that the Savings Plan supports the objectives of our compensation structure, including the ability to recruit and retain senior and experienced mid- to late-career executive talent for critical positions within our organization.

## Outstanding Equity Awards Under the Plan

The following tables represent outstanding equity awards under the Plan as of December 31, 2016. We do not issue awards under any other plan.

<table><tr><td>Stock Options</td><td>Number of Securities to be Issued Upon Exercise of Outstanding Options</td><td>Weighted-Average Exercise Price of Outstanding Options</td><td>Average Remaining Contractual Life (Years)</td></tr><tr><td>Restricted Stock</td><td>5,319,400</td><td>$ 9.22</td><td>9.7</td></tr><tr><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>Number of Securities to be Issued Upon Vesting</td><td></td></tr><tr><td></td><td></td><td></td><td>1,738,077</td></tr></table>

As of December 31, 2016 a total of 1,689,398 shares of our common stock were available for future grants under the Plan. As of February 28, 2017, approximately 1,703,733 shares of our common stock are available for future grants under the Plan.

## Employment Contracts, Termination of Employment and Change-in-Control Arrangements

During 2012, we entered into employment agreements with each member of our senior management, including Messrs. Wilson, Herod and Mize. Strong competition for management talent and uncertainty associated with our business plan and our stated willingness to embrace consolidation trends in our industry led us to conclude that it was appropriate and in our best interests to enter into employment agreements with each of such named executive officers.

## Term of Employment Agreements

The initial term of employment of Mr. Wilson was for a term of two years from June 1, 2012, the effective date of his employment agreement, which the Company elected to renew for an additional two years effective June 1, 2014 and June 1, 2016, respectively. The initial term of employment of each of Messrs. Herod and Mize was originally until December 31, 2013, with automatic one-year extensions unless either party provides written notice thirty days prior to expiration of the initial term or any extension. Our failure to renew an executive's employment agreement will be considered a termination without cause under each employment agreement.

## Compensation and Benefits

The salary of each named executive officer is subject to periodic review and may be increased from time to time by the Compensation Committee. Each named executive officer is eligible to receive bonuses, grants of stock options, restricted stock or other equity awards as determined in the discretion.



of the Compensation Committee. Each of the named executive officers is also entitled to reimbursement for reasonable business expenses and to participate in our life, health, and dental insurance programs, and all other employee benefit plans which we may, from time to time, make available. We provide tax gross-ups on a limited basis for life insurance, parking and country club memberships.

Our Chief Executive Officer and President is entitled under his employment agreement to receive a vehicle allowance and reimbursement for reasonable fees and membership dues for one Houston area country club. Our Chief Financial Officer is entitled under his employment agreement to be reimbursed for reasonable fees and membership dues for one Houston area country club.

Our use of expense reimbursement and perquisites as an element of compensation is limited. We do not view these items as a significant element of our compensation structure but do believe that they can be used in conjunction with base salary to recruit, motivate and retain executive talent in a competitive environment. The Compensation Committee periodically reviews these items provided to determine if they are appropriate and if any adjustments are warranted.

## Termination Provisions and Severance Payments

We may terminate each named executive officer's employment upon disability, and at any time for cause or without cause. Each named executive officer may terminate his or her employment at any time, and such termination will be deemed to be with "good reason" if it is based on a material reduction in base salary; a material reduction in authority, responsibilities or duties or those of the supervisor to whom the named executive officer reports; a material reduction in the budget over which the named executive officer retains authority; a permanent relocation of the named executive officer's principal place of employment to any location outside a fifty mile radius of the location from which named executive officer provides services to the Company; or any uncured material breaches of the employment agreement by us. If the employment of any of the named executive officers is terminated by death or disability, such named executive officer (or his or her personal representative in the event of death) is entitled to receive accrued unpaid base compensation, plus an optional bonus to be determined by the Compensation Committee, and all stock options and other incentive awards held by the named executive officer will become fully vested and immediately exercisable, and all restrictions on any shares of restricted stock will be removed. If the employment of any of the named executive officers is terminated by us for cause, such named executive officer (or his or her personal representative in the event of death) is entitled to receive accrued unpaid base compensation.

If the employment of any named executive officer is terminated by us without cause or by such named executive officer with good reason, and such termination is not within two years after a change in control, such named executive officer will be entitled to the accrued portion of unpaid salary, payment of the greater of a prorated amount of the named executive officer's target bonus for the year in which the termination occurs or a bonus for such year as may be determined by our Compensation Committee in its sole discretion, a severance payment equal to one year's base salary plus the higher of the current year target bonus or the bonus paid for the preceding year, payment of the premiums for medical, vision and dental insurance for the executive and his or her dependents for up to one year following termination, and the full vesting of all unvested options and earned performance units (if applicable) and all restrictions removed from shares of restricted stock.

If such named executive officer is terminated by us without cause or such named executive officer terminates his or her employment with the Company with or without good reason, and such termination is within two years after a change in control, such named executive officer will be entitled to receive the accrued portion of unpaid salary, payment of the greater of a prorated amount of the named executive officer's target bonus for the year in which the termination occurs or a bonus for such year as may be determined by our Compensation Committee in its sole discretion, a severance payment equal



to a multiple (which varies by individual) of base salary plus the higher of the current year target bonus or the bonus paid for the year prior to termination or the year in which the change of control occurred, payment of the premiums for medical, vision and dental insurance for the executive and his or her dependents for up to eighteen months following termination, and the full vesting of all unvested options and earned performance units (if applicable) and all restrictions removed from shares of restricted stock. The multiplier for Mr. Wilson is 3.0, and for Messrs. Herod and Mize it is 2.5. In addition, if a bonus for the named executive officer for the year immediately preceding the termination has been determined but not paid as of the date of termination, the named executive officer will be paid the bonus so determined; and if such a bonus has not been determined, then the named executive officer will be paid a bonus equal to the greater of such named executive officer's target bonus for such year, or for the year in which the termination occurs or the change of control occurs, or the bonus paid to executive for the year immediately preceding the year in which the change of control occurs. If the employment of such named executive officer is terminated by such named executive officer without good reason and not within two years after a change in control, such named executive officer is entitled to receive accrued unpaid base compensation.

The employment agreements with the named executive officers generally define a change of control to mean any of the following events:

• any person or group becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 35% of the total voting power of our outstanding voting stock;

• our merger with or consolidation into another entity and, immediately after giving effect to the merger or consolidation, one or both of the following occurs: (a) less than 50% of the total voting power of the outstanding voting stock of the surviving or resulting entity is then "beneficially owned" in the aggregate by our stockholders immediately prior to such merger or consolidation, or (b) the individuals who were members of our board of directors immediately prior to the execution of the agreement providing for the merger or consolidation do not constitute at least a majority of the members of the board of directors of the surviving or resulting entity;

• we sell, assign, convey, transfer, lease or otherwise dispose of all or substantially all of our assets to a third party in one transaction or a series of related transactions;

• individuals who constitute our board of directors cease for any reason to constitute at least a majority of our board of directors unless such persons were elected, appointed or nominated by a vote of at least a majority of our incumbent directors; or

• the complete liquidation or dissolution of our Company.

In our view, having the change of control and severance protections helps to maintain the named executive officer's objectivity in decision-making and provides another vehicle to align the interests of our named executive officers with the interests of our stockholders.

The following table sets forth the estimated amounts that would be payable to each of the named executive officers upon a termination under the scenarios outlined above, excluding termination for cause or on account of death or disability, assuming that such termination occurred on December 31, 2016 and using the closing price of our common stock at December 31, 2016 for purposes of the calculations as required by the SEC. The dollar amounts set forth under the column heading "Early Vesting of Restricted Stock/Options/PSUs" correspond to the amounts that would be paid, in addition to accrued and unpaid salary through the date of death or disability, in the event of the death or disability.



at year-end of each of the executives. There can be no assurance that these scenarios would produce the same or similar results as those disclosed if a termination occurs in the future.

<table><tr><td></td><td>Severance Payment(1)</td><td>Early Vesting of Restricted Stock/Options/PSUs(2)</td><td>Other(3)</td><td>Total</td></tr><tr><td>Without Cause/For Good Reason</td><td></td><td></td><td></td><td></td></tr><tr><td>Floyd C. Wilson</td><td>$ 1,500,000</td><td>$ 4,535,188</td><td>$ 34,314</td><td>$ 6,069,502</td></tr><tr><td>Stephen W. Herod</td><td>$ 900,000</td><td>$ 1,187,063</td><td>$ 34,314</td><td>$ 2,121,377</td></tr><tr><td>Mark J. Mize</td><td>$ 800,000</td><td>$ 1,187,063</td><td>$ 34,314</td><td>$ 2,021,377</td></tr><tr><td>Following Change of Control</td><td></td><td></td><td></td><td></td></tr><tr><td>Floyd C. Wilson</td><td>$ 4,500,000</td><td>$ 4,535,188</td><td>$ 51,471</td><td>$ 9,086,659</td></tr><tr><td>Stephen W. Herod</td><td>$ 2,250,000</td><td>$ 1,187,063</td><td>$ 51,471</td><td>$ 3,488,534</td></tr><tr><td>Mark J. Mize</td><td>$ 2,000,000</td><td>$ 1,187,063</td><td>$ 51,471</td><td>$ 3,238,534</td></tr></table>

(1) Represents total annual cash compensation (2016 base salary plus target bonus, which is 100% of base salary for each officer, in accordance with the terms of the employment agreement), which, in the event of a change of control, has been multiplied by the applicable multiplier set forth in each officer's employment agreement.

(2) The value of unvested restricted stock and stock options that would vest under each termination scenario is based on the closing price of our common stock on December 31, 2016.

(3) Represents an estimate of health insurance benefits to be provided to the named executive officer and each eligible dependent under each of the scenarios based on actual amounts paid out in 2016.

## Board Representation

Mr. Wilson's employment agreement provides that he will be nominated as a member of our board, and that we will use our best efforts to cause him to be elected, appointed, or re-elected or re-appointed, as a director.

## Indemnity Agreements

We have entered into an indemnity agreement with each of our non-employee directors and Messrs. Wilson and Mize. These agreements provide for us to, among other things, indemnify such persons against certain liabilities that may arise by reason of their status or service as directors or officers, to advance their expenses incurred as a result of a proceeding as to which they may be indemnified and to cover such person under any directors' and officers' liability insurance policy we choose, in our discretion, to maintain. These indemnity agreements are intended to provide indemnification rights to the fullest extent permitted under applicable indemnification rights statutes in the State of Delaware and are in addition to any other rights such person may have under our certificate of incorporation, bylaws and applicable law. We believe these indemnity agreements enhance our ability to recruit and retain knowledgeable and experienced executives and independent, non-management directors.



## Tax Deductibility

Section 162(m) of the Code limits the deductibility of compensation in excess of $1 million paid to our chief executive officer and our three next most highly compensated executive officers (other than our principal financial officer) unless the compensation is performance-based as determined by applying certain specific and detailed criteria. We believe that it is often desirable and in our best interests to deduct compensation payable to our executive officers. However, we also believe that there are circumstances where our interests are best served by maintaining flexibility in the way compensation is provided, even if it might result in the non-deductibility of certain compensation under the Code. In this regard, we consider the anticipated tax treatment to our Company and our executive officers in the review and establishment of compensation programs and payments; however, we may pay compensation to our executives that may not be deductible, including discretionary bonuses or other types of compensation outside of our plans.

## Summary Compensation Table

The table below sets forth information regarding compensation for our named executive officers for the years indicated (commencing with the first year in which such officer became one of our named executive officers):

<table><tr><td>Name and Principal Position</td><td>Year</td><td>Salary(1)</td><td>Bonus(2)</td><td>Stock Awards(3)</td><td>Option/SAR Awards(3)</td><td>All Other Compensation(4)</td><td>Total</td></tr><tr><td></td><td>2016</td><td>$ 750,000</td><td>$ 3,275,000</td><td>$ 8,604,750</td><td>$ 11,463,436</td><td>$ 31,510</td><td>$ 24,124,696</td></tr><tr><td>Floyd C. Wilson</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2015</td><td>$ 750,000</td><td>—</td><td>$ 1,040,495</td><td>$ 1,120,732</td><td>$ 27,450</td><td>$ 2,938,677</td></tr><tr><td>Chairman of the</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2014</td><td>$ 750,000</td><td>$ 322,500</td><td>$ 2,058,065</td><td>—</td><td>$ 27,461</td><td>$ 3,158,026</td></tr><tr><td>Board, Chief Executive Officer and President</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Stephen W. Herod</td><td>2016</td><td>$ 450,000</td><td>$ 965,000</td><td>$ 2,252,250</td><td>$ 3,000,497</td><td>$ 31,510</td><td>$ 6,699,257</td></tr><tr><td></td><td>2015</td><td>$ 450,000</td><td>—</td><td>$ 378,742</td><td>$ 407,949</td><td>$ 26,909</td><td>$ 1,263,600</td></tr><tr><td>Executive Vice</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2014</td><td>$ 450,000</td><td>$ 193,500</td><td>$ 1,140,473</td><td>—</td><td>$ 25,975</td><td>$ 1,809,948</td></tr><tr><td>President, Corporate Development</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Mark J. Mize</td><td>2016</td><td>$ 400,000</td><td>$ 946,667</td><td>$ 2,252,250</td><td>$ 3,000,497</td><td>$ 38,461</td><td>$ 6,637,875</td></tr><tr><td></td><td>2015</td><td>$ 400,000</td><td>—</td><td>$ 375,502</td><td>$ 404,461</td><td>$ 34,824</td><td>$ 1,214,787</td></tr><tr><td>Executive Vice</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2014</td><td>$ 400,000</td><td>$ 172,000</td><td>$ 997,882</td><td>—</td><td>$ 31,266</td><td>$ 1,601,148</td></tr><tr><td>President, Chief Financial Officer and Treasurer</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(1) Represents actual base salary paid in the year.

(2) Comprised of a retention bonus paid prior to the Company and its subsidiaries filing of voluntary petitions under chapter 11 of the bankruptcy code and an annual cash incentive bonus paid subsequent to year end for prior year performance.

(3) Represents the grant date fair value of awards granted during the indicated year, as determined in accordance with ASC Topic 718. Pursuant to SEC rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions. Please see the discussion of the assumptions made in the valuation of these awards in "Note 13—Stockholders' Equity" to the audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2016. See "Grants of Plan-Based Awards in 2016" for information on awards made in 2016. Generally, the full grant date fair value is the amount that we would expense in our financial statements over the award's vesting schedule. These amounts reflect our accounting expense, and do not correspond to the actual value that will be recognized by the named executive officers.



(4) For 2016, the amounts reported for "All Other Compensation" include amounts provided to the named executive officers as outlined in the table below, with respect to (a) the matching contribution that we make on account of employee contributions under our 401(k) Savings Plan, (b) premiums paid by the Company for executive long-term disability insurance, (c) tax gross-ups for life insurance and parking payments and (d) country club membership paid by the Company for Mr. Mize.

<table><tr><td rowspan="2"></td><td colspan="5">All Other Compensation ($)</td></tr><tr><td>(a)</td><td>(b)</td><td>(c)</td><td>(d)</td><td></td></tr><tr><td>Named Executive Officer</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Floyd C. Wilson</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Stephen W. Herod</td><td>24,000</td><td>1,593</td><td>5,917</td><td>—</td><td></td></tr><tr><td>Mark J. Mize</td><td>24,000</td><td>1,593</td><td>5,917</td><td>—</td><td></td><td></td></tr><tr><td></td><td>18,000</td><td>1,593</td><td>5,917</td><td>12,951</td><td></td></tr></table>

## Grants of Plan-Based Awards in 2016

The table below sets forth information regarding grants of plan-based awards made to our named executive officers during 2016.

<table><tr><td rowspan="2">Name</td><td rowspan="2">Grant Date</td><td colspan="2">Estimated Future Payouts Under Equity Incentive Plan Awards(1)</td><td rowspan="2">Type of Award(2)</td><td rowspan="2">Exercise or Base Price of Option Awards ($/Sh)(3)</td><td rowspan="2">Grant Date Fair Value of Stock and Option Awards(4)</td></tr><tr><td>Target(#)</td><td>Options</td></tr><tr><td>Floyd C. Wilson</td><td>9/12/2016</td><td>—</td><td>1,862,500</td><td>—</td><td>$9.24</td><td>$11,463,436</td></tr><tr><td></td><td>9/12/2016</td><td>—</td><td>931,250</td><td>—</td><td>Restricted Stock</td><td>$8,604,750</td></tr><tr><td></td><td>9/12/2016</td><td>—</td><td>487,500</td><td>—</td><td>Options</td><td>$9.24</td></tr><tr><td>Stephen W. Herod</td><td>9/12/2016</td><td>—</td><td>243,750</td><td>—</td><td>Restricted Stock</td><td>$2,252,250</td></tr><tr><td></td><td>9/12/2016</td><td>—</td><td>487,500</td><td>—</td><td>Options</td><td>$9.24</td></tr><tr><td>Mark J. Mize</td><td>9/12/2016</td><td>—</td><td>243,750</td><td>—</td><td>Restricted Stock</td><td>$2,252,250</td></tr></table>

(1) Awards granted under the Plan provide only for a single estimated payout. Under the Plan there are no minimum amounts payable for a certain level of performance and there are no maximum payouts possible above the target. Thus, there are no thresholds or maximums (or equivalent items) applicable to these awards.

(2) Represents shares of restricted stock and stock options issued under the Plan. The shares of restricted stock vest in two equal installments, half on the date of grant and half on the first anniversary of the date of grant, provided that the recipient has been continuously employed at such date. Stock options vest in three equal installments on each anniversary of the date of grant, beginning on the first anniversary of the date of grant, in each case, provided that the recipient has been continuously employed at such date.

(3) The exercise price of each award is equal to the weighted average closing market price of our common stock for seven trading days following the date of grant.

(4) Represents the full grant date fair value determined in accordance with ASC Topic 718. Please see the discussion of the assumptions made in the valuation of these awards in "Note 13—Stockholders' Equity" to the audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2016. Generally, the full grant date fair value is the amount that we would expense in our financial statements over the award's vesting schedule. These amounts reflect our



accounting expense, and do not correspond to the actual value that will be recognized by the named executive officers.

## Outstanding Equity Awards at December 31, 2016

The following table summarizes the number of securities underlying outstanding plan awards for each named executive officer as of December 31, 2016.

<table><tr><td rowspan="2">Name</td><td colspan="3">Option Awards</td><td colspan="5">Stock Awards</td></tr><tr><td>Number of Securities Underlying Unexercised Options Exercisable</td><td>Number of Securities Underlying Unexercised Options Unexercisable(1)</td><td>Option Exercise Price</td><td>Option Expiration Date</td><td>Number of Shares or Units of Stock That Have Not Vested(1)</td><td>Market Value of Shares or Units of Stock That Have Not Vested(2)</td><td>Equity Incentive Plan Awards: Number of Unearned Shares, Units Or Other Rights That Have Not Vested</td><td>Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested</td></tr><tr><td>Floyd C. Wilson</td><td>—</td><td>1,862,500</td><td>$ 9.24</td><td>9/12/2026</td><td>465,625</td><td>$ 4,348,938</td><td>—</td><td>$ —</td></tr><tr><td>Stephen W. Herod</td><td>—</td><td>487,500</td><td>$ 9.24</td><td>9/12/2026</td><td>121,875</td><td>$ 1,138,313</td><td>—</td><td>$ —</td></tr><tr><td>Mark J. Mize</td><td>—</td><td>487,500</td><td>$ 9.24</td><td>9/12/2026</td><td>121,875</td><td>$ 1,138,313</td><td>—</td><td>$ —</td></tr></table>

(1) The shares of restricted stock vest in two equal installments, half on the date of grant and half on the first anniversary of the date of grant, provided that the recipient has been continuously employed at such date. Stock options vest in three equal installments on each anniversary of the date of grant, beginning on the first anniversary of the date of grant, in each case, provided that the recipient has been continuously employed at such date.

(2) Calculated based upon the closing market price of our common stock as of December 30, 2016, the last trading day of our 2016 fiscal year ($9.34) multiplied by the number of unvested awards at year end.

## Compensation Adjustments Subsequent to Fiscal Year End

Subsequent to December 31, 2016, the compensation committee awarded the following increase in base salary in response to competitive compensation practices.

<table><tr><td>Name</td><td>Base Salary Increase</td></tr><tr><td>Floyd C. Wilson</td><td>$ 50,000</td></tr></table>



## Option Exercises and Stock Vested

The following table summarizes option exercises and the vesting of restricted stock for our named executive officers in 2016.

<table><tr><td rowspan="2">Name</td><td colspan="2">Option Awards</td><td colspan="2">Stock Awards</td></tr><tr><td>Number of Shares Acquired on Exercise</td><td>Value Realized on Exercise(1)</td><td>Number of Shares Acquired on Vesting</td><td>Value Realized on Vesting(2)</td></tr><tr><td>Floyd C. Wilson</td><td>—</td><td>—</td><td>723,210</td><td>5,143,616</td></tr><tr><td>Stephen W. Herod</td><td>—</td><td>—</td><td>234,508</td><td>1,363,193</td></tr><tr><td>Mark J. Mize</td><td>—</td><td>—</td><td>224,905</td><td>1,359,774</td></tr></table>

(1) The value realized upon the exercise of the option award is determined by multiplying the number of shares acquired on exercise by the difference between the closing price of our common stock on the date of exercise and the exercise price of the option.

(2) The value realized equals the closing price of our common stock on the date of vesting, multiplied by the number of shares vested.

## Stock Ownership Guidelines Policy

Our board of directors has adopted an Amended and Restated Stock Ownership Guidelines Policy (the "Policy") applicable to our board of directors, chief executive officer and president and each executive vice president to ensure that they maintain a meaningful economic stake in the Company. The Policy is designed to maintain stock ownership of our directors and the specified officers at a significant level so as to further align their interests with the interests of our stockholders in value creation. Subject to certain exceptions contained in the Policy, our directors are required to hold a number of shares of our common stock valued at three times (3x) the annual cash retainer paid to them by the Company, our chief executive officer and president is required to hold a number of shares of our common stock valued at six times (6x) the base salary paid to him by the Company and the other specified officers are required to hold a number of shares of our common stock valued at three times (3x) the base salaries paid to them by the Company. For purposes of calculating the value of shares owned, each share of stock shall have a deemed value equal to the greater of the price at acquisition or the current market value. For purposes of calculating the value of unvested restricted shares, the value shall be determined without giving effect to the restriction.



## DIRECTOR COMPENSATION

The table below sets forth certain information concerning the compensation earned in 2016 by our non-employee directors for service on our board of directors and committees of the board of directors during 2016.

<table><tr><td>Name</td><td>Fees Earned or Paid in Cash</td><td>Stock Awards(1)(2)</td><td>Option Awards</td><td>All Other Compensation</td><td>Total(3)</td></tr><tr><td>William J. Campbell</td><td>$ 28,001</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 163,005</td></tr><tr><td>James W. Christmas</td><td>$ 227,715</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 362,719</td></tr><tr><td>Michael L. Clark</td><td>$ 29,556</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 164,560</td></tr><tr><td>Thomas R. Fuller</td><td>$ 176,276</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 311,280</td></tr><tr><td>Darryl L. Schall</td><td>$ 23,334</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 158,338</td></tr><tr><td>Ronald D. Scott</td><td>$ 23,334</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 158,338</td></tr><tr><td>Eric G. Takaha.</td><td>$ 24,111</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 159,115</td></tr><tr><td>Nathan W. Walton</td><td>$ 23,334</td><td>$ 135,004</td><td>$ —</td><td>$ —</td><td>$ 158,338</td></tr></table>

(1) Represents the grant date fair value of awards granted during the indicated year, as determined in accordance with ASC Topic 718. Pursuant to SEC rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions. Please see the discussion of the assumptions made in the valuation of these awards in "Note 13—Stockholders' Equity" to the audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2016. Generally, the full grant date fair value is the amount that we would expense in our financial statements over the award's vesting schedule. These amounts reflect our accounting expense, and do not correspond to the actual value that will be recognized by our directors.

(2) The number of restricted stock awards subject to vesting, excluding shares received in lieu of fees, made to each of our directors for service as a director during 2016 was 17,264.

(3) Represents the numerical sum of the dollar amounts reflected in each other column for each director.

## Discussion of Director Compensation Table

Employee directors receive no additional compensation for service on our board of directors or any committee of the board of directors. All directors receive actual expense reimbursements associated with attending board and committee meetings. Our director compensation program has been developed with the advice and guidance of our independent compensation consultant using peer group and market data and consists of two principal elements: (1) annual retainer and committee fees and (2) equity consisting of restricted stock awards. Our Compensation Committee reviews our director compensation program at least annually, and more frequently if circumstances warrant it, using the advice and information provided by our independent compensation consultant. Our non-employee directors received an award of restricted stock under our 2016 Plan with value of $135,004; they will receive annually an award of restricted stock under our 2016 Plan having a value of $165,000, which grant shall be made following our annual meeting of stockholders. Our non-employee directors also receive an annual cash retainer of $70,000, payable on a quarterly basis and pro rated for actual service during the year. Our lead independent director receives an additional $25,000 per year, also payable on a quarterly basis and pro rated for actual service during the year. Additional annual compensation for



each committee chairperson and committee member for all of the committees of our board of directors is set forth below:

<table><tr><td>Board Committee</td><td>Committee Chairperson Additional Compensation</td><td>Committee Member (excluding Chairperson) Additional Compensation</td></tr><tr><td>Audit</td><td>$ 25,000</td><td>$ 7,500</td></tr><tr><td>Compensation</td><td>$ 15,000</td><td>$ 5,000</td></tr><tr><td>Nominating and Corporate Governance</td><td>$ 12,500</td><td>$ 5,000</td></tr><tr><td>Reserves</td><td>$ 12,500</td><td>$ 5,000</td></tr></table>

Fees are paid in four equal quarterly installments and board members may elect to take all or a portion of the cash compensation we pay to them in shares of our common stock, with the number of shares determined by dividing such fees by the trading price per share of our common stock on the last day of each calendar quarter. Any such election must be made prior to the beginning of the quarter for which the compensation is to be paid and is irrevocable for that quarter.

## COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

No member of the Compensation Committee during 2016 served as one of our officers or employees or of any of our subsidiaries during that year. In addition, during 2016, none of our executive officers served as a director or as a member of the compensation committee of a company which employs any of our directors.

## ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

## Security Ownership of Certain Beneficial Owners and Management

The following sets forth information regarding the beneficial ownership of our common stock as of February 28, 2017 by:

• each person to be known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock;

• each of our named executive officers;

• each of our directors; and

• all of our current executive officers and directors as a group.



As of February 28, 2017, approximately 93 million shares of our common stock were outstanding. Unless otherwise noted, the mailing address of each person or entity named below is 1000 Louisiana St., Suite 6700, Houston, Texas 77002.

<table><tr><td>Name and Address of Beneficial Owner</td><td>Amount and Nature of Beneficial Ownership</td><td>Percent of Class \( ^{(1)} \)</td></tr><tr><td>Franklin Resources, Inc. \( ^{(2)} \)</td><td>34,261,424</td><td>36.7%</td></tr><tr><td>Ares Management LLC \( ^{(3)} \)</td><td>18,357,256</td><td>19.7%</td></tr><tr><td>Tyrus Capital S.A.M. \( ^{(4)} \)</td><td>9,126,652</td><td>9.7%</td></tr><tr><td>Floyd C. Wilson \( ^{(5)} \)</td><td>1,160,149</td><td>1.2%</td></tr><tr><td>Stephen W. Herod \( ^{(6)} \)</td><td>275,353</td><td>*</td></tr><tr><td>Mark J. Mize \( ^{(7)} \)</td><td>269,553</td><td>*</td></tr><tr><td>William J Campbell \( ^{(8)} \)</td><td>17,264</td><td>*</td></tr><tr><td>James W. Christmas \( ^{(9)} \)</td><td>53,340</td><td>*</td></tr><tr><td>Michael L. Clark \( ^{(10)} \)</td><td>17,264</td><td>*</td></tr><tr><td>Thomas R. Fuller \( ^{(11)} \)</td><td>27,685</td><td>*</td></tr><tr><td>Darryl L. Schall \( ^{(12)} \)</td><td>—</td><td>*</td></tr><tr><td>Ronald D. Scott \( ^{(13)} \)</td><td>17,264</td><td>*</td></tr><tr><td>Eric G. Takaha \( ^{(14)} \)</td><td>17,264</td><td>*</td></tr><tr><td>Nathan W. Walton \( ^{(15)} \)</td><td>—</td><td>*</td></tr><tr><td>All directors and executive officers as a group (13 individuals)</td><td>2,616,147</td><td>2.8%</td></tr></table>

* Less than 1%.

(1) Unless otherwise indicated, each stockholder has sole voting and investment power with respect to all shares of common stock indicated as being beneficially owned by such stockholder. Shares of common stock that are not outstanding, but which a designated stockholder has the right to acquire within 60 days, are included in the number of shares beneficially owned by such stockholder and are deemed to be outstanding for purposes of determining the percentage of outstanding shares beneficially owned by such stockholder, but not for purposes of determining the percentage of outstanding shares beneficially owned by any other designated stockholder. In all instances where ownership of unvested restricted stock is reported below, the individual has the sole power to vote such shares but no investment power.

(2) According to, and based solely upon, Schedule 13G/A filed by Franklin Resources, Inc., Charles B. Johnson, Rupert H. Johnson, Jr. and Franklin Advisers, Inc. (collectively, "Franklin") with the SEC on February 5, 2016. The business address for Franklin is One Franklin Parkway, San Mateo, CA 94403.

(3) The business address of Ares Management LLC is 2000 Avenue of the Stars, 12 \( ^{th} \)  Floor, Los Angeles, CA 90067.

(4) According to, and based solely upon, Schedule 13G/A filed by Tyrus Capital S.A.M. and Tony Chendraoui (collectively, "Tyrus") with the SEC on February 14, 2017. The business address for Tyrus is 4 Avenue Roqueville, Monaco, MC 98000.

(5) Includes 465,625 shares of unvested restricted stock. Also includes 7,019 shares held in seventeen trusts for the benefit of Mr. Wilson's children and grandchildren, of which Mr. Wilson is the trustee and disclaims beneficial ownership of such shares. Does not include 6,583






(6) Includes 121,875 shares of unvested restricted stock. Does not include 2,749 shares held in trusts for the benefit of Mr. Herod's minor children, of which Mr. Herod disclaims beneficial ownership of such shares and has no dispositive or voting power with respect to the shares held by such trusts.

(7) Includes 121,875 shares of unvested restricted stock. 1,964 shares held by Mr. Mize are pledged.

(8) The business address for Mr. Campbell is 820 Gessner, Suite 1460, Houston, TX 77024.

(9) Does not include 177 shares of common stock held in three trusts for his children. Mr. Christmas has no dispositive or voting power with respect to the shares held by such trusts. The business address for Mr. Christmas is c/o Halcón Resources Corporation, 1000 Louisiana Street, Suite 6700, Houston, TX 77002.

(10) The business address for Mr. Clark is c/o Halcón Resources Corporation, 1000 Louisiana Street, Suite 6700, Houston, TX 77002.

(11) The business address for Mr. Fuller is 19500 SH 249, Suite 640, Houston, TX 77070.

(12) The business address for Mr. Schall is c/o Halcón Resources Corporation, 1000 Louisiana Street, Suite 6700, Houston, TX 77002.

(13) The business address for Mr. Scott is 1030 Andrews Highway, Suite 200, Midland, TX 79703.

(14) The business address for Mr. Takaha is c/o Halcón Resources Corporation, 1000 Louisiana Street, Suite 6700, Houston, TX 77002.

(15) The business address for Mr. Walton is 2000 Avenue of the Stars, 12 \( ^{th} \)  Floor, Los Angeles, CA 90067.

## Equity Compensation Plan Information

The following table sets forth certain information as of December 31, 2016 with respect to compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.

<table><tr><td>Plan Category</td><td>Number of Securities to be Issued Upon Exercise of Outstanding Options and Rights(a)</td><td>Weighted-Average Exercise Price of Outstanding Options and Rights</td><td>Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))</td></tr><tr><td>Equity compensation plans approved by security holders(1)</td><td>7,057,477(2)\(</td><td>9.22</td><td>1,689,398</td></tr><tr><td>Equity compensation plans not approved by security holders</td><td>—</td><td>—</td><td>—</td></tr><tr><td></td><td>7,057,477(2)\(</td><td>9.22</td><td>1,689,398</td></tr></table>

(1) Represents information for the 2016 Long-Term Incentive Plan.

(2) Includes 1,738,077 shares of restricted stock not yet vested.

## ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Charter of Aircraft. In the ordinary course of its business, the Company occasionally charter private aircraft from unaffiliated air charter companies. Floyd C. Wilson, the Company's Chairman, CEO and President, indirectly owns an aircraft which is managed by an independent air charter company unaffiliated with both Mr. Wilson and the Company. The Company occasionally charters



private aircraft, including the aircraft owned indirectly by Mr. Wilson, from this company. The aircraft in the air charter company's fleet, including the aircraft indirectly owned by Mr. Wilson, are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. During 2016, the Company paid a total of approximately $0.5 million to the air charter company that manages Mr. Wilson's aircraft, all of which was related to the use of the aircraft indirectly owned by Mr. Wilson. Because the air charter company establishes fees for the use of the aircraft in its fleet, Mr. Wilson does not receive any greater benefit from the Company's charter of the aircraft indirectly owned by him than he does if any third party were to charter those aircraft. Any fees related to the charter of the aircraft are paid to the air charter company, which deducts from revenues received from charter customers a variety of expenses incidental to use of the aircraft (such as personnel, fuel and commissions) and recurring charges (such as for inspections, maintenance, storage and service).

The use of charter and Company-owned aircraft by Company personnel is governed by the Company's Aircraft Policy. Our policies do not require that a special committee of the Company's independent directors approve the use of aircraft chartered through an unaffiliated air charter company that independently establishes the amount charged under arrangements that otherwise comply with our Aircraft Policy.

Related Party Transaction Review Policies and Procedures. A transaction or series of similar transactions to which we are a party in which the amount involved exceeds $120,000 and involves a director, executive officer, 5% stockholder or any immediate family members of these persons is evaluated by a special committee of disinterested directors formed by our board of directors to evaluate such transactions. In addition, our code of conduct provides that every employee should disclose any material transaction or relationship that could reasonably be expected to give rise to a conflict of interest to upper management or the Company's Audit Committee. The Audit Committee has the authority to evaluate any such conflicts of interest and recommend actions to be taken by our board in connection with such conflicts of interest or to report the existence of any such conflicts of interest to the full board for it to take action.

Director Independence. The current listing standards of the NYSE require our board to affirmatively determine the independence of each director and to disclose such determination in the proxy statement for each annual meeting of our stockholders. The board, on February 28, 2017, affirmatively determined that each of Messrs. Campbell, Christmas, Clark, Fuller, Schall, Scott, Takahara and Walton is an "independent director" under the guidelines described below and the independence rules of the NYSE codified in Section 303A of the NYSE Listed Company Manual.

In connection with its assessment of independence, our board reviewed information regarding relevant relationships, arrangements or transactions between the Company and each director or parties affiliated with such director. Our board has established the following standards for determining director independence in our corporate governance guidelines:

A majority of the directors on our board must be "independent." No director qualifies as "independent" unless the board affirmatively determines that the director has no "material relationship" with the Company, either directly, or as a partner, shareholder or officer of an organization that has a relationship with the Company. A "material relationship" is a relationship that the board determines, after a consideration of all relevant facts and circumstances, compromises the director's independence from management. Our board's determination of independence must be consistent with all applicable requirements of the NYSE, the SEC, and any other applicable legal requirements. Our board may adopt specific standards or guidelines for independence in its discretion from time to time, consistent with those requirements. As set forth in the NYSE Listed Company



Manual Section 303A.02, our board must consider the following factors that preclude a finding by the board of a member's or prospective member's "independence" from the Company:

1. A director who is, or who has been within the last three years, an employee of the Company (including in each case subsidiaries or parent entities in a consolidated group), or an immediate family member who is, or has been within the last three years, an executive officer, of the Company;

2. A director who has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $120,000 in direct compensation from the Company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service); provided, that, compensation received by a director for former service as an interim Chairman or CEO or other executive officer need not be considered in determining independence under this test, and compensation received by an immediate family member for service as an employee of the Company need not be considered in determining independence under this test;

3. (A) A director is a current partner or employee of a firm that is the Company's internal or external auditor; (B) a director who has an immediate family member who is a current partner of such a firm; (C) a director who has an immediate family member who is a current employee of such a firm and who participates in the Company's audit; or (D) a director or an immediate family member who was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on the Company's audit within that time;

4. A director or an immediate family member who is, or who has been within the last three years, employed as an executive officer of another company where any of the Company's present executive officers at the same time serves or served on that company's compensation committee;

5. A director who is a current employee, or an immediate family member who is a current executive officer, of a company that has made payments to, or received payments from, the Company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $200,000, or 2% of such other company's consolidated gross revenues;

6. Whether the director has any other relationship with the Company, either directly or as a partner, shareholder or officer of an organization that has a relationship with the Company; and

7. Whether the director is aware of any other relationships that could potentially interfere, or could appear to interfere, with his exercise of independent judgment in carrying out the responsibilities of a director, including (i) any transaction, arrangement or relationship, in the last fiscal year, involving the director, including any family members, and any other officer or director of the Company; or (ii) any other relationship with the Company, either directly or as a shareholder, executive officer or partner or an organization that has such a relationship, including any relationships with charitable, educational, political or other not-for-profit organizations.

For purposes of determining "independence" of a director based on the tests set forth above, among other things, the following applies:

A. In applying the test in paragraph 5 above, both the payments and the consolidated gross revenues to be measured are those reported in the last completed fiscal year. The look-back provision for this test applies solely to the financial relationship between the Company and the director or immediate family member's current employer; the Company is not required to consider former employment of the director or the immediate family member.



B. For purposes of paragraph 5 above, contributions to tax exempt organizations are not considered "payments," although the Company still considers the "materiality" of any such relationship in determining the "independence" of a director.

C. For purposes of determining "independence," an "immediate family member" includes a person's spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than a domestic employee) who shares such person's home, and does not include individuals who are no longer immediate family members as a result of legal separation or divorce, or those who have died or become incapacitated.

Our corporate governance guidelines set forth our policy with respect to qualifications of the members of the board, the standards of director independence, director responsibilities, board meetings, director access to management and independent advisors, director orientation and continuing education, director compensation, Chairman and CEO dual responsibilities, management evaluation and succession, annual performance evaluation of the board, and executive sessions.

## ITEM14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

## Principal Accountant

Deloitte is the independent registered public accounting firm selected by our Audit Committee as the independent registered public accountant for the fiscal years ended December 31, 2016 and 2015. During the years ended December 31, 2016 and 2015, neither the Company nor anyone acting on its behalf consulted Deloitte with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company's consolidated financial statements, or any other matters or reportable events as defined in Items 304(a)(1)(iv) and (v) of Regulation S-K.

## Fees

The following table presents fees billed for professional audit services rendered by Deloitte, our principal accounting firm for the years ended December 31, 2016 and 2015. The table also presents fees for other services rendered by Deloitte during those periods. Except as set forth below, we paid all such fees.

<table><tr><td></td><td>2016</td><td>2015</td></tr><tr><td>Audit Fees</td><td></td><td></td></tr><tr><td></td><td>$ 1,679,469</td><td>$ 1,604,908</td></tr><tr><td>Audit-Related Fees</td><td></td><td></td></tr><tr><td></td><td>203,013</td><td>100,000</td></tr><tr><td>Tax Fees</td><td></td><td></td></tr><tr><td></td><td>2,654,768</td><td>—</td></tr><tr><td>All Other Fees</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Total</td><td></td><td></td></tr><tr><td></td><td>$ 4,537,250</td><td>$ 1,704,908</td></tr></table>

As used above, the following terms have the meanings set forth below:

Audit Fees. The fees for professional services rendered by Deloitte for the audit of our annual financial statements, for the review of the financial statements included in our quarterly reports on Form 10-Q and for services that are normally provided by the accountants in connection with statutory and regulatory filings or engagements and private placements, including but not limited to registration statements, for the years ended December 31, 2016 and 2015.

Audit-Related Fees. The fees for assurance and related services by Deloitte that are for audit, valuation services related to the Reorganization and valuation services for a specific subsidiary that are reasonably related to the performance of the audit or review of our financial statements and are not otherwise reported under "Audit Fees."



## Table of Contents

Tax Fees. The fees for professional services rendered by Deloitte for tax compliance, tax advice, and tax planning.

All Other Fees. The fees for products and services provided by Deloitte, other than for the services reported under the headings "Audit Fees," "Audit-Related Fees" and "Tax Fees," for the period in question.

## Audit Committee Pre-Approval Policy

All audit fees, audit-related fees and tax fees as described above for the years ended December 31, 2016 and 2015 were pre-approved by our Audit Committee, which concluded that the provision of such services by Deloitte was compatible with the maintenance of their respective independence in the conduct of their auditing functions. Our Audit Committee's pre-approval policy provides that pre-approval of all such services must be approved separately by the Audit Committee. The Audit Committee has not delegated any such pre-approval authority to anyone outside the Audit Committee. Each member of the Audit Committee has the authority to pre-approve non-audit services up to $200,000 to be performed by our independent registered public accountant.



## PART IV

## ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

## (1) Consolidated Financial Statements:

The consolidated financial statements of the Company and its subsidiaries and reports of independent registered public accounting firms listed in Section 8 of this Annual Report on Form 10-K are filed as a part of this Annual Report on Form 10-K.

## (2) Consolidated Financial Statements Schedules:

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

## (3) Exhibits:

2.1 Order of the Bankruptcy Court, dated September 8, 2016, confirming the Amended Joint Prepackaged Plan of Reorganization of Halcón Resources Corporation, et al, under Chapter 11 of the Bankruptcy Code, together with such Amended Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed September 9, 2016).

2.2* Purchase and Sale Agreement dated January 18, 2017, by and between Halcón Energy Properties, Inc. and Samson Exploration, LLC.

2.3* Agreement of Sale and Purchase dated January 24, 2017, by and among Halcón Energy Properties, Inc., Halcón Holdings, Inc., HK Energy, LLC, HK Oil & Gas, LLC, HRC Energy, LLC, The 7711 Corporation, Halcón Operating Co., Inc. and Halcón Field Services, LLC and Hawkwood Energy East Texas, LLC.

2.4 Stock Purchase Agreement dated January 24, 2017, by and among Halcón Resources Corporation and the Investors named on Schedule A thereto (Incorporated by referenced to Exhibit 2.1 of our Current Report on Form 8-K filed January 26, 2017).

3.1 Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated September 9, 2016 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed September 9, 2016).

3.2 Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed May 7, 2015).

3.2.1 Amendment No. 1 to the Fifth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed September 9, 2016).

4.1 Indenture, dated as of May 1, 2015, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, relating to Halcón Resources Corporation's 8.625% Senior Secured Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed May 4, 2015).

4.1.1 First Supplemental Indenture, dated as of September 28, 2016, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 8.625% Senior Secured Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed September 30, 2016).



4.1.2 * Second Supplemental Indenture, dated as of January 23, 2017, among Lampe, LLC, a subsidiary of Halcón Resources Corporation, the existing subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 8.625% Senior Secured Notes due 2020.

4.2 Indenture, dated as of December 21, 2015, among Halcón Resources Corporation, the guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 12.0% Second Lien Senior Secured Notes due 2022 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed December 22, 2015).

4.2.1 First Supplemental Indenture dated as of September 28, 2016, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 12.0% Second Lien Senior Secured Notes due 2022 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed September 30, 2016).

4.2.2* Second Supplemental Indenture dated as of January 23, 2017, among Lampe, LLC, a subsidiary of Halcón Resources Corporation, the existing subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 12.0% Second Lien Senior Secured Notes due 2022.

4.3 Purchase Agreement, dated February 9, 2017, by and among the Company, the Guarantors and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 10, 2017).

4.4* Indenture, dated as of February 16, 2017, among Halcón Resources Corporation, the guarantors named therein and U.S. Bank National Association, as Trustee (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 16, 2017).

4.5 Registration Rights Agreement, dated as of February 16, 2017, by and among the Company, the Guarantors and J.P. Morgan Securities, LLC as representatives of the Initial Purchasers (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 16, 2017).

10.1 Senior Secured Revolving Credit Agreement, dated as of September 9, 2016, by and among Halcón Resources Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 9, 2016).

10.2 Intercreditor Agreement, dated as of May 1, 2015, among Halcón Resources Corporation, the subsidiary guarantors named therein, U.S. Bank National Association, as second lien collateral trustee, and JPMorgan Chase Bank, N.A., as priority lien agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 4, 2015).

10.2.1 Priority Confirmation Joinder, dated as of December 21, 2015, by and between JPMorgan Chase Bank, N.A., as Priority Lien Agent, U.S. Bank National Association, as New Representative, U.S. Bank National Association as Second Lien Collateral Trustee, and U.S. Bank National Association, as Third Lien Collateral Trustee (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed December 22, 2015).



10.3 Collateral Trust Agreement, dated as of May 1, 2015, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, the other party lien debt representatives from time to time party thereto and U.S. Bank National Association, as collateral trustee (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed May 4, 2015).

10.3.1 Collateral Trust Joinder, dated as of December 21, 2015, by U.S. Bank National Association, as New Notes Trustee, and U.S. Bank National Association, as Collateral Trustee (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 22, 2015).

10.4 Second Lien Security Agreement, dated as of May 1, 2015, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as collateral trustee (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed May 4, 2015).

10.4.1 First Amendment to Second Lien Security Agreement, dated as of December 21, 2015, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as collateral trustee (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed December 22, 2015).

10.5 Registration Rights Agreement, dated as of September 9, 2016, by and among Halcón Resources Corporation and the Holders parties thereto (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed September 9, 2016).

10.6 Warrant Agreement, dated as of September 9, 2016, by and between Halcón Resources Corporation and U.S. Bank National Association, as warrant agent (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed September 9, 2016).

10.7† Halcón Resources Corporation 2016 Long-Term Incentive Plan, effective as of September 9, 2016 (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed September 9, 2016).

10.8 Assignment and Assumption Agreement, dated as of September 30, 2016, among Halcón Energy Properties, Inc., Halcón Gulf States, LLC and Apollo HK TMS Investment Holdings, L.P. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 5, 2016).

10.9 Form of Indemnity Agreement between Halcón Resources Corporation and each of its directors (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 19, 2012).

10.10† Employment Agreement between Floyd C. Wilson and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 5, 2012).

10.11† Employment Agreement between Stephen W. Herod and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed June 5, 2012).

10.12† Employment Agreement between Mark J. Mize and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed June 5, 2012).

10.13† Employment Agreement between David S. Elkouri and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed June 5, 2012).



10.14† Employment Agreement between Joseph S. Rinando, III and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed June 5, 2012).

10.15† Key Employee Retention Agreement between Floyd C. Wilson and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.37 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.16† Key Employee Retention Agreement between Stephen W. Herod and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.38 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.17† Key Employee Retention Agreement between Mark J. Mize and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.39 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.18† Key Employee Retention Agreement between David S. Elkouri and Halcón Resources Corporation dated March 8, 2016 (Incorporated by reference to Exhibit 10.40 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.19†* Third Amended and Restated Summary of Non-Employee Director Compensation adopted effective as of September 9, 2016.

10.20† Amended and Restated Stock Ownership Guidelines Policy adopted on February 25, 2015 (Incorporated by reference to Exhibit 10.26 of our Annual Report on Form 10-K filed February 26, 2016, as amended by Amendment No. 1 filed on April 25, 2016).

10.21†* Form of Employee Stock Option Award Agreement.

10.22†* Form of Employee Restricted Stock Award Agreement.

10.23†* Form of Non-Employee Director Restricted Stock Award Agreement.

12.1* Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends

21.1* List of Subsidiaries of Halcón Resources Corporation

23.1* Consent of Deloitte & Touche LLP

23.2* Consent of Netherland, Sewell & Associates, Inc.

31.1* Sarbanes-Oxley Section 302 certification of Principal Executive Officer

31.2* Sarbanes-Oxley Section 302 certification of Principal Financial Officer

32* Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer

99.1* Report of Netherland, Sewell & Associates, Inc.

101.INS* XBRL Instance Document

101.SCH* XBRL Taxonomy Extension Schema Document

101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF* XBRL Taxonomy Extension Definition Document



101.LAB* XBRL Taxonomy Extension Label Linkbase Document

101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document

* Attached hereto.

 \( ^{\dagger} \)  Indicates management contract or compensatory plan or arrangement.

The registrant has not filed with this report copies of the instruments defining rights of all holders of long-term debt of the registrant and its consolidated subsidiaries based upon the exception set forth in Item 601(b)(4)(iii)(A) of Regulation S-K. Copies of such instruments will be furnished to the SEC upon request.



## SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

## HALCÓN RESOURCES CORPORATION

Date: February 28, 2017

By:

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board,
Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ FLOYD C. WILSON</td><td rowspan="2">Chairman of the Board, Chief Executive Officer and President</td><td rowspan="2">February 28, 2017</td></tr><tr><td>Floyd C. Wilson</td></tr><tr><td>/s/ MARK J. MIZE</td><td rowspan="2">Executive Vice President, Chief Financial Officer and Treasurer</td><td rowspan="2">February 28, 2017</td></tr><tr><td>Mark J. Mize</td></tr><tr><td>/s/ JOSEPH S. RINANDO, III</td><td rowspan="2">Senior Vice President, Chief Accounting Officer and Controller</td><td rowspan="2">February 28, 2017</td></tr><tr><td>Joseph S. Rinando, III</td></tr><tr><td>/s/ WILLIAM J. CAMPBELL</td><td rowspan="2">Director</td><td rowspan="2">February 28, 2017</td></tr><tr><td>William J. Campbell</td></tr><tr><td>/s/ JAMES W. CHRISTMAS</td><td rowspan="2">Lead Director</td><td rowspan="2">February 28, 2017</td></tr><tr><td>James W. Christmas</td></tr><tr><td>/s/ MICHAEL L. CLARK</td><td rowspan="2">Director</td><td rowspan="2">February 28, 2017</td></tr><tr><td>Michael L. Clark</td></tr><tr><td>/s/ THOMAS R. FULLER</td><td rowspan="2">Director</td><td rowspan="2">February 28, 2017</td></tr><tr><td>Thomas R. Fuller</td></tr></table>



<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ DARRYL L. SCHALL</td><td></td><td></td></tr><tr><td>Darryl Schall</td><td>Director</td><td>February 28, 2017</td></tr><tr><td>/s/ RONALD D. SCOTT</td><td></td><td></td></tr><tr><td>Ronald D. Scott</td><td>Director</td><td>February 28, 2017</td></tr><tr><td>/s/ ERIC G. TAKAHA</td><td></td><td></td></tr><tr><td>Eric G. Takaha</td><td>Director</td><td>February 28, 2017</td></tr><tr><td>/s/ NATHAN W. WALTON</td><td></td><td></td></tr><tr><td>Nathan W. Walton</td><td>Director</td><td>February 28, 2017</td></tr></table>



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# PURCHASE AND SALE AGREEMENT

# BETWEEN

# SAMSON EXPLORATION, LLC (“SELLER”)

# AND

# HALCON ENERGY PROPERTIES, INC. (“BUYER”)

# DATED

# January 18, 2017

## TABLE OF CONTENTS

1. DEFINITIONS
2. PURCHASE AND SALE
2.1 Interests
2.2 Wells
2.3 Equipment
2.4 Production
2.5 Surface Rights
2.6 Contract Rights and Permits
2.7 Gathering System
2.8 Interests of TAR Owners
2.9 Files and Records
2.10 Gas and Pipeline Imbalances
2.11 Excluded Assets
3. PURCHASE PRICE AND ALLOCATION
3.1 Base Purchase Price
3.2 Performance Deposit and Payment
3.3 Adjustments to the Base Purchase Price
3.4 Allocation of Base Purchase Price
3.5 Allocation of Adjusted Base Purchase Price
4. ACCESS TO ASSETS AND DATA; DISCLAIMERS
4.1 Access
4.2 Disclaimer
5. SELLER'S REPRESENTATIONS
5.1 Existence
5.2 Authority
5.3 Violations
5.4 Compliance
5.5 Payment of Royalties
5.6 Taxes
5.7 Contracts and Permits
5.8 Litigation and Claims
5.9 Sale Contracts
5.10 Notices
5.11 Imbalances
5.12 Take-or-Pay
5.13 Timely Payment
5.14 Outstanding Obligations
5.15 Brokers
5.16 Consents
5.17 Preferential Purchase Rights; AMIs; MFNs
5.18 Surety Bonds
5.19 Current Plugging Obligations
5.20 Payout
5.21 Suspended Amounts.
5.22 Screaming Eagle Agreement and Project Payout.



6. BUYER'S REPRESENTATIONS 16
6.1 Information 16
6.2 Knowledge and Experience 16
6.3 No Warranty 17
6.4 Formation, Good Standing and Authority 17
6.5 Liability for Broker's Fees 17
6.6 Financial Resources 17
6.7 Qualification to Assume Operatorship 18
7. TITLE 18
7.1 Title Defects 18
7.2 Additional Interests 19
7.3 Notices 19
7.4 Adjustments to Base Purchase Price 19
7.5 Deductible for Title and Environmental Defects 20
8. ENVIRONMENTAL AND ENVIRONMENTAL INDEMNITY 21
8.1 Acceptance of Environmental Condition 21
8.2 Remedy for Environmental Defects 19
8.3 Acceptance of Environmental Condition 23
8.4 NORM 24
8.5 Environmental Indemnities 24
9. THIRD-PARTY PREFERENTIAL RIGHTS TO PURCHASE, CONSENTS, AND TAG ALONG RIGHTS 25
9.1 Third Party Notices 25
9.2 Third-Party Exercise 25
9.3 Third-Party Failure to Purchase 25
9.4 Tag Along Rights 25
10. CONDITIONS TO CLOSING; SETTLEMENT STATEMENT; CLOSING 29
10.1 Seller's Conditions to Closing 29
10.2 Buyer's Conditions to Closing 30
10.3 Closing Settlement Statement 31
10.4 Closing Date and Place 31
10.5 Closing Activities 31
11. POST-CLOSING OBLIGATIONS 32
11.1 Recordation and Filing of Documents 32
11.2 Records 32
11.3 Final Settlement Statement 33
11.4 Suspense Accounts 33
11.5 Further Assurances 34
11.6 Volume Commitment 34
12. TAXES 34
12.1 Property Taxes 34
12.2 Production Taxes 34
12.3 Other Taxes 35
ii
12.4 Transfer Taxes 35
12.5 Tax Returns 35
13. OWNERSHIP OF ASSETS 35
13.1 Distribution of Production 35
13.2 Proration of Income and Expenses 36
13.3 Notice to Remitters of Proceeds 36
13.4 Production Imbalances 36
13.5 Pipeline and Other Non Well-head Imbalances 37
14. INTERIM OPERATIONS 37
14.1 Standard of Care 37
14.2 Liability of Operator 38
14.3 Removal of Signs 38
14.4 Non-Operated Assets 38
14.5 Third-Party Notifications 38
14.6 Accounting Cooperation 38



15. EXCHANGE PROVISION 39
16. ASSUMPTION OF LIABILITY AND GENERAL INDEMNIFICATION 39
16.1 Buyer's Assumption of Obligations 39
16.2 Definitions 39
16.3 Buyer's General Indemnity 40
16.4 Seller's General Indemnity 41
16.5 Limitation on Indemnification 42
16.6 Further Limitation on Indemnification 42
16.7 Indemnification Procedures 42
17. CASUALTY LOSS 43
18. NOTICES 44
19. TERMINATION 44
19.1 Termination 44
19.2 Liabilities Upon Termination; Deposit Amount 45
20. MISCELLANEOUS 45
20.1 Entire Agreement 45
20.2 Survival 45
20.3 Arbitration and Dispute Resolution Procedures 46
20.4 Confidentiality 48
20.5 Choice of Law 48
20.6 Assignment 48
20.7 No Admissions 48
20.8 Amendments 49
20.9 Counterparts 49
20.10 Third-Party Beneficiaries 49
20.11 Public Communications 49
20.12 Headings 49
20.13 Expenses 49
ii
20.14 Waiver of Consumer and Other Rights 49
20.15 Non-Compensatory Damages 50
List of Exhibits:
Exhibit "A" — Leases and Mineral Rights
Exhibit "A-1" — Gas Gathering System Plat
Exhibit "A-2" — Oil Gathering System Plat
Exhibit "A-3" — Water Recycling System Plat
Exhibit "A-4" — Gas Gathering System Equipment, Easements, and Surface Rights
Exhibit "A-5" — Oil Gathering System Equipment, Easements, and Surface Rights
Exhibit "A-6" — Water Recycling System Equipment, Easements, and Surface Rights
Exhibit "B" — Wells
Exhibit "C" — Surface Rights
Exhibit "D" — Excluded Assets
Exhibit "E" — Allocated Values
Exhibit "F" — Assignment, Conveyance, and Bill of Sale
Exhibit "G" — TAR Election Letter
List of Schedules:
Schedule 5.6—Taxes
Schedule 5.7—Material Contracts
Schedule 5.8—Litigation and Claims
Schedule 5.10—Notices of Violation
Schedule 5.11—Imbalances
Schedule 5.12—Throughput Obligations
Schedule 5.14—Outstanding Obligations
Schedule 5.16—Consents
Schedule 5.17—Preferential Purchase Rights; AMIs; MFNs
Schedule 5.18—Surety Bonds
Schedule 5.21—Suspense Accounts
Schedule 5.22—Screaming Eagle Project Payout Balance
Schedule 13.4—Production Imbalances
Schedule 14.1—Certain Permitted Pre-Closing Actions



# PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (“Agreement”) is entered into this 18 \( ^{th} \)  day of January, 2017 (“Execution Date”) by and between SAMSON EXPLORATION, LLC, a Texas limited liability company whose address is 110 West 7 \( ^{th} \)  Street, Suite 2000, Tulsa, Oklahoma 74119 (“Seller”), and HALCON ENERGY PROPERTIES, INC., a Delaware corporation whose address is 1000 Louisiana Street, Suite 6700, Houston, Texas 77002 (“Buyer”). Buyer and Seller are sometimes referred to below individually as a “Party” or collectively as the “Parties.”

WHEREAS, Buyer desires to purchase from Seller, and Seller desires to sell to Buyer, the Assets (as defined below) on the terms and conditions set forth below.

NOW, THEREFORE, in consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

## ARTICLE 1

## 1. DEFINITIONS

“AAA” has the meaning set forth in Section 20.3(b).

“Additional Interest” has the meaning set forth in Section 7.2.

“Allocated Values” has the meaning set forth in Section 3.4.

“Arbitrable Dispute” has the meaning set forth in Section 20.3(b).

“Assets” has the meaning set forth in ARTICLE 2.

“Assumed Imbalance” has the meaning set forth in Section 13.4.

“Assumed Obligations” has the meaning set forth in Section 16.1.1.

“Base Purchase Price” has the meaning set forth in Section 3.1.

“Block” means a block of land described on Exhibit “E” used as a basis for Seller to reflect its Working Interest and Net Revenue Interest - notwithstanding the effects of any pooling, communication, unitization, or contractual interests - for any future well that would be drilled in a unit consisting of all, but not more than all, of that block of land as to all depths above the base of the Wolfcamp Formation or such additional depth limitations set forth on Exhibit “E”.

“Business Day” means any day, other than Saturday or Sunday, on which commercial banks are open for commercial business with the public in Tulsa, Oklahoma.

“Buyer” has the meaning set forth in the Preamble.

“Buyer Group” has the meaning set forth in Section 16.2.

“Buyer’s Knowledge” means the actual personal knowledge of Floyd Wilson, Steve Herod or David Elkouri, after reasonable inquiry into their respective areas of responsibility.

“Casualty Defect” has the meaning set forth in ARTICLE 17.

“Claims” means any and all claims, rights, demands, causes of action, liabilities (including civil fines), damages, losses, fines, penalties, sanctions of every kind and character, whether suffered or incurred by a Party or arising in connection with a claim or action by a third party, including fees and expenses of attorneys, technical experts and expert witnesses, judgments or proceedings of any kind or character whatsoever, whether arising or founded in law, equity, statute, contract, tort, strict liability or voluntary settlement and all expenses, costs and fees (including reasonable attorneys’ fees) in connection therewith.

“Claimant” has the meaning set forth in Section 20.3(b).

“Cleanup” has the meaning set forth in Section 8.1(d).

“Closing” has the meaning set forth in Section 10.4.

“Closing Settlement Statement” has the meaning set forth in Section 10.3.

“Code” means the Internal Revenue Code of 1986, as amended, and any successor statute, and the regulations and administrative guidance promulgated thereunder.



“Consents” has the meaning set forth in Section 9.1.

“Contracts” means all contract rights relating to the Interests, Wells, Equipment, Easements, Hydrocarbons, Surface Agreements, Permits, or Imbalances, including, but not limited to, any operating agreements, joint venture agreements, unit agreements, orders and decisions of state and federal regulatory authorities establishing units, unit operating agreements, farmout agreements, processing agreements, transportation agreements, gathering and processing agreements, enhanced recovery and injection agreements, farm-in agreements, balancing agreements, options, drilling agreements, exploration agreements, seismic agreements, gas sales agreements, and assignments of operating rights, working interests, subleases and rights above or below certain footage depths or geological formations, to the extent the same are directly related to the Interests, together with all of Seller’s interest, rights and claims in, to and under the Screaming Eagle Agreement (including, without limitation, all rights and claims, from and after the Closing, (i) to recoup any amounts attributable to Project Payout (regardless of when the costs, expenses or liabilities giving rise to the Project Payout amount being recouped) and to receive and retain any payments made by TRO-X Group members in connection with the acceleration of Project Payout after Closing (or, to the extent applicable, any subsequent Closing pursuant to the terms of this Agreement), as contemplated in the Screaming Eagle Agreement).

“Conveyances” means the Assignment, Conveyance, and Bill of Sale substantially in the form attached as Exhibit “F” and any other mutually agreeable assignments, deeds, and/or bills of sale conveying the Assets to Buyer in accordance with the terms of this Agreement, to be executed and delivered in accordance with the provisions of Section 10.5.2. To the extent a Conveyance includes any interests of a TAR Seller then said Conveyance shall include an assignment of the “by, through and under” title warranty received from the applicable TAR Sellers.

“Current Tax Period” means the Tax period in which the Effective Time occurs.

“Deductible Amount” has the meaning set forth in Section 7.5.

“Deposit” has the meaning set forth in Section 3.2.

“Designating Judge” has the meaning set forth in Section 20.3(b).

“Due Diligence Period” has the meaning set forth in Section 7.1.

“Easements” means rights-of-way, easements, permits, licenses, approvals, servitudes and franchises specifically acquired for, or used in connection with, operations for the exploration and production of oil, gas or other minerals on or from the Interests or otherwise in connection with the Wells, Equipment, Gathering System, Gathering Equipment or Surface Agreements or other Assets, including, without limitation, the rights to permits and licenses of any nature owned, held, or operated in connection with said operations.

“Effective Time” means 7:00 a.m. local time where the Interests are located on November 1, 2016.

“Environmental Adjustment” has the meaning set forth in Section 8.2(a).

“Environmental Defect” has the meaning set forth in Section 8.1.

“Environmental Laws” means any and all present and future laws, statutes, regulations, rules, orders, ordinances, codes, plans, requirements, criteria, standards, decrees, judgments, injunctions, notices, demand letters, permits, licenses, or determinations issued or promulgated by any federal, state, or local governmental authority pertaining to (a) use, storage, transportation, production, recycling, handling, treatment, emission, discharge, clean-up, release, or threatened release of pollutants, contaminants, NORM, chemicals, or industrial, toxic or hazardous wastes or substances or solid wastes (collectively, “Pollutants”) on or into the environment or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transportation or handling of Pollutants, (b) health, (c) the environment, or (d) wildlife or natural resources applicable to the Assets and in effect in or for the jurisdiction in which the Assets are located, including, without limitation, the Clean Air Act (Air Pollution Control Act), the Clean Water Act, the Federal Water Pollution Act, the Rivers and Harbors Act, the Safe Drinking Water Act, the National Environmental Policy Act of 1969 (NEPA), the Endangered Species Act, the Fish and Wildlife Conservation Act of 1980, the Fish and Wildlife Coordination Act (FWCA), the Oil Pollution Act, the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the Superfund Amendments and Reauthorization Act of 1986 (SARA), the Resources Conservation and Recovery Act (RCRA), the Toxic Substance Control Act, the Occupational, Safety and Health Act (OSHA), the Hazardous Materials Transportation Act, the Hazardous and Solid Waste Amendments of 1984 (HSWA), and any and all other applicable present and future federal, state and local laws, statutes, regulations, rules, orders, ordinances, codes, plans, requirements, criteria, standards, decrees, judgments, injunctions, notices, demand letters, permits, licenses or determinations whose purpose is to regulate Pollutants or to conserve or protect health, the environment, wildlife or natural resources as any of the foregoing are now existing or may hereafter be amended or interpreted.

“Environmental Notice” has the meaning set forth in Section 8.1.

“Equipment” has the meaning set forth in Section 2.3.

“Escrow Account” has the meaning set forth in Section 3.2.

“Escrow Agent” has the meaning set forth in Section 3.2.

“Excluded Assets” has the meaning set forth in Section 2.11.



“Execution Date” has the meaning set forth in the Preamble.

“Final Settlement Statement” has the meaning set forth in Section 11.3.

“Governmental Authorities” means any court or tribunal in any jurisdiction (domestic or foreign) or any federal, state, county, municipal or other governmental or quasi-governmental body, agency, authority, department, board, commission, bureau or instrumentality.

“Hydrocarbons” has the meaning set forth in Section 2.4.

“Imbalances” has the meaning set forth in Section 2.10.

“Interests” has the meaning set forth in Section 2.1.

“Leases” has the meaning set forth in Section 2.1.

“Litigation” means those items set forth on Schedule 5.8.

“Loss” has the meaning set forth in Section 8.1(e).

“Material Contracts” means any (i) Contract that can reasonably be expected to result in aggregate payments by Seller of more than $100,000 during the current or any subsequent fiscal year or $250,000 in the aggregate over the term of such Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues) that cannot be terminated by Seller on not greater than 90 days’ notice; (ii) any Contract that can reasonably be expected to result in aggregate revenues to Seller of more than $100,000 during the current or any subsequent fiscal year or $250,000 in the aggregate over the term of such Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues); (iii) any Contract that (A) is a Hydrocarbon purchase and sale, gathering, transportation, processing, compression or similar Contract pursuant to which Seller received annual revenues or makes annual payments in excess of $100,000 and (B) is not terminable by Seller or its assignee without penalty on 60 days’ or less notice; (iv) any Contract that is an indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bonds, letters of credit or similar financial Contract, except any such Contract with an aggregate outstanding principal amount not exceeding $100,000; (v) any Contract that constitutes a lease under which Seller is the lessor or the lessee of real, immovable, personal or movable property which lease (A) cannot be terminated by Seller without penalty upon 60 days or less notice and (B) involves an annual base rental of more than $100,000; (vi) Contracts with any affiliate of Seller other than joint operating agreements; and (vii) Contracts that create any area of mutual interest to which any of the Assets are subject and that are currently in force and effect or contain any non-compete provision. Material Contracts do not include any “master” type vendor or consulting agreements.

“Mineral Rights” has the meaning set forth in Section 2.1.

“Net Revenue Interest” means the interest in and to all production of Hydrocarbons saved, produced and sold or which can be produced and sold from any Well or Block after giving effect to all valid lessor’s royalties, overriding royalties, production payments, carried interests, liens,

net profits interests, volumetric production payments, and other encumbrances or charges against production therefrom related to such interest.

“NORM” means naturally occurring radioactive material.

“Open Defect” has the meaning set forth in Section 7.4(c).

“Oxy” has the meaning set forth in Section 9.4(b)iv.

“Parties” and “Party” have the meaning set forth in the Preamble.

“Permits” has the meaning set forth in Section 2.6.

“Permitted Encumbrances” means (i) any third party consents to assignment and similar agreements with respect to which waivers or comments are obtained prior to Closing; (ii) easements, rights of way, servitudes, licenses and permits on, over, across or in respect of any of the Assets which do not materially interfere with the use, operation or development of the Assets; (iii) rights reserved to or vested in any governmental agency to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable laws, rules and orders of any such governmental agency or under any franchise, grant, license or permit issued by any such governmental agency; (iv) materialmen's, mechanics', repairmen's, employees', contractors', operators', Tax and other similar liens or charges arising in the ordinary course of business incidental to the construction, maintenance or operation of any of the Assets: (a) if filed, has not yet become due and payable and payment is being withheld as provided by law or (b) is being contested in good faith in the ordinary course of business by appropriate action, in either event Seller shall have notified Buyer in writing prior to Closing and shall have agreed to fully indemnify, defend and hold Buyer harmless after Closing; (v) any other liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects or irregularities of any kind whatsoever affecting the Assets that do not operate to reduce Seller's Net Revenue Interest of any Interest below that set forth for Seller on Exhibit "E" for such Interest or increase Seller's Working Interest for any Interest above that set forth for Seller on Exhibit "E" for such Interest without a proportionate increase in the corresponding Net Revenue Interest and which does not materially impair the use of such Interest for the purposes for which it is currently owned and operated; (vi) defects and irregularities arising out of the lack of a survey; (vii) defects or irregularities arising out of the lack of recorded powers of attorney from corporations or partnerships to execute and deliver documents on their behalf; (viii) defects in the chain of title consisting of failure to recite marital status or the omission of succession or heirship or estate proceedings; (ix) any of the matters clearly disclosed on Exhibits "A" or "B" or any Schedule to this Agreement (excluding, however, any information that may be disclosed in documents or instruments merely referred to on Exhibits "A" or "B" or any Schedule to this Agreement); (x) defects based solely on lack of information in Seller's files; (xi) defects or irregularities arising out of prior oil and gas leases which by their terms and on their face, expired more than ten (10) years prior to the Effective Time, and which have not been released of record;



(xii) defects or irregularities arising out of mortgages or deeds of trust which, by their terms and on their face, expired and terminated more than ten (10) years prior to the Effective Time but which remain unreleased of record; (xiii) defects and irregularities cured by possession under applicable statutes of limitation and statutes relating to prescription (insofar as Seller has provided Buyer with evidence thereof reasonably satisfactory to Buyer); (xiv) preferential rights to purchase which are subject to ARTICLE 9; (xv) any absence or loss of rights, defects, liens, or encumbrances of any kind with respect to depths below the base of the Wolfcamp Formation; and (xvi) any interest

owned by or defects, liens, or encumbrances of any kind with respect to any TAR Owners who are not TAR Sellers.

“Preferential Purchase Right” has the meaning set forth in Section 9.1.

“Project Payout” has the meaning set forth in Section 4 of the Screaming Eagle Agreement.

“Real Property Taxes” has the meaning set forth in Section 12.1.

“Records” has the meaning set forth in Section 2.9.

“Required Consent” has the meaning set forth in Section 10.2(c).

“Respondent” has the meaning set forth in Section 20.3(b).

“Reversionary Interests” has the meaning set forth in Section 9.4.

“Screaming Eagle Agreement” has the meaning set forth in Section 9.4.

“Seller” has the meaning set forth in the Preamble.

“Seller Group” has the meaning set forth in Section 16.2.

“Seller’s Knowledge” means the actual personal knowledge of Keith St. Gemme, Kurt Primeaux, Drew Phillips, Scott Rowland, and Mark Lauer, after reasonable inquiry into their respective areas of responsibility.

“Surface Agreements” means any surface leases, surface use right or agreements or any similar rights, agreements or licenses relating to the Interests, Wells, Equipment, Gathering System, Gathering Equipment or Hydrocarbons.

“Surface Fee” means the real property in which Seller owns an interest in the surface estate which is identified as Surface Fee on Exhibit “C,” as well as all structures thereon and improvements thereto.

“Suspense Accounts” has the meaning set forth in Section 11.4.

“Tag Along Rights” has the meaning set forth in Section 9.4.

“TAR Owners” has the meaning as set forth in Section 9.4.

“TAR Pref Right” has the meaning as set forth in Section 9.4(b)iv.

“TAR Sellers” has the meaning as set forth in Section9.4(b).

“Title Defect” has the meaning set forth in Section 7.1.

“Taxes” means any taxes, assessments, unclaimed property or escheat obligations and other governmental charges imposed by any Governmental Authority, including gross income, net income, profits, gross receipts, license, employment, stamp, occupation, premium, alternative or add-on minimum, ad valorem, real property, personal property, transfer, real property transfer, value added, sales, use, customs, duties, capital stock, franchise, excise, withholding, social

security (or similar), unemployment, disability, payroll, windfall profit, severance, production, environmental (including taxes under Code Section 59A) estimated or other tax, including any interest, penalty or addition thereto, whether disputed or not.

“Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto, and including any amendment thereof.

“Volume Commitment Shortfall Payments” means any payment paid by Seller (or Buyer as Seller’s successor in interest) to the counterparty to that certain Gas Gathering Agreement dated October 1, 2012 between Regency Field Services, LLC and EXL Petroleum, LP and that certain Interconnect Agreement dated August 1, 2016 between Enterprise GC LLC and Seller, in each case to the extent such payment is the result of a failure to satisfy the volume commitments contained therein in a timely manner.

“Wells” has the meaning set forth in Section 2.2.



“Wolfcamp Formation” means the geologic formation the base of which is seen at a measured depth of 14,728 feet on the April 13, 1979 electric log of the C&K Petroleum, Inc. White-State No. 1 Well (API No. 42371326820000).

“Working Interest” means with respect to the Wells and Blocks, the interest in and to the full and entire mineral and/or leasehold estate created under and by virtue of the Interests and all rights and obligations of every kind and character appurtenant thereto or arising therefrom, without regard to any valid lessor’s royalty, overriding royalties, production payments, carried interests, liens, or other encumbrances or charges against production therefrom insofar as such interest in said leasehold estate is burdened with the obligation to bear and pay costs of operations.

## ARTICLE 2

## 2. PURCHASE AND SALE

Seller agrees to sell to Buyer, and Buyer agrees to buy from Seller, effective as of the Effective Time, for the consideration recited and subject to the terms and conditions set forth in this Agreement, all of Seller’s right, title and interest in and to the following (all such right, title, and interest collectively referred to as the “Assets”):

2.1 Interests - Those certain oil and gas properties, leases, and oil, gas and mineral leases described on Exhibit “A” attached hereto (“Leases”), and any fee mineral interests, mineral rights and/or mineral servitudes described on Exhibit “A” (the “Mineral Rights”), together with all other rights, titles and interests in the Leases and Mineral Rights and any other lands or interests covered thereby, associated therewith or pooled, unitized or communitized therewith, including, without limitation, all working interests, royalty interests, overriding royalty interests, net profits interests, production payments, mineral interests, forced pooled interests, and interests acquired under contracts or otherwise in the lands covered by the Leases and/or Mineral Rights, and any other lands or interests pooled, unitized or communitized therewith, including water rights, if any, provided, however, that all of the foregoing are subject to the limitations described in said Exhibit “A” (the Leases, Mineral Rights and the lands and other interests are collectively referred to herein as the “Interests”).

2.2 Wells - The oil and gas wells, salt water disposal wells, injection wells and other wells and wellbores located on or attributable to the Interests or on lands pooled or unitized with any portion thereof, or on lands located within any governmental drilling and spacing unit which includes any portion thereof, whether producing, plugged or unplugged, shut-in or permanently or temporarily abandoned, including, but not limited to, the wells identified on Exhibit “B” (the “Wells”).

2.3 Equipment - All personal property, fixtures and improvements and facilities, spare parts and inventory (insofar as the same are located on the Interests, Easements, Surface Agreements, and/or Surface Fee), equipment, pipelines, pipeline laterals, well pads, tank batteries, well heads, treating equipment, compressors, power lines, casing, tubing, pumps, motors, gauges, valves, heaters, treaters, appurtenant to the Interests or Wells or used in connection with the ownership or operation of the Interests or Wells or the production, treatment, sale or disposal of Hydrocarbons, including but not limited to, facilities, gathering systems, plants, treating and processing systems, casing, pipelines and gathering systems, as well as all motor vehicles, tools, computers (subject to purging), telephones (subject to purging), or similar mobile personal property to the extent they are used in the field in connection with operation of the Interests (collectively, the “Equipment”).

2.4 Production - All of the oil, natural gas, condensate, casigned gas, products or other minerals, attributable or allocable to the Interests or Wells (i) from and after the Effective Time or (ii) which are in storage above the pipeline connection as of the Effective Time, or (iii) with regard to any under-produced volumes of Seller attributable to the Imbalances (the “Hydrocarbons”).

2.5 Surface Rights - All the Easements and Surface Agreements set forth on Exhibit “C,” as well as all of the Surface Fee.

2.6 Contract Rights and Permits - All environmental and other governmental (whether federal, state or local) permits, licenses, orders, authorizations, franchises and related instruments or rights relating to the ownership, operation or use of the Interests, Wells, Equipment, Hydrocarbons, Easements and Surface Agreements (the “Permits”), as well as all Contracts.

2.7 Gathering System - The gas gathering system depicted on the plat attached hereto as Exhibit “A-1,” the oil gathering system depicted on the plat attached hereto as Exhibit “A-2,” and the water recycling system depicted on the plat attached hereto as Exhibit “A-3” (collectively, the “Gathering System”), including all pipelines, trunk lines, laterals, pipeline interconnects and other receipt and delivery facilities, meters, check meters, and metering stations, measurement and regulation equipment, dehydration equipment, compressors and compression facilities and equipment, quality measurement equipment, valves, generators, motors, pumping stations and equipment, cathodic and electrical protection units, bypasses, gas samplers, regulators, drips, flanges, pigs and pig traps, flow control equipment, and other connections, fittings, spare parts, facilities, fixtures, inventories, pad gas, and tangible personal and mixed property and improvements, whether movable or immovable, that are located on or are appurtenant to, or that affect the Gathering System or are used in connection with, installed in or on, or otherwise relate to the ownership and operation of the

Gathering System and the gathering and transportation of Hydrocarbons pursuant thereto, including those items of personal property and equipment identified on Exhibits “A-4,” “A-5,” and “A-6” (collectively, the “Gathering Equipment”), together with all Easements and Surface Rights related to the Gathering System and the Gathering Equipment, including, without limitation, those described on Exhibits “A-4,” “A-5,” and “A-6.”

2.8 Interests of TAR Owners - All right, title, and interest acquired by Seller from the TAR Owners pursuant to the provisions set forth in Section 9.4.



2.9 Files and Records - All of the files, records and data directly relating to the items and interests described in Sections 2.1 through 2.6 above including, without limitation, land and lease files, well files, title records including abstracts of title, title opinions, title insurance reports/policies, property ownership reports, division order and right-of-way files, prospect information, contracts, production records, all logs including electric logs, core data, pressure data and decline curves and graphical production curves, customer lists, supplier lists, sales materials, promotional materials, operational records, technical records, production and processing records, accounting files and contract files, and all related materials in the possession of Seller, LESS AND EXCEPT all legal files and records (other than legal files and records included in, or are part of, the above-referenced files and records, such as, for example, title opinions, title curative materials, environmental and regulatory reports and assessments), Seller’s federal or state income, franchise or margin Tax files and records, employee files, reserve evaluation information or economic projections (other than reserve evaluation or economic projection materials and files previously made available to Buyer), competing bids, proprietary data, information and data under contractual restrictions on assignment, privileged information, intellectual property, and seismic data, geophysical, geological, or other similar information or data (collectively, the “Records”).

2.10 Gas and Pipeline Imbalances - Subject to the provisions of Sections 13.4 and 13.5, any production or pipeline imbalances associated with the Assets, whether arising before, on or after the Effective Time (collectively, the “Imbalances”).

2.11 Excluded Assets - Seller hereby reserves and excepts from the sale and conveyance of the Assets in favor of itself, its successors and assigns all items identified on Exhibit “D” (the “Excluded Assets”), which shall not be considered as part of the Assets for any purposes hereunder.

## ARTICLE 3

## 3. PURCHASE PRICE AND ALLOCATION

3.1 Base Purchase Price - Buyer agrees to pay for the Assets the total sum of Seven Hundred Five Million Dollars ($705,000,000) (“Base Purchase Price”) in cash, subject only to the price adjustments set forth in this Agreement.

3.2 Performance Deposit and Payment - Not later than one (1) Business Day after the execution and delivery of this Agreement, Buyer shall deposit by wire transfer in immediately available funds into an account (the “Escrow Account”) with JPMorgan Chase Bank, N.A. (the “Escrow Agent”), the sum of $55,000,000 (such amount, together with any interest earned thereon (the “Deposit”) to be held, invested, and disbursed in

accordance with the terms of this Agreement and the Escrow Agreement. Buyer and Seller agree to execute and deliver joint written instructions to the Escrow Agent, directing the release of the Deposit in accordance with the terms of this Agreement. Buyer and Seller shall each bear 50% of the cost and fees owed to the Escrow Agent related to the Deposit.

3.3 Adjustments to the Base Purchase Price - The Base Purchase Price shall be adjusted as follows:

(a) Upward Adjustments. The Base Purchase Price shall be adjusted upward for the following, without duplication:

(i) all normal and customary production expenses, operating expenses, operated and non-operated overhead charges (excluding any corporate overhead costs beyond what is permitted by the applicable Operating Agreements) and approved capital expenditures paid or incurred by Seller in connection with the ownership and operation of the Assets attributable to the periods from and after the Effective Time (including, without limitation, royalties and Taxes attributable to Hydrocarbons produced and saved from and after the Effective Time, and approved pre-paid charges), excluding, however, any costs incurred or paid to cure any Title Defects, Environmental Defects, or Casualty Defects, and excluding Seller’s Taxes based upon income, profits or capital gains, and excluding lease bonuses and other costs of acquisition of Leases, broker’s fees, and other lease acquisition costs (said exclusion does not apply to lease extension costs);

(ii) all proceeds attributable to the sale of Hydrocarbons from the Assets and all other income and benefits received by Buyer attributable to production, ownership and operation of the Assets prior to the Effective Time (excluding any payments received by, or recoupments taken by, Buyer from and after Closing relative to the Project Payout;

(iii) all adjustments for oil in inventory or gas beyond the meters, as provided in Section 13.1;

(iv) to the extent the Imbalances reflect an under-balanced (or under-produced or under-received balance) position of Seller as of the Closing regarding the Assets, all adjustments regarding such under-balanced Imbalances, in accordance with the provisions of Sections 13.4;

(v) adjustments for over-delivered pipeline imbalances as provided in Section 13.5; and

(vi) any other upward adjustments to the Base Purchase Price specified in this Agreement.

(b) Downward Adjustments. The Base Purchase Price shall be adjusted downward as follows, without duplication:

(i) an amount equal to the Deposit;



(ii) all production expenses, operating expenses, operated and non-operated overhead charges and other costs under applicable operating agreements and other expenses, costs and charges paid or incurred by Buyer in connection with the Assets and attributable to periods prior to the Effective Time, including, without limitation, Taxes, capital expenses and other costs;

(iii) all proceeds attributable to the sale of hydrocarbons and all other income and benefits received by Seller and attributable to the production, operation or ownership of the Assets on or after the Effective Time;

(iv) all adjustments regarding Title Defects, in accordance with the provisions of ARTICLE 7 (reduced by any offsets for Additional Interests);

(v) all adjustments regarding Environmental Defects, in accordance with the provisions of ARTICLE 8;

(vi) all adjustments regarding unobtained Required Consents and exercised Preferential Purchase Rights, as contemplated in ARTICLE 9;

(vii) an amount equal to the amounts held in the Suspense Accounts as of the Closing, as contemplated in Section 11.4;

(viii) to the extent the Imbalances reflect an over-balanced (or over-produced or over-received balance) position of Seller as of the Closing regarding the Assets, all adjustments regarding such overbalanced Imbalances, in accordance with the provisions of Sections 13.4;

(ix) adjustments for under-delivered pipeline imbalances, as provided in Section 13.5;

(x) an amount equal to the Volume Commitment Shortfall Payments, if any; and

(xi) any other downward adjustments to the Base Purchase Price specified in this Agreement.

3.4 Allocation of Base Purchase Price - Seller and Buyer agree that the Base Purchase Price shall be allocated among the Interests as set forth for Seller on Exhibit “E” (the “Allocated Values”) for the purpose of (i) establishing a basis for certain Taxes, (ii) providing notices, or obtaining waivers, of any preferential rights to purchase the Assets, (iii) determining the value of a Title Defect, and (iv) handling those instances for which the Base Purchase Price is to be adjusted.

3.5 Allocation of Adjusted Base Purchase Price - For purposes of Taxes, Buyer and Seller agree that the allocation of the purchase price (as determined for such purposes), is consistent with Section 1060 of the Code, and Treasury Regulations thereunder (and, as adjusted hereunder, if applicable, in accordance with any other similar provision of state or local law). Buyer and Seller shall report the purchase and sale of the Assets on all Tax Returns (including IRS Form 8594) consistently with Exhibit “E” and shall not take any

position that is inconsistent with Exhibit “E” unless otherwise required by applicable Law. Exhibit “E” may be revised from time to time, upon the mutual written consent of Buyer and Seller, to take into account any matters that need updating (such as Base Purchase Price adjustments).

## ARTICLE 4

## 4. ACCESS TO ASSETS AND DATA; DISCLAIMERS

4.1 Access - Seller shall provide Buyer and Buyer’s authorized representatives, at any reasonable time(s) before the Closing, (i) reasonable physical access, at Buyer’s sole risk, cost and expense, to the lands, Wells and Equipment on or associated with the Assets that are Seller-operated to allow Buyer to conduct on-site Phase I environmental site assessments and regulatory compliance assessments of the Assets and (ii) access to the Records, to the extent the Records are in Seller’s or its representative’s possession, and relate to the Assets; provided, however, that Seller shall have no obligation to provide Buyer access to any interpretative or predictive data or information which Seller considers confidential or proprietary or which Seller believes in good faith it cannot lawfully provide Buyer because of third-party restrictions (to the extent any such data or information is proprietary or subject to third-party restrictions, Seller will use its good-faith efforts to obtain any consents necessary to allow Buyer to review such data or information). In connection with such on-site inspections, Buyer agrees to not unreasonably interfere with the normal operation of the Assets and further agrees that under no circumstances shall it perform any invasive tests of any nature on the Assets without the express written consent of Seller. In connection with granting such access, and except to the extent that such claims are caused by the gross negligence or willful misconduct of Seller, Buyer waives and releases all claims against Seller Group (as defined in Section 16.2) for injury to, or death of persons, or damage to property directly caused by Buyer or its representatives in connection with the performance of this diligence and Buyer agrees to indemnify, defend and hold harmless Seller Group (as defined in Section 16.2) from and against all such claims.

4.2 Disclaimer - Buyer specifically understands and acknowledges the following:

4.2.1 Title - Title to the Assets shall be transferred and conveyed to Buyer at Closing with a “by, through and under” warranty of title of Seller and the Seller shall also assign to Buyer the “by, through and under” warranty of title received from the TAR Sellers.

4.2.2 Disclaimer of Warranty - EXCEPT AS OTHERWISE SET FORTH IN THIS AGREEMENT, OR IN THE CONVEYANCES, SELLER EXPRESSLY DISCLAIMS AND NEGATES ANY REPRESENTATION, COVENANT OR WARRANTY, EXPRESS OR IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE, RELATING TO THE CONDITION OF THE ASSETS AND ANY PERSONAL PROPERTY, EQUIPMENT, FIXTURES AND ITEMS OF MOVABLE PROPERTY COMPRISING ANY PART OF THE ASSETS INCLUDING (i) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS



FOR ANY PARTICULAR PURPOSE; (ii) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS; (iii) ANY RIGHTS OF BUYER UNDER APPLICABLE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN

OF THE BASE PURCHASE PRICE; (iv) ANY CLAIM BY BUYER FOR DAMAGES BECAUSE OF DEFECTS OR OTHER VICES, WHETHER KNOWN OR UNKNOWN; (v) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT OR INFRINGEMENT OF ANY OTHER INTELLECTUAL PROPERTY RIGHT; (vi) ANY IMPLIED OR EXPRESS WARRANTY REGARDING ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT INCLUDING, WITHOUT LIMITATION, NATURALLY OCCURRING RADIOACTIVE MATERIAL OR ASBESTOS, OR PROTECTION OF THE ENVIRONMENT OR HEALTH; OR (vii) ANY IMPLIED OR EXPRESS WARRANTY REGARDING TITLE TO ANY OF THE ASSETS. IT IS THE EXPRESS INTENTION OF BUYER AND SELLER THAT, EXCEPT AS OTHERWISE SET FORTH IN THIS AGREEMENT, OR IN THE CONVEYANCES, THE PERSONAL PROPERTY, EQUIPMENT, FIXTURES AND ITEMS AND THE CONDITION OF THE ASSETS ARE BEING CONVEYED TO BUYER "AS IS, WHERE IS," WITH ALL FAULTS, AND IN THEIR PRESENT CONDITION AND STATE OF REPAIR. BUYER REPRESENTS TO SELLER THAT IT HAS BEEN GIVEN THE OPPORTUNITY TO MAKE OR CAUSE TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

4.2.3 Additional Disclaimer - EXCEPT AS OTHERWISE SET FORTH IN THIS AGREEMENT OR IN THE CONVEYANCES, SELLER HEREBY EXPRESSLY NEGATES AND DISCLAIMS, AND BUYER HEREBY WAIVES AND ACKNOWLEDGES THAT SELLER HAS NOT MADE, ANY WARRANTY, REPRESENTATION OR COVENANT, EXPRESS OR IMPLIED, AS TO THE ACCURACY OR COMPLETENESS OR MATERIALITY OF ANY FILES, RECORDS, DATA, INFORMATION, OR MATERIALS (WRITTEN OR ORAL) HERETOFORE OR HEREAFTER FURNISHED TO BUYER IN CONNECTION WITH THE ASSETS, OR AS TO THE QUALITY OR QUANTITY OF HYDROCARBON RESERVES (IF ANY) ATTRIBUTABLE TO THE ASSETS OR THE ABILITY OF THE ASSETS TO PRODUCE HYDROCARBONS. ANY AND ALL SUCH FILES, RECORDS, DATA, INFORMATION, AND OTHER MATERIALS FURNISHED BY SELLER IS PROVIDED TO BUYER AS A CONVENIENCE, AND ANY RELIANCE ON OR USE OF THE SAME SHALL BE AT BUYER'S SOLE RISK.

## ARTICLE 5

## 5. SELLER'S REPRESENTATIONS

Seller represents to Buyer, as of the date hereof and as of the Closing Date, as follows:

5.1 Existence - Seller is a limited liability company duly organized and validly existing and in good standing under the laws of the State of Texas, and is duly qualified to carry on its business as presently conducted and to own and operate oil and gas properties in each jurisdiction in which the Assets are located.

5.2 Authority - Seller has all requisite power and authority to carry on its business as presently conducted, to enter into this Agreement and the Conveyances and to perform its

obligations under this Agreement. This Agreement is, and the Conveyances and other agreements, documents or instruments to be delivered at Closing, when executed and delivered by Seller will be, the valid and binding obligation of Seller, enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). There are no bankruptcy, reorganization, or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened in writing against Seller.

5.3 Violations - To Seller’s Knowledge, Seller has not materially violated and none of the Assets are in material violation of any laws, statutes, regulations or orders applicable to such Assets.

5.4 Compliance - Seller has materially complied (and all of the Assets, as owned and operated, are in material compliance) with all applicable laws, rules, regulations, ordinances and orders of all local, tribal, state and federal governmental bodies, authorities and agencies having jurisdiction.

5.5 Payment of Royalties - To Seller’s Knowledge, all royalties, in-lieu royalties, production payments, net profits interests, and other burdens payable out of production with respect to the Assets, which accrued or are attributable to the period prior to Closing, have been properly and fully paid, escheated, or are included within the suspense amounts being conveyed to Buyer pursuant to Section 11.4.

5.6 Taxes. Except as set forth in Schedule 5.6, during the period of Seller’s ownership of the Assets, all Taxes that have become due and payable by Seller with respect to the Assets have been properly paid, other than any Taxes that are being contested in good faith and all Tax Returns required to have been filed with respect to the Assets have been timely filed (taking into account applicable filing extensions) and are complete and accurate in all material respects. Except as set forth on Schedule 5.6, Seller has not received written notice of, nor, to Seller’s Knowledge, is there pending or threatened, any claim or audit by any applicable Governmental Authority for the assessment of any Taxes that could result in an encumbrance on the Assets. All Taxes imposed on Seller that could result in an encumbrance or other claim against any of the Assets that have become due and payable have been properly paid, unless contested in good faith by appropriate proceeding listed on Schedule 5.6. None of the Assets are subject to any tax partnership agreement or provisions requiring a partnership income tax return to be



filed under Subchapter K of Chapter 1 of Subtitle A of the Code, or any similar state statute and no transfer of any part of the Assets will be treated as a transfer of an interest in a partnership for Tax purposes. All of the Assets have been properly listed and described on the property Tax rolls for all periods prior to and including the date of Closing and no portion of the Assets constitute omitted property for property Tax purposes.

5.7 Contracts and Permits. Schedule 5.7 sets forth, a true, correct and complete list of all Material Contracts, including all amendments and modifications thereto. Seller is not in default, and has not received written notice of any default, under any of the Material Contracts, and the Permits and the Material Contracts are in full force and effect. To Seller's Knowledge, Seller has all material permits, certificates, licenses, approvals, registrations, and authorizations under applicable laws necessary for the ownership or operation of the Assets, as currently owned and operated. Seller's Records contain true,

correct, and complete copies of all Material Contracts, including all amendments and modifications thereto.

5.8 Litigation and Claims. Except as set forth on Schedule 5.8, no suit, action, demand, proceeding, lawsuit, Claim or other litigation is pending or, to Seller’s Knowledge, threatened with respect to the Assets or Seller’s ownership or operation of any of the Wells, Leases, or other Assets.

5.9 Sale Contracts. Except for (a) contracts governing the sale of Hydrocarbons in the ordinary course or (b) the disposition in the ordinary course of equipment no longer suitable for oil and gas field operations, there are no contracts or options outstanding for the sale, exchange or transfer of Seller’s interest in the Assets or any portion thereof.

5.10 Notices. Except as set forth on Schedule 5.10, (a) Seller’s operation of the Assets is not the subject of any pending material regulatory compliance or enforcement actions and (b) Seller has not received written notice, which has not heretofore been complied with, in all material respects, of any violation of laws, rules or regulations (federal, state and local) issued with respect to the Assets.

5.11 Imbalances. To Seller’s Knowledge, except as set forth on Schedule 5.11, there are no gas or other Hydrocarbon production, pipeline, transportation or processing imbalances existing as of the Effective Time with respect to any of the Assets.

5.12 Take-or-Pay. Seller is not obligated under a take-or-pay or similar arrangement in any of the Contracts, and, except as noted on Schedule 5.12, there are no material throughput and deficiency or minimum volume obligations with respect to the delivery of Hydrocarbons by Seller after the Effective Time in any of the Material Contracts.

5.13 Timely Payment. Seller has paid its share of all costs payable by it under the Leases and the Material Contracts, except those not yet due or those being contested in good faith and described in Schedule 5.8.

5.14 Outstanding Obligations. Except as otherwise described in Schedule 5.14, to Seller’s Knowledge, there are no outstanding authorizations for expenditures in excess of One Hundred Thousand Dollars ($100,000), net to Seller’s interest, or other written commitments or proposals to conduct operations on the Assets.

5.15 Brokers. Seller has incurred no liability, contingent or otherwise, for broker’s or finder’s fees in respect of this Agreement or the transactions contemplated hereby for which Buyer shall have any responsibility whatsoever.

5.16 Consents. To Seller’s Knowledge, all Leases, Easements, Surface Agreements, and Material Contracts which contain a Consent provision are listed on Schedule 5.16.

5.17 Preferential Purchase Rights: AMIs; MFNs. To Seller’s Knowledge, all (i) Leases, Easements, Surface Agreements, and Material Contracts which contain Preferential Purchase Rights, (ii) Leases or Contracts which create any area of mutual interest that any of the Interests are subject, and (iii) Leases which contain any most favored nations provisions are, in each case, listed on Schedule 5.17. There are no outstanding or deferred bonuses remaining, or upon the satisfaction of a condition, could become outstanding, or

other acquisition costs, relating to any of the Leases or other Assets (excluding any extension payments).

5.18 Surety Bonds. All surety bonds held by Seller related to its ownership or operation of the Assets are listed on Schedule 5.18.

5.19 Current Plugging Obligations. To Seller’s Knowledge, as of the Execution Date there is no Well that is currently obligated by law, regulation or contract to be plugged and abandoned because such Well is not currently capable of producing in commercial quantities.

5.20 Payout. Exhibit “B” identifies the Wells subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than a termination of a Lease by its terms).

5.21 Suspended Amounts. Schedule 5.21 lists all funds held in suspense (including funds held in suspense for unleased interests) by Seller as of the date of this Agreement that are attributable to the Interests.

5.22 Screaming Eagle Agreement and Project Payout. The Screaming Eagle Agreement is in full force and effect and, to the Knowledge of Seller, has not been breached by any TRO-X Group members or Oxy, or previously by ExL, including, without limitation, with regard to the Tag Along Rights and the preferential right to purchase provisions under the Screaming Eagle Agreement. Subject to additional revenues or expenses not yet received or booked, and to adjustments made in the normal course of business, Seller believes that Schedule 5.22 sets forth



a true and accurate calculation of the Project Payout balance as of the Effective Time.

5.23 Leases and Interests: Pooling. The terms of the Leases, Mineral Rights or other Interests do NOT contain any remaining commitments or obligations of Seller to drill any wells.

## ARTICLE 6

## 6. BUYER'S REPRESENTATIONS

Buyer represents to Seller, as of the date hereof, as follows:

6.1 Information - Buyer represents that it is a sophisticated purchaser, knowledgeable in the evaluation of oil and gas properties and has performed due diligence on the Assets and performed all necessary tasks involved in evaluating the Assets, to the Buyer's complete satisfaction. SUBJECT TO THE OTHER TERMS OF THIS AGREEMENT, BUYER REPRESENTS AND WARRANTIES THAT ON THE CLOSING, BUYER WILL ACCEPT THE ASSETS AT CLOSING IN THEIR PRESENT CONDITION, "AS IS AND WHERE IS." BUYER ACKNOWLEDGES AND AGREES THAT, EXCEPT AS OTHERWISE SET FORTH IN THIS AGREEMENT AND IN THE CONVEYANCES, SELLER HAS MADE NO REPRESENTATIONS OR WARRANTIES OF ANY KIND, EXPRESS OR IMPLIED, WRITTEN OR ORAL, AS TO THE ACCURACY OR COMPLETENESS OF THE BACKGROUND MATERIALS OR ANY OTHER INFORMATION RELATING TO THE ASSETS FURNISHED BY OR ON BEHALF OF SELLER OR TO BE FURNISHED TO BUYER OR ITS

REPRESENTATIVES, INCLUDING WITHOUT LIMITATION ANY INTERNAL APPRAISALS AND/OR INTERPRETIVE DATA OF SELLER. Buyer acknowledges and affirms that it has relied and will rely solely upon Seller's representations, warranties and covenants in this Agreement and on its independent analysis, evaluation and investigation of, and judgment with respect to, the business, economic, legal, Tax or other consequences of this transaction, including its own estimate and appraisal of the extent and value of the petroleum, natural gas and other reserves associated with the Assets.

6.2 Knowledge and Experience - Buyer (i) is engaged in the business of exploring for and/or producing oil and gas or other valuable minerals as an ongoing business and (ii) is purchasing the Assets for its own account for investment purposes and not with the intent to resell the Assets in violation of any federal or state securities laws. Buyer is an experienced and knowledgeable investor in oil and gas properties, has the financial and business expertise to evaluate the merits and risks of the transactions covered by this Agreement and has relied solely on the basis of its own independent investigation of the Assets for all purposes. In acquiring the Assets, Buyer is acting in the conduct of its own business and not under any specific contractual commitment to any third party, or any specific nominee agreement with any third party, to transfer to, or to hold title on behalf of, such third party, with respect to all or any part of the Assets. Buyer acknowledges that it has had the opportunity to seek the advice of persons it deemed appropriate concerning the consequences of the provisions of this Agreement and hereby waives any and all rights to claim that it is an unsophisticated investor in oil and gas properties.

6.3 No Warranty - Buyer acknowledges that, except as otherwise set forth in this Agreement and in the Conveyances, Seller has not made any representation, covenant or warranty, express or implied, at common law, by statute or otherwise, relating to the condition of the Assets, including, without limitation, any implied or express warranty of merchantability, of fitness for any particular purpose, or of conforming to models or samples of materials as to any personal property, fixtures or structures conveyed pursuant to this Agreement.

6.4 Formation, Good Standing and Authority - Buyer is a corporation duly formed, validly existing and in good standing under the laws of the state of Delaware and is, or will be prior to Closing, duly qualified and in good standing in the State of Texas. Buyer has all requisite power and authority to enter into this Agreement and the Conveyances and to perform its obligations under this Agreement. This Agreement is, and the Conveyances when executed and delivered by Buyer will be, the valid and binding obligation of Buyer, enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law). There are no bankruptcy, reorganization, or receivership proceedings pending, being contemplated by or, to Buyer's Knowledge, threatened in writing against Buyer.

6.5 Liability for Broker’s Fees - Buyer has not incurred any liability, contingent or otherwise, for broker’s or finder’s fees relating to the transactions contemplated by this Agreement for which Seller shall have any responsibility whatsoever.

6.6 Financial Resources - At Closing, Buyer shall have all funds necessary to pay the Base Purchase Price and any other amounts contemplated by this Agreement. Buyer’s ability

to consummate the transactions contemplated hereby is not contingent on its ability to secure financing or to complete any public or private placement of securities prior to or upon Closing.

6.7 Qualification to Assume Operatorship - Buyer is qualified to do business in and to own and, assume operatorship of oil, gas and mineral leases, including the Leases and Wells, in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated in this Agreement will not cause Buyer to be disqualified as such an owner or operator. To the extent required by the applicable state and federal governmental bodies or agencies, Buyer currently has, and will continue to maintain, lease bonds, area wide bonds, or any other surety bonds as may be required by, and in accordance with, such state or federal regulations governing the post-Closing ownership and operation of such Leases.



## 7. TITLE

7.1 Title Defects - Buyer shall notify Seller in writing of any Title Defect in the Wells or Blocks after discovering the Title Defect but in any event on or before seven (7) Business Days prior to Closing (the period between the Execution Date and such notice date is the "Due Diligence Period"). For the purpose of this Agreement, a "Title Defect" shall mean a material deficiency which individually per property exceeds Thirty-Five Thousand Dollars ($35,000) in one (or more) of the following respects (other than Permitted Encumbrances), provided, however, that the above $35,000 threshold for individual Title Defects shall not be applicable with regard to (i) matters or claims that Buyer may have the right to assert under the special warranty of title in the Conveyances or (ii) a breach of any of Seller's representations and warranties under this Agreement, and Buyer's right to indemnification therefor. For purposes of this Article 7, Seller's title shall be deemed to include the title of the TAR Sellers:

7.1.1 Adverse Claims - Seller’s title as to all or part of a Well or Block or other Asset is subject to (i) an outstanding mortgage which is not released on or before Closing; (ii) a deed of trust which is not released on or before Closing; (iii) a lien or encumbrance which is not released on or before Closing; or (iv) a pending claim or cause of action in which a competing ownership interest in a Well or Block or other Asset is claimed or implied.

7.1.2 Decreased Net Revenue Interest - Seller owns less than the Net Revenue Interest shown for Seller on Exhibit “E” for a particular Well for the productive life of the Well as to all depths from the surface to the lowest productive depth therein or for a particular Block as to all depths from the surface to the base of the Wolfcamp Formation (except as provided otherwise on Exhibit “E”).

7.1.3 Increased Working Interest - Seller owns more than the Working Interest shown for Seller on Exhibit “E,” without a proportionate increase in the corresponding Net Revenue Interest shown for Seller on Exhibit “E,” for a particular Well for the productive life of the Well as to all depths from the surface to the lowest productive depth therein or for a particular Block as to all depths from the surface to the base of the Wolfcamp Formation (except as provided otherwise on Exhibit “E”).

7.1.4 Reversions — Seller’s title to a Well or Block is subject to reduction by the exercise by a third-party of a reversionary, back-in, or other similar right except for any reversionary interest reflected in Exhibit “E” held by the TAR Owners.

7.2 Additional Interests - During the Due Diligence Period, Buyer shall notify Seller in writing if Buyer determines that Seller has a lesser Working Interest (without a corresponding proportionate decrease in Net Revenue Interest) or a greater Net Revenue Interest with respect to all or any part of a Well or Block than that set forth for Seller on Exhibit “E.” During the Due Diligence Period and for two (2) Business Days thereafter, Seller may notify Buyer in writing of any increase in Net Revenue Interest or decrease in Working Interest of a Well or Block (without a corresponding proportionate decrease in Net Revenue Interest) (“Additional Interest”). If Buyer and Seller agree upon the existence of any Additional Interest, such Additional Interest shall only be permitted to offset and reduce the aggregate amount of all Title Defects, if any.

7.3 Notices - Any Title Defect notice by Buyer pursuant to Section 7.1 or Additional Interest notice by Seller pursuant to Section 7.2 shall include appropriate documentation to substantiate the applicable position and the estimated value of the Title Defect or Additional Interest. If any such notice is not timely delivered, the claimant shall thereafter have no right to assert such Title Defect or Additional Interest as the basis for an adjustment to the Base Purchase Price; provided, however, that this waiver shall not apply with regard to any matters or claims that Buyer may have the right to assert under the special warranty of title in the Conveyances, nor shall this waiver apply with regard to a breach of any of Seller’s representations and warranties under this Agreement, and Buyer’s right to indemnification therefor.

7.4 Adjustments to Base Purchase Price - Upon timely delivery of a notice under this ARTICLE 7 pursuant to Section 7.1 or 7.2, either by Buyer or by Seller, Buyer and Seller shall meet and use their reasonable commercial efforts to agree on the validity of any claims for Title Defects or Additional Interests and the amount of any Base Purchase Price adjustment using the following criteria:

(a) Liquidated Charges - If the adjustment is based upon a lien, encumbrance, or other charge upon an Asset which is liquidated in amount or which can be estimated with reasonable certainty, then the adjustment shall be the sum necessary to be paid to the obligee to remove the encumbrance from the affected Asset.

(b) Ownership Variance - If the adjustment is based upon Seller owning a lesser or greater Net Revenue Interest and proportionate Working Interest than that shown on Exhibit “E,” then the adjustment shall be proportionate to the amount allocated to the affected Asset on Exhibit “E.”

(c) Valuation of Title Defects - If the adjustment is for an item other than as set forth in (a) or (b) above, Buyer and Seller shall endeavor to mutually agree on the amount of the Base Purchase Price adjustment. If the parties cannot agree to the existence of a Title Defect or Additional Interests or the applicable adjustment, the matter shall be resolved in accordance with the dispute resolution provisions in Section 20.3. Any such item shall be referred to as an “Open Defect.” Notwithstanding any of the preceding provisions of this ARTICLE 7, all adjustments applicable to Title Defects or Additional Interests (other than with



be made prior to Closing which Closing shall be extended until resolution of any disputes relating to the Title Defects or Additional Interests (subject to Section 19.1(c)); provided, however, that if adjustments for alleged Title Defects, Environmental Defects, Casualty Defects, Open Defects and contested Environmental Defects do not, in the aggregate, exceed 10% of the Base Purchase Price, then Closing shall occur as to the other Assets that are not subject to the dispute (with the portion of the Assets subject to the dispute being excluded, and the Base Purchase Price reduced for the entire Allocated Values thereof) and Closing shall subsequently occur with respect to the Assets made the subject of the dispute within thirty (30) days following the final resolution of the dispute, and such Closing shall not waive or release any claims of Buyer that are the subject of the dispute.

(d) If a Title Defect is not in effect, or does not adversely affect a Well or Block, throughout the entire life of such Well or Interest in such Block, such fact shall be taken into account in determining the value of the Title Defect. The value of each Title Defect shall also be determined without duplication of any costs or losses included in determining the value of such Title Defect or the value of any other Title Defect. In no event shall the value of a Title Defect exceed the Allocated Value of the applicable Well or Block affected thereby. In addition to the criteria expressly described in this Section 7.4, the parties shall consider any other factors as are reasonably necessary to make a proper evaluation.

For all Title Defects, subject to the provisions of Section 7.5, Seller shall elect to either (i) sell to Buyer the entire Asset(s) affected by the Title Defect but reduce the Base Purchase Price by the portion of the Allocated Value set forth for Seller on Exhibit "E" attributable to such affected Assets or (ii) exclude from Closing the Assets affected by such Title Defect and reduce the Base Purchase Price for the entire Allocated Value of those Assets so excluded. If Seller cures any Title Defect within the 120 calendar days following Closing then the Parties shall have a secondary Closing in which (i) Buyer shall pay to Seller the Base Purchase Price reduction associated with each such cured Title Defect and/or (ii) Buyer shall pay to Seller the entire Allocated Value of the excluded Assets for which all Title Defects have been cured (or a reduced portion thereof, as appropriate, due to any remaining Title Defect(s) associated with the applicable Asset for which other Title Defect(s) have been cured) and receive from Seller a Conveyance of the applicable Assets for which Title Defect(s) have been cured; provided, however, that the amount to be paid at such secondary Closing shall be subject to adjustment in the manner described in Section 3.3, and any disputes regarding the cure of a Title Defect or the applicable adjustment thereof shall be resolved in accordance with the dispute resolution provisions in Section 20.3. For purposes of clarity, any Additional Interests shall only be permitted to offset and reduce the aggregate amount of all Title Defects and Environmental Defects, if any.

7.5 Deductible for Title and Environmental Defects - Notwithstanding the provisions set forth above, a Title Defect or Environmental Defect shall not result in an adjustment to the Base Purchase Price unless the aggregate net value of the sum of (a) all Title Defects with respect to the Assets and (b) all Environmental Defects agreed to by the parties is greater than one and one-half percent (1.5%) of the Base Purchase Price (the “Deductible

Amount"); provided, however, that this Deductible Amount shall NOT be applicable with regard to (i) matters or claims that Buyer may have the right to assert under the special warranty of title in the Conveyances or (ii) a breach of any of Seller's representations and warranties under this Agreement, and Buyer's right to indemnification therefor. In such event, the Base Purchase Price on the Closing shall be adjusted by the aggregate net value of the sum of (a) all Title Defects and (b) all Environmental Defects which collectively exceed the Deductible Amount.

## ARTICLE 8

## 8. ENVIRONMENTAL AND ENVIRONMENTAL INDEMNITY

8.1 Acceptance of Environmental Condition - Buyer may give Seller notice (an “Environmental Notice”) of any fact or circumstance that indicates a violation of a currently existing Environmental Law associated with an Asset or existence of some issue which would otherwise require remedial or corrective action under any Environmental Law (“Environmental Defect”). For the purpose of this Agreement, an Environmental Defect shall mean a material deficiency which individually exceeds Thirty-Five Thousand Dollars ($35,000) and complies with all of the following conditions precedent but shall exclude the mere fact that a well needs to be plugged or that a website or operating location needs to be reclaimed upon cessation of operations thereon or expiration of the applicable leases, easements, or agreements therefor:

(a) The Environmental Notice must be received by Seller as soon as reasonably practical after discovery of the Environmental Defect by Buyer, but in any event on or before seven (7) Business Days prior to the Closing Date;

(b) The Environmental Notice must be based on credible and probative evidence substantiated in good faith by Buyer’s environmental experts (which may include internal employees or personnel of Buyer, its affiliates or third parties) that shows it is more likely than not that there exists an Environmental Defect;

(c) The evidence referred to in Section 8.1(b) must be fully described, substantiated in good faith by Buyer’s environmental experts, and in the case of documentary evidence, enclosed;

(d) The Environmental Notice must reasonably describe the remediation and/or restoration (“Cleanup”) required to remedy the Environmental Defect, or the potential damages claimed or likely to be claimed by a third party, each as recommended or estimated in good faith by Buyer’s environmental experts; and

(e) To the extent practicable, the Environmental Notice must state Buyer’s good faith estimate of the amount of potential Loss to be incurred by Buyer as a result of the Environmental Defect. For purposes of this Agreement, the term “Loss” shall include any estimated Cleanup, costs, losses, expenses, liabilities (including civil and administrative fines and penalties), damages, demands, suits, sanctions, reasonable fees and expenses of attorneys, technical experts and expert witnesses.

If Buyer does not provide Seller with an Environmental Notice within the period set forth above, then at Closing, Buyer shall be deemed to have accepted such Asset and to have waived Buyer’s right to assert an Environmental Defect with respect to the Assets, except with regard to a breach



of any of Seller’s representations and warranties under this Agreement, and Buyer’s right to indemnification therefor.

8.2 Remedy for Environmental Defects - If Buyer gives a valid Environmental Notice in accordance with Section 8.1, Seller may provide for one of the remedies in Section 8.2(a) with respect to the Environmental Defect that is subject to such Environmental Notice, but each such remedy, and the aggregate of all remedies, shall be limited in accordance with Section 7.5.

(a) Remedy. If Buyer delivers a valid Environmental Notice to Seller, Seller, at its election, shall have the option of (i) remediating the Environmental Defect and resolving all Losses arising from such Environmental Defect to the reasonable satisfaction of Buyer and, if applicable, the appropriate state and federal agencies having jurisdiction, (ii) contesting the existence of an Environmental Defect or Buyer's estimate of the amount of all Losses associated with the Environmental Defect pursuant to Section 8.2(c), (iii) paying Buyer's good faith estimate of the amount of all Losses associated with the Environmental Defect in the form of a reduction to the Base Purchase Price (an "Environmental Adjustment"), or (iv) excluding the Asset pursuant to Section 8.2(b). If Seller elects to remediate the Environmental Defect but fails to remediate the Environmental Defect and resolve all Losses arising from such Environmental Defect to the reasonable satisfaction of Buyer and, if applicable, the appropriate state and federal agencies having jurisdiction within one hundred twenty (120) days following Closing then Seller shall pay Buyer's good faith estimate of the amount of all Losses associated with said Environmental Defect. If there is disagreement as to such amount, the dispute shall be resolved in accordance with the dispute resolution provisions set forth in Section 20.3.

(b) Exclusion of Affected Asset. If an Environmental Defect exceeds the Allocated Value of the Asset which is the subject of a valid Environmental Notice, then at Seller’s option, an exclusion adjustment may be made in an amount equal to the Allocated Value of such Asset. In such event Seller shall retain the Asset and the Base Purchase Price shall be reduced by the Allocated Value of such Asset.

(c) Contested Environmental Defects. If Seller contests the existence of any Environmental Defect or Buyer’s estimate of the Loss associated with such Environmental Defect, Seller shall notify Buyer within five (5) Business Days after Seller’s receipt of the Environmental Notice. The notice shall state the basis for Seller’s contest of the Environmental Defect or the estimate of the Cleanup cost. Within two (2) Business Days after Buyer’s receipt of the notice, representatives of Seller and Buyer, knowledgeable in environmental matters, shall meet, and, prior to Closing, either (i) agree to reject the Environmental Defect, in which case Buyer shall waive the Environmental Defect, or (ii) agree on the validity of the Environmental Defect and the estimated Loss, in which case Seller shall have the options described in Section 8.2(a) (except the right to contest) and Section 8.2(b) (Exclusion of Affected Asset). If Seller and Buyer cannot agree on either option (i) or (ii) in the preceding sentence, the Environmental Defect or the estimated Loss subject to the Environmental Notice shall be resolved in accordance with the dispute resolution provisions set forth in Section 20.3. Notwithstanding any of the preceding provisions of this Section 8.2(c), all Environmental Adjustments shall be made prior to Closing, which

Closing shall be extended until resolution of any disputes relating to the Environmental Defects (subject to Section 19.1(c)); provided, however, that if adjustments for alleged Title Defects, Environmental Defects, Casualty Defects, Open Defects and contested Environmental Defects do not, in the aggregate, exceed 10% of the Base Purchase Price, then Closing shall occur as to the other Assets that are not subject to the dispute (with the portion of the Assets subject to the dispute being excluded, and the Base Purchase Price reduced for the entire Allocated Values thereof) and Closing shall subsequently occur with respect to the Assets made the subject of the dispute within thirty (30) days following the final resolution of the dispute. IT IS SPECIFICALLY UNDERSTOOD AND AGREED THAT ONCE AN ENVIRONMENTAL DEFECT HAS BEEN REMEDIATED AND ALL LOSSES RELATED TO SUCH ENVIRONMENTAL DEFECT HAVE BEEN RESOLVED TO BUYER'S REASONABLE SATISFACTION, EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT, BUYER SHALL ASSUME ANY AND ALL FUTURE ENVIRONMENTAL OBLIGATIONS ASSOCIATED WITH SUCH ENVIRONMENTAL DEFECT AND THE ASSOCIATED PROPERTY.

(d) Implementing Cleanup. If Seller elects to Cleanup an Environmental Defect pursuant to Section 8.2(a), Seller shall select the means and methods of effecting the Cleanup in accordance with applicable Environmental Law, applicable industry standards, and any applicable agreement, provided, however, that Seller shall not be required to plug and abandon any currently unplugged wells if the cost thereof would be customary and normal site remediation costs assumed by Buyer in the transfer of the Assets hereunder, including without limitation, plugging and abandonment of Wells. Seller's responsibility for remediation under this Section 8.2 shall be limited to a standard appropriate for the use of an Asset for oil and gas activities and in accordance with all applicable laws.

8.3 Acceptance of Environmental Condition - SUBJECT TO THE OTHER TERMS AND PROVISIONS SET FORTH IN THIS AGREEMENT, INCLUDING THE REPRESENTATION SET FORTH IN SECTION 5.4 FOR THE TERM THEREOF, UPON CLOSING, BUYER AGREES TO ACCEPT THE ENVIRONMENTAL CONDITION OF THE ASSETS, INCLUDING, BUT NOT LIMITED TO, COSTS TO CLEAN UP OR REMEDIATE; AND SUBJECT TO THE OTHER TERMS AND PROVISIONS SET FORTH IN THIS AGREEMENT, BUYER HEREBY AGREES TO RELEASE SELLER FROM ANY AND ALL LIABILITY AND RESPONSIBILITY THEREFORE AND AGREES TO INDEMNIFY, DEFEND, AND HOLD SELLER HARMLESS FROM ANY AND ALL CLAIMS, CAUSES OF ACTION, FINES, EXPENSES, COSTS, LOSSES, AND LIABILITIES WHATSOEVER (INCLUDING, WITHOUT LIMITATION, REASONABLE ATTORNEYS' FEES AND COSTS) IN CONNECTION WITH THE ENVIRONMENTAL CONDITION OR BUYER'S FAILURE TO PROPERLY REMEDIATE THE CONDITION. BUYER ACKNOWLEDGES AND AFFIRMS THAT THE ASSETS HAVE BEEN UTILIZED FOR THE PURPOSE OF EXPLORATION, PRODUCTION AND DEVELOPMENT OF OIL AND GAS, AND THAT SUBJECT TO THE OTHER



TERMS OF THIS AGREEMENT, AT CLOSING, THE ASSETS WILL BE ACQUIRED IN THEIR “AS IS, WHERE IS” ENVIRONMENTAL CONDITION. BUYER HAS CONDUCTED AN INDEPENDENT INVESTIGATION OF THE PHYSICAL AND ENVIRONMENTAL CONDITION OF THE ASSETS, TO THE EXTENT BUYER DEEMS NECESSARY OR APPROPRIATE.

8.4 NORM - Buyer acknowledges that the Assets have been used for exploration, development and production of oil, gas and water and that there may be petroleum, produced water, wastes or other materials located on, under or associated with the Interests. Equipment and sites included in the Assets may contain NORM. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms; the wells, materials and equipment located on or included in the Assets may contain NORM and other wastes or hazardous substances/materials; and NORM containing material and other wastes or hazardous substances/materials may have been buried, come in contact with the soil or otherwise been disposed of on or around the Assets. Special procedures may be required for the remediation, removal, transportation or disposal of wastes, asbestos, hazardous substances/materials, including hydrogen sulfide gas and NORM from the Assets. Except with regard to a breach of any of Seller’s representations and warranties under this Agreement, and Buyer’s right to indemnification therefor, from and after the Closing, Buyer shall assume responsibility for the control, storage, handling, transporting and disposing of or discharge all materials, substances and wastes from the Assets (including produced water, hydrogen sulfide gas, drilling fluids, NORM and other wastes), whether present before or after the Effective Time, in a safe and prudent manner and in accordance with all applicable Environmental Laws (as defined below).

8.5 Environmental Indemnities - EXCEPT AS OTHERWISE SET FORTH IN THIS AGREEMENT OR IN THE CONVEYANCES, THIS SALE IS MADE ON AN “AS IS, WHERE IS” BASIS AND BUYER RELEASES SELLER FROM ANY LIABILITY WITH RESPECT TO THE ENVIRONMENTAL CONDITION OF THE ASSETS, WHETHER OR NOT CAUSED BY OR ATTRIBUTABLE TO SELLER’S NEGLIGENCE. FROM AND AFTER CLOSING, SUBJECT TO THE OTHER TERMS AND PROVISIONS SET FORTH IN THIS AGREEMENT, BUYER SHALL INDEMNIFY, DEFEND, RELEASE AND HOLD SELLER HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, IN FAVOR OF ANY THIRD PARTY OR ENTITY FOR INJURY, ILLNESS OR DEATH OF ANY PERSON(S) OR FOR DAMAGE, LOSS, POLLUTION OR CONTAMINATION OF ANY REAL OR PERSONAL PROPERTY, GROUNDWATER OR THE ENVIRONMENT ATTRIBUTABLE TO THE ENVIRONMENTAL CONDITION OF THE ASSETS, INCLUDING, WITHOUT LIMITATION, CLAIMS ARISING UNDER ENVIRONMENTAL LAWS OR, FOR ANY OTHER CLAIMS ARISING DIRECTLY OR INDIRECTLY FROM, OR INCIDENT TO, THE USE, OCCUPATION, OWNERSHIP, OPERATION, CONDITION (WHETHER LATENT OR PATENT), MAINTENANCE, OR ABANDONMENT OF ANY OF THE ASSETS AND WHETHER ARISING FROM OR CONTRIBUTED TO BY THE ACTIVE, PASSIVE, JOINT, SOLE, OR CONCURRENT NEGLIGENCE, OR STRICT LIABILITY OF SELLER, OR SELLER’S AGENTS OR EMPLOYEES OF SELLER’S CONTRACTORS OR SUBCONTRACTORS, INCLUDING ANY STRICT LIABILITY UNDER ENVIRONMENTAL LAWS, REGARDLESS OF WHETHER ANY SUCH CLAIMS RESULT FROM ANY CONDITIONS, EVENTS, ACTIONS, OR INACTIONS ARISING, OCCURRING, OR ACCRUING PRIOR TO, ON, OR AFTER THE EFFECTIVE TIME; EXCLUDING, HOWEVER, ANY CLAIMS ARISING FROM OR ATTRIBUTABLE TO THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER, ITS AFFILIATES OR ANY OF ITS OR THEIR RESPECTIVE EMPLOYEES, AND ALSO EXCLUDING ANY CLAIMS ATTRIBUTABLE TO SELLER’S OFF-SITE DISPOSAL OF WASTES AND OTHER MATERIALS, AND ALSO EXCLUDING ANY FINES AND PENALTIES

RELATING TO ENVIRONMENTAL LAWS RESULTING FROM THE ACTIONS OF SELLER, ITS AFFILIATES OR ANY OF ITS OR THEIR RESPECTIVE EMPLOYEES. Buyer and Seller shall treat all information regarding any environmental conditions as confidential and shall not make any contact with any Governmental Authority or third party regarding same without written consent from the other Party unless so required by applicable law.

## ARTICLE 9

## 9. THIRD-PARTY PREFERENTIAL RIGHTS TO PURCHASE, CONSENTS, AND TAG ALONG RIGHTS

9.1 Third Party Notices. In accordance with the documents creating such rights and/or requirements, Seller shall, within five (5) Business Days of the execution of this Agreement, (i) request any consent or approval of any third party or Governmental Authority necessary for the conveyance of the applicable Asset to Buyer (“Consents”) and (ii) send out notices for all options, rights of first refusal, or similar preferential purchase rights burdening any of the Assets (each a “Preferential Purchase Right”). Seller shall use all commercially reasonable efforts, but without obligation to incur any cost or expense, to obtain such Consents and waivers of, or to comply with, any such Preferential Purchase Right prior to Closing.

9.2 Third-Party Exercise - If a third-party exercises a Preferential Purchase Right of the Assets or if Seller fails to obtain a Required Consent by Closing, the affected Asset shall be removed from this Agreement and the Base Purchase Price shall be adjusted by the Allocated Value of the affected Asset. If, as of Closing, the time for exercising a Preferential Purchase Right has not expired and such Preferential Purchase Right has not been exercised or waived, then the Assets subject to such Preferential Purchase Right shall be included in the Assets to be assigned to Buyer at Closing, and Buyer shall be entitled to the proceeds associated with the exercise of such Preferential Purchase Right.

9.3 Third-Party Failure to Purchase - If (i) a third-party exercises a Preferential Purchase Right for an Asset excluded at Closing, but fails to close the purchase for any reason within sixty (60) days of Closing or (ii) a Required Consent that was not obtained prior to Closing is obtained by Seller within 120 days following the Closing Date, then (1) Buyer shall purchase from Seller the Asset that was so excluded at Closing and pay to Seller the amount by which the Purchase Price was reduced at Closing with respect to the Asset so excluded and (2) Seller shall assign to Buyer the Asset so excluded at Closing pursuant to an instrument in substantially the same form as the Conveyance,



with such assignment effective as of the Effective Time hereunder.

9.4 Tag Along Rights - That certain Participation Agreement: Screaming Eagle Prospect — Pecos County, Texas dated effective January 1, 2012, between ExL Energy II LP and TRO-X, L.P., et al., for the exploration and development of lands located in the Screaming Eagle Prospect, as amended by the Waiver and Disclaimer dated effective September 30, 2013 and by Agreements dated April 1, 2015, August 1, 2015, November 1, 2015, December 1, 2015, February 24, 2016, and February 24, 2016 (collectively, the “Screaming Eagle Agreement”), contains a provision giving certain parties thereto (“TAR Owners”) the ability to join in the sale reflected by this Agreement (“Tag Along Rights”). The Tag Along Rights apply with respect to the reversionary working interests (“Reversionary Interests”) owned by the TAR Owners on a reverted (after Project

Payout) basis even though such interests have not yet reverted. Buyer agrees to purchase the Reversionary Interests owned by the TAR Owners but only on a fully reverted (after Project Payout) basis. Therefore, with respect to the Tag Along Rights, the Parties agree that:

(a) Within three (3) Business Days after the Execution Date Seller shall provide to the TAR Owners a notice and election in substantially in the form attached hereto as Exhibit “G” (including its enclosed Sales Terms and a redacted copy of this Agreement) (an “Election Letter”) for each TAR Owner to sell to Seller on the same terms as contained in this Agreement including, in particular, this Section 9.4.

(b) The Election Letter shall bind each owner of a Tag Along Right who elects to sell by timely signing and delivering the Election Letter (“TAR Seller”) to sell all of its share of the Reversionary Interest (on a reverted, after Project Payout basis) to Buyer (nominally, see (d) below) on the same terms as this Agreement except that:

“Seller” will be deemed to be only the applicable TAR Seller for all purposes except as set forth in this Section 9.4 (in which “Seller” refers to only Samson Exploration, LLC and is distinguished from the applicable “TAR Seller”);

ii. “Assets” will be limited to the share of the Reversionary Interest owned by the TAR Seller, including, but not limited to, all of the TAR Seller’s right, title and interest in and to the Screaming Eagle Agreement;

iii. “Base Purchase Price” will be the aggregated Allocated Values shown for the TAR Owners on Exhibit “E”, proportionately reduced to the percentage of the Reversionary Interest owned by the TAR Seller;

iv. Due to an assertion by Oxy USA, Inc. (“Oxy”) that the Tag Along Rights are subject to a preferential right to purchase in favor of Oxy (and consequently Seller), the TAR Seller’s transaction will be treated as being subject to a preferential right to purchase consistent with Section 6 of the Screaming Eagle Agreement (“TAR Pref Right”). The Closing process shall be altered as necessary as described below in order to effectuate TAR Pref Right elections. No reference to the TAR Pref Right in this Agreement, any TAR Pref Right notice or election, or any other document shall in any way serve as any acknowledgement of the existence, validity, or applicability of any preferential right to purchase under the Screaming Eagle Agreement;

v. The Deposit shall be entirely for the account of Seller, and not the TAR Sellers. The TAR Seller’s proportionate share of the outstanding Project Payout balance under the Screaming Eagle Agreement, as of the Effective Date, shall be paid to Seller rather than the applicable TAR Seller. Seller shall be responsible for paying Oxy its portion of such amount;

vi. With respect to the Reversionary Interest, all of Seller’s representations in this Agreement shall be deemed to be made by the applicable TAR Seller rather than by Seller, and all responsibility therefor under Article 16 shall be borne solely by the applicable TAR Seller(s);

vii. Any Title Defect that doesn’t affect the interest of Seller and all TAR Sellers shall be solely for the account of the Seller and/or applicable TAR Sellers whose interests in the Assets are affected thereby. In addition, all dollar and percentage amounts set forth in Section 7.1, 7.5, 8.1, and 16.5 shall apply separately to (i) TAR Sellers as a group and (ii) Seller;

viii. The TAR Seller’s entity type, state of formation, and notice address shall be as set forth in the Election Letter, and persons with “Seller’s Knowledge” shall be the person signing the Election Letter, and any other changes as are necessary shall be deemed to be made, mutatis mutandis, to reflect the different parties, interests, price, etc. subject to such transaction.

ix. Notwithstanding anything stated in this Agreement to the contrary, Buyer shall have no obligation to purchase any interests or Assets (as defined in subpart (b)(ii) above) of the TAR Sellers if Buyer does not purchase the Assets of Seller under this Agreement (and the occurrence of Closing between Buyer and Seller (Samson Exploration, LLC) under this Agreement shall be a condition precedent to any obligation of Buyer to purchase the interests of TAR Sellers, whether directly as part of the TAG Along Rights, or indirectly through Seller, as part of the interests Seller acquires in connection with the TAR Pref Right.

(c) Due to the need to send TAR Pref Right notices and the 10 Business Day election period applicable to the TAR Pref Right, Buyer agrees to include in this Agreement only those TAR Owners who execute and deliver to Seller an executed Election Letter on or before January 31, 2017 and thereby become a TAR Seller.

(d) The Parties acknowledge that the TAR Pref Right is owned 75% by Seller and 25% by Oxy, and that the TAR Pref Right notice shall be



issued by the TAR Sellers accordingly within Three (3) Business Days after the earlier of (i) the date set forth in paragraph (c) above or (ii) the date on which all TAR Owners have become a TAR Seller. Seller shall timely exercise its TAR Pref Right and thereby ensure its ability to deliver the before Project Payout interests reflected for Seller on Exhibit “E” with no after Project Payout reduction in Seller’s interest related to the Reversionary Interests owned by the TAR Sellers. Upon Seller’s timely execution of its TAR Pref Right all of Buyer’s obligations with respect to the TAR Owners shall cease. Seller does not know if Oxy will exercise its TAR Pref Right.

(e) If Oxy does exercise its TAR Pref Right, then:

i. TAR Sellers shall convey to Seller 75% of the Reversionary Interests owned by the TAR Sellers on a reverted (after Project Payout) basis at least 3 Business Days prior to Closing;

ii. Oxy and the TAR Sellers will complete their TAR Pref Right transaction (including conveyances, payment, and Project Payout payment) completely separate from any involvement of Seller and Buyer;

iii. Seller will convey to Buyer at Closing all of Seller’s interests reflected for Seller on Exhibit “E” plus Seller’s 75% of the Reversionary Interests of the TAR Sellers on a reverted (after Project Payout) basis (to the extent received therefrom) and thereby ensure its ability to deliver Seller’s before Project Payout interests reflected for Seller on Exhibit “E” with no after Project Payout reduction in Seller’s interest related to the Reversionary Interests owned by the TAR Sellers; and

iv. Buyer will deliver to Seller at Closing, as adjusted pursuant to Article 3: (A) the entire Allocated Value attributed to Seller on Exhibit “E” plus (B) the Allocated Value attributed to the portion of the TAR Owners’ interests burdening Seller on Exhibit “E” proportionately reduced to the percentage of the Reversionary Interests owned by the TAR Sellers’ interests burdening Seller (to the extent Seller has received conveyances therefrom). Buyer acknowledges that all of the Project Payout balance to be paid by the TAR Sellers is for the account of Seller.

(f) If Oxy does not exercise its TAR Pref Right, then:

i. TAR Sellers shall convey to Seller 100% of the Reversionary Interests owned by the TAR Sellers on a reverted (after Project Payout) basis at least 3 Business Days prior to Closing;

ii. Seller shall endeavor to obtain, prior to Closing, from Oxy an assignment from Oxy to Seller of the working interests owned by Oxy and burdened by the Reversionary Interests owned by the TAR Sellers (in order to properly place record title to such reverted working interests into Buyer due to the fact that the Reversionary Interests of the TAR Sellers shall revert to a present working interest as part of this transaction and payment of the TAR Seller’s portion of the Project Payout with a portion of the sales proceeds as reflected below);

iii. Seller shall convey to Buyer at Closing all of Seller’s interests reflected for Seller on Exhibit “E” plus Seller’s 75% of the Reversionary Interests of the TAR Sellers (to the extent Seller has received conveyances therefrom) plus Oxy’s 25% of the Reversionary Interests of the TAR Sellers on a reverted (after Project Payout) basis (to the extent Seller has received conveyances therefrom) and thereby ensure its ability to deliver the before Project Payout interests reflected for Seller on Exhibit “E” with no after Project Payout reduction in Seller’s interest related to the Reversionary Interests owned by the TAR Sellers plus the additional Oxy interest; and

iv. Buyer shall deliver to Seller at Closing, as adjusted pursuant to Article 3: (A) the entire Allocated Value attributed to Seller on Exhibit “E”, plus (B) the Allocated Value attributed to the portion of the TAR Owners’ interests burdening Seller on Exhibit “E” proportionately reduced to percentage of the Reversionary Interests owned by the TAR Sellers’ interests burdening Seller (to the extent Seller has received conveyances therefrom), plus (C) the Allocated Value attributed to the portion of the TAR Owners’ interests burdening Oxy on Exhibit “E” proportionately reduced to percentage of the Reversionary Interests owned by the TAR Sellers’ interests burdening Oxy

(to the extent Seller has received conveyances therefrom). Buyer acknowledges that all of the Project Payout balance to be paid by the TAR Sellers is for the account of Seller and Oxy, and that Seller will be responsible for paying Oxy its portion of any such funds actually received by Seller.

(g) Buyer and Seller agree that Closing of this Agreement shall proceed notwithstanding any delay caused by or dispute regarding the Tag Along Rights, any TAR Owner’s execution, or non-execution, of an Election Letter, the TAR Pref Right, or any matters related thereto, and that a Title Defect shall not exist by virtue of any such delay, dispute, or decision to execute, or to not execute, an Election Letter and/or to exercise (or not exercise) a TAR Pref Right. In the event Seller has not received the conveyances of the Reversionary Interests from the TAR Sellers and/or the working interests burdened thereby from Oxy and/or any other Closing documents from the TAR Sellers, then Closing shall proceed without those Reversionary Interests and/or Oxy’s burdened working interests, and the payment to the TAR Seller hereunder shall be reduced accordingly based on the procedures set forth in Section 9.4(e) or (f) above, as applicable, with the Reversionary Interests and/or Oxy’s burdened working interests not being conveyed—to the extent not being conveyed—being treated at Closing as being owned by TAR Owners who are not TAR Sellers and using the Allocated Value split among Seller and the TAR Owners as set forth on Exhibit “E”. In the event any such delay or dispute should be resolved, or conveyance should be received, within the 120 days after Closing then the Parties agree to cooperate to conduct a subsequent Closing for such Reversionary Interests and/or Oxy’s burdened working interests as is just and equitable and with procedures, conditions, and price adjustments as are reasonable



considering the circumstances.

(h) Notwithstanding anything stated in this Agreement to the contrary, to the extent there is any dispute or challenge made or asserted by any TAR Owners or Oxy relative to their respective Tag Along Rights, preferential purchase rights, or other rights or claims associated with the transactions contemplated in this Section 9.4 or the notices, elections, or actions to be taken or contemplated above, Seller shall INDEMNIFY, DEFEND AND HOLD HARMLESS Buyer with regard to any Losses, claims or demands relating to any such disputes or challenges, REGARDLESS OF THE NEGLIGENCE, STRICT LIABILITY OR OTHER LEGAL FAULT OR RESPONSIBILITY OF SELLER, BUYER OR ANY OTHER PERSON.

## ARTICLE 10

## 10. CONDITIONS TO CLOSING; SETTLEMENT STATEMENT; CLOSING

10.1 Seller’s Conditions to Closing - The obligations of Seller at the Closing are subject to the satisfaction at or prior to the Closing, or waiver in writing by Seller, of the following conditions:

(a) All representations and warranties of Buyer contained in this Agreement, to the extent qualified with respect to materiality, shall be true and correct in all respects, and to the extent not so qualified, shall be true and correct in all material respects, in each case as if such representations and warranties were made at and as of the Closing; and Buyer shall have performed and satisfied in

all material respects all covenants and agreements required to be performed and satisfied by it under this Agreement at or prior to the Closing.

(b) No suit, action or other proceeding brought by a third party shall be pending, nor shall any order have been entered by any court or Governmental Authorities having jurisdiction over the Parties or the subject matter of this Agreement which remains in effect at the time of Closing, in either case, that restrains or prohibits or seeks to restrain or prohibit, or seeks damages in connection with, the purchase and sale contemplated by this Agreement.

(c) Buyer shall have provided Seller evidence satisfactory to Seller that Buyer, as of Closing (i) is qualified to do business and to own and operate the Assets in all jurisdictions in which the Assets are located and (ii) has posted all bonds required by any federal, state, or local governmental, quasi-governmental or regulatory branch, agency, bureau, department, service, commission or other body to own and operate the Assets, including but not limited to replacement of the bonds listed on Schedule 5.18 which have accepted by the obligees thereunder.

(d) The aggregate adjustments to the Base Purchase Price attributable to Title Defects (excluding all Title Defects related to any Reversionary Interests), Environmental Defects and Casualty Defects shall not have exceeded ten percent (10%) of the Base Purchase Price.

(e) Buyer shall have performed its obligations set forth in Section 10.5.

10.2 Buyer’s Conditions to Closing - The obligations of Buyer at the Closing are subject to the satisfaction at or prior to the Closing, or waiver in writing by Buyer, of the following conditions:

(a) All representations and warranties of Seller contained in this Agreement, to the extent qualified with respect to materiality, shall be true and correct in all respects, and to the extent not so qualified, shall be true and correct in all material respects, in each case as if such representations and warranties were made at and as of the Closing, and Seller shall have performed and satisfied in all material respects all covenants and agreements required to be performed and satisfied by it under this Agreement at or prior to the Closing.

(b) No suit, action or other proceeding brought by a third party shall be pending, nor shall any order have been entered by any court or Governmental Authorities having jurisdiction over the Parties or the subject matter of this Agreement which remains in effect at the time of Closing, in either case, that restrains or prohibits or seeks to restrain or prohibit, or seeks damages in connection with, the purchase and sale contemplated by this Agreement.

(c) All Consents shall have been received or waived in writing; and Seller shall have provided evidence satisfactory to Buyer of the same. This condition shall be deemed to have been met if all Required Consents that have not been obtained at or prior to Closing apply to Assets whose Allocated Values as set forth for Seller on Exhibit “E” constitute, in the aggregate, less than five percent (5%) of the Base Purchase Price. “Required Consent” means any consent by a third party that, if not obtained prior to the assignment of such Asset, (a) makes the

assignment with respect to such Asset void or voidable, (b) terminates Seller’s interest in any Asset, or (c) triggers the required payment of a predetermined amount as purported liquidated damages; provided, however, that, for purposes hereof, any Consent requirement providing that it cannot be unreasonably withheld shall be deemed to have been obtained unless the holder of the right to grant such Consent has expressly objected to the conveyance and stated grounds that could reasonably be determined to be reasonable grounds for withholding such Consent.

(d) The aggregate adjustments to the Base Purchase Price attributable to Title Defects (excluding all Title Defects related to any Reversionary Interests), Environmental Defects and Casualty Defects shall not have exceeded ten percent (10%) of the Base



Purchase Price.

(e) Seller shall have performed its obligations set forth in Section 10.5.

(f) Seller shall have timely elected to exercise its TAR Pref Right as set forth in Section 9.4(d).

10.3 Closing Settlement Statement - At least three (3) Business Days prior to Closing, Seller shall provide Buyer with a closing settlement statement covering all adjustments, without duplication, to the Base Purchase Price to be made at Closing under this Agreement (the "Closing Settlement Statement"). To the extent available, actual numbers shall be used. If not available, Seller shall use reasonable and good faith estimates of the same, which estimates shall be adjusted to take into account actual numbers in connection with the Final Settlement Statement described in Section 11.3 below.

10.4 Closing Date and Place - Subject to the satisfaction of the conditions in this Agreement, the closing of the transactions contemplated by this Agreement shall be held on or before February 28, 2017, at the offices of Seller at 110 West 7 \( ^{th} \)  Street, Suite 2000, Tulsa, Oklahoma 74119 or on such other date or at such other place as the parties mutually agree (the "Closing").

10.5 Closing Activities - The following actions shall take place at Closing:

10.5.1 Certificates - Each Party shall deliver to the other Party a certificate in a form reasonably satisfactory to the other Party dated as of the Closing and executed by a duly authorized officer, partner, attorney-in-fact or owner, as appropriate, of such Party to the effect that (a) the Party has all requisite corporate, partnership or other power and authority to purchase or sell the Assets, as the case may be, on the terms described in this Agreement and to perform its other obligations hereunder, (b) that all corporate, partnership and/or other prerequisites of whatsoever nature have been fulfilled, and (c) certifying that all conditions to Closing as set forth in Sections 10.1 or 10.2, as the case may be, have been met.

10.5.2 Conveyances - Seller and Buyer shall execute, acknowledge and deliver three (3) counterpart copies of each of the Conveyances (substantially in the form set forth as Exhibit “F” attached hereto) to be filed in each respective County where the Assets are located, assigning and conveying the Assets to Buyer, as well as applicable governmental assignment forms.

10.5.3 Payment - Buyer shall deliver to an account designated in writing by Seller by wire transfer of same day funds the Base Purchase Price plus or minus any adjustments thereto contemplated in Section 3.3 above or otherwise in this Agreement. Buyer and Seller shall deliver joint written instructions to the Escrow Agent that Closing has occurred and that the Deposit should be distributed to Seller.

10.5.4 Additional Documents — For Seller-operated Interests, to the extent Buyer has or will be appointed operator, Buyer shall deliver to Seller on or prior to Closing, evidence of compliance with the rules and regulations dealing with both the operation of and the plugging and abandoning of Wells, such as the appropriate bond which has been accepted by the relevant regulatory agency. In addition, for Seller-operated Interests, to the extent Buyer has or will be appointed Operator, Seller shall deliver to Buyer on or prior to Closing designation or change of operator forms in satisfaction of applicable governmental requirements. Notwithstanding the foregoing, Buyer understands that Seller cannot guarantee that it can assign operatorship rights to Buyer. In order to assume operatorship Buyer must comply with the appointment/election provisions of the applicable joint operating agreement; provided, however, that Seller shall use all reasonable commercial efforts to assist Buyer being appointed as operator.

10.5.5 Possession - Seller shall (subject to the terms of any applicable joint operating agreements and to the other provisions hereof) deliver to Buyer exclusive possession of the Assets.

10.5.6 Letters-in-Lieu - Seller shall prepare and Seller and Buyer shall execute and deliver to Buyer the Letters-in-Lieu of Transfer Orders provided for in Section 13.3.

10.5.7 Releases. Seller shall deliver recordable or recorded releases of any deeds of trust, mortgages, financing statements, fixture filings and security agreements burdening any of the Assets.

10.5.8 FIRPTA. Seller shall deliver an executed certificate of non-foreign status that meets the requirements set forth in Treasury Regulation § 1.1445-2(b)(2).

## ARTICLE 11

## 11. POST-CLOSING OBLIGATIONS

Seller and Buyer agree to the following post-Closing obligations:

11.1 Recordation and Filing of Documents - After the Closing, Buyer shall file or record the Assignments in the appropriate county and governmental records. Buyer shall provide a copy of same, including recording date, to Seller, all at the sole cost of Buyer.

11.2 Records - Within ten (10) Business Days after the Closing, Seller will furnish Buyer the original Records, but Seller shall have the right to retain copies thereof. Insofar as Seller reasonably believes the Records may be needed or useful in connection with federal, state or local regulatory or Tax matters or resolution of disputes, litigation, or contract compliance issues, (i) Seller may retain the original Records and deliver to Buyer copies



therefore and (ii) Buyer (for a period of seven (7) years after the Closing) shall further make available to Seller or its affiliates (at the location of such Records in Buyer's organization) access to the Records during normal business hours, upon not less than two (2) Business Days prior written request by Seller, and Seller shall have the right to copy at its own expense and retain such copies of the Records as Seller, in good faith, believes may be useful or needed in connection with the above-described matters. If, however, Buyer elects to destroy any of the Records prior to the expiration of the seven (7) year period, Buyer shall give to Seller written notice of such intent at least thirty (30) days prior to such destruction, and Seller shall have the option, at its expense, of having such Records delivered to it.

11.3 Final Settlement Statement - Seller shall issue a final settlement statement (the "Final Settlement Statement") within one hundred twenty (120) days after Closing. Buyer shall respond with objections and proposed corrections within thirty (30) days of the issuance of the Final Settlement Statement. If Buyer does not respond with objections and the support therefor to the Final Settlement Statement in writing within thirty (30) days of the issuance of the Final Settlement Statement, the Final Settlement Statement shall be deemed approved by Buyer. In the event that Buyer does respond and objects within this time period, the Parties shall meet within fifteen (15) days following receipt of Buyer's objections and attempt to resolve the disputed items. If the Parties are unable to resolve the disputed items by the end of such fifteen-day period, the dispute shall be resolved in accordance with the dispute resolution provisions set forth in Section 20.3. After approval by both Parties (or after final resolution of the same under Section 20.3), the net adjustment due pursuant to the Final Settlement Statement for the Assets conveyed will be summarized and a net check or invoice will be sent to the Buyer or Seller, as the case may be. Buyer or Seller, as the case may be, agrees to promptly pay such invoice within ten (10) days after receipt by Buyer. This process shall be repeated, if necessary, following any subsequent Closing pursuant to Section 7.4. If an exact amount is not known within 120 days after Closing, Seller shall include a reasonable estimate of the adjustment necessary for the Volume Commitment Shortfall Payment, if any. The Party owing the difference between the estimated amount used for the Final Settlement Statement and such final amount shall pay the other Party as promptly as practicable.

11.4 Suspense Accounts - As set forth and itemized on Schedule 5.21 attached hereto, Seller currently maintains suspense accounts pertaining to oil and gas heretofore produced comprising monies not yet escheated but payable to royalty owners, mineral owners and other persons with an interest in production that Seller has been unable to pay (the "Suspense Accounts"). Seller will transfer to Buyer all funds in the Suspense Accounts related to proceeds of production for the three-year period prior to the Effective Time. Seller will be responsible for timely filing of escheat reports for suspended funds aged beyond such three year abandonment period. A downward adjustment to the Base Purchase Price will be made at Closing to reflect the funds in the Suspense Accounts as of the date the Closing Settlement Statement is prepared, and an additional adjustment will be made in the Final Settlement Statement pursuant to Section 11.3 in order to reflect additional amounts thereafter received by Seller and/or credited to the Suspense Accounts. Subject to the other provisions hereof and only to the extent Buyer has received a downward adjustment to the Base Purchase Price for the same, Buyer shall assume full and complete responsibility and liability for proper payment of the funds comprising the Suspense Accounts transferred to Buyer. Buyer agrees to indemnify, defend and hold Seller, its parent, subsidiary and affiliated entities, together with their respective officers, directors, employees, agents and their respective successors and

assigns, harmless from and against any and all liabilities, claims, demands, penalties and expenses (including reasonable attorneys' fees) arising out of or pertaining to the proper payment and administration of the funds in the Suspense Accounts transferred to Buyer.

11.5 Further Assurances - After Closing, Buyer and Seller further agree that each will, from time to time and upon reasonable request, execute, acknowledge, and deliver in proper form, any instrument of conveyance, assignment, transfer, or other instruments reasonably necessary for transferring title in the Assets to Buyer or otherwise to implement the transactions contemplated herein.

11.6 Volume Commitment - Buyer shall exercise its reasonable commercial efforts to negotiate an extension of the deadline to fulfill Seller's volume commitment under that certain Gas Gathering Agreement dated October 1, 2012 between Regency Field Services, LLC and EXL Petroleum, LP to December 31, 2017 or later (or to as late of a date as possible if Regency isn't willing to extend the deadline to at least December 31, 2017) due to Regency's (i) failure to maintain pressures equal to or less than the maximum pressure requirements of such gas gathering agreement and (ii) inability to accept Seller's gas, both of which required Seller to flare gas or make gas deliveries to other pipelines instead of delivering said gas to Regency at its designated receipt points.

## ARTICLE 12

## 12. TAXES

12.1 Property Taxes - Seller shall be allocated and bear all ad valorem Taxes, real property Taxes, and similar obligations (“Real Property Taxes”) attributable to (i) any Tax period ending prior to the Effective Time and (ii) the portion of any Current Tax Period ending immediately prior to the date on which the Effective Time occurs. Buyer shall be allocated and bear all Real Property Taxes attributable to (i) any Tax period beginning on or after the Effective Time and (ii) the portion of any Current Tax Period beginning on the date on which the Effective Time occurs. Each Party shall be responsible for its own Income Taxes. Real Property Taxes pertaining to a Current Tax Period shall be allocated between the portion of such Current Tax Period ending immediately prior to the date on which the Effective Time occurs and the portion of such Current Tax Period beginning on the date on which the Effective Time occurs by prorating each such Real Property Tax based on the number of days in the applicable Current Tax Period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such Current Tax Period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of the preceding sentence, the period for such Real Property Taxes shall begin on the date on which ownership of the applicable Asset gives rise to liability for the particular Real Property Tax and shall end on the day before the next such date. All Real Property Taxes applicable to the Assets with respect to the Current Tax Period shall be apportioned between Seller and Buyer as of the Effective Time based on the immediately preceding Tax period’s assessment, unless the Current Tax Period’s assessment is known, in which case that assessment shall be used for apportionment. Upon the later determination of the actual amount of Real Property Taxes for the Current Tax Period, timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such



12.2 Production Taxes - All Taxes (other than Real Property, income, franchise, or similar Taxes) imposed on or with respect to the production of oil, natural gas, or other hydrocarbons or minerals, or the receipt of proceeds therefrom (including, but not limited to, severance, production and excise Taxes) shall be apportioned between the parties based upon the respective shares of production taken by the parties. Payment or withholding of all such Taxes that have accrued prior to the Effective Time and filing of all statements, returns and documents pertinent thereto shall be the responsibility of Seller. Payment or withholding of all such Taxes that have accrued from and after the Effective Time and the filing of all statements, returns and documents incident thereto shall be the responsibility of Buyer. In the event any such Taxes attributable to the Assets and to periods on or after the Effective Time become due and payable prior to Closing, Seller shall timely pay and satisfy the same, and appropriate adjustments thereof shall be made to the Base Purchase Price under Section 3.3 above.

12.3 Other Taxes - Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than production Taxes described in Section 12.2), shall be allocated to the Tax period or portion thereof in which the transaction giving rise to such Taxes occurred.

12.4 Transfer Taxes - As may be required by relevant Taxing agencies, Seller shall collect and Buyer shall pay at Closing all applicable state and local sales Tax, use Tax, gross receipts Tax, business license Tax, and other Taxes attributable to the consummation of the transactions under this Agreement except Taxes imposed by reason of income to (or capital of) Seller. The Tax collected shall be based upon the Allocated Values as provided in Section 3.4 and shall be added to the Base Purchase Price at Closing. Any state or local Tax specified above, inclusive of any penalty and interest, assessed at a future date against Seller with respect to the transaction covered herein shall be paid by Buyer or, if paid by Seller, Buyer shall promptly reimburse Seller therefor. Any documentary stamp Tax which may be due shall be paid by Buyer. Seller shall make commercially reasonable efforts to cooperate with Buyer to obtain the benefit of any applicable exemption related to Taxes described in this Section 12.4.

12.5 Tax Returns - Buyer shall be responsible for the preparation and timely filing of any Tax Returns and the payment to the applicable Governmental Authority of all Taxes that become due and payable on or after the date of Closing, and Buyer shall indemnify and hold Seller harmless for any failure to file such Tax Returns and to make such payments. Buyer shall prepare any Tax Returns for Taxes for Current Tax Periods ending on or after the date of Closing on a basis consistent with past practice except to the extent otherwise required by applicable Law. Buyer shall provide Seller with a copy of any such Current Tax Period Tax Return for review at least ten days prior to the due date for the filing of such Tax Return (or within a commercially reasonable period after the end of the Current Tax Period, if such Tax Return is required to be filed less than ten days after the close of the Current Tax Period), and Buyer shall incorporate reasonable comments of Seller provided to Buyer in advance of the due date for the filing of such Tax Return.

## ARTICLE 13

## 13. OWNERSHIP OF ASSETS

13.1 Distribution of Production - All oil in storage, including Seller’s tankage and pipeline volumes, or gas beyond the meters at the Effective Time shall be credited to Seller, less

applicable royalties and severance Taxes. For Seller-operated Assets, Seller has gauged the oil in storage and read all gas meter charts as of the Effective Time. For Seller non-operated Assets, the quantity of such oil in storage or gas beyond the meters shall be determined on the same basis as that used for Seller-operated Assets based on operator reports or applicable state regulatory agency production reports or records. As part of the Closing Settlement Statement, the price for such oil in storage shall be at the price that Seller has contracted to sell the oil on the Effective Time, taking into account applicable royalties and severance Taxes. If there is no such price, the price shall be the average of the two highest prices that are posted at the Effective Time (plus any premium) by other purchasing companies, as determined by Seller in the field or locality where the Interests are located for oil of like grade and gravity. Title to the oil in storage for both Seller-operated and Seller non-operated Assets shall pass to Buyer upon Closing, effective as of the Effective Time, and an upward adjustment shall be made to the Base Purchase Price due at Closing, less applicable royalties and severance Taxes.

13.2 Proration of Income and Expenses - Except as otherwise provided in this Agreement, all proceeds (including proceeds held in suspense or escrow), receipts, credits, and income attributable to the Assets for all periods of time prior to the Effective Time shall belong to Seller, and all proceeds, receipts, credits, and income attributable to the Assets for all periods of time from and after the Effective Time shall belong to Buyer. Except as otherwise provided in this Agreement, all costs, expenses, disbursements, and obligations attributable to the Assets for periods of time prior to the Effective Time shall be the obligation of Seller, and Seller shall promptly pay, or if paid by Buyer, promptly reimburses Buyer for and hold Buyer harmless from and against same. Except as otherwise provided in this Agreement, all costs, expenses, disbursements and obligations attributable to the Assets for periods of time from and after the Effective Time shall be the obligation of Buyer, and Buyer shall promptly pay, or if paid by Seller, promptly reimburses Seller for and hold Seller harmless from and against same.

13.3 Notice to Remitters of Proceeds - Buyer shall be responsible for informing all purchasers of production or other remitters to pay Buyer and obtain from the remitter revenues accrued after the Effective Time. The remitter shall be informed by Seller and Buyer via Letters-in-Lieu of Transfer Order or such other reasonable documents which remitter may require.

13.4 Production Imbalances - Set forth on Schedule 13.4 attached hereto and made a part hereof for all purposes is a listing of all gas imbalance volumes measured in Mcfs or MMBtu's and the aggregate net volume of overproduction or underproduction, as applicable, with respect to the Assets as of the Effective Time (the "Assumed Imbalance"). At Closing, the Base Purchase Price shall be adjusted, upward or downward as appropriate, to reflect the value of said aggregate net volume of overproduction or underproduction with respect to the



Assumed Imbalance as said volume may be adjusted prior to Closing in accordance with each Party’s due diligence investigation. The value of said aggregate net volume (less royalties) of overproduction or underproduction, as applicable, shall be the product obtained by multiplying Two Dollars ($2.00) by the volume of such aggregate net overproduction or underproduction measured in Mcfs or MMBtu’s as shown on Schedule 13.4. Buyer shall be solely responsible for any liability and solely entitled to any benefit from production imbalances, whether occurring on, before or after the Effective Time. If the imbalance cannot be determined by Closing or there are further imbalance adjustments attributable to Pre-Effective Time periods subsequent to Closing but prior to the Final Settlement

Statement, then the value adjustment associated with any imbalance will be made in connection with the Final Settlement Statement.

Pipeline and Other Non Well-head Imbalances- To the extent there exists any imbalances attributable to Hydrocarbons produced from the Assets as of the Effective Time, with respect to any gas pipeline, storage or processing facility, at Closing the Base Purchase Price shall be adjusted upward or downward, as appropriate, to reflect the value of said imbalance. The value of said imbalance shall be calculated by summing the product(s) obtained by multiplying the volume of each net over-position or under-position, as the case may be, measured in the same manner as it is measured by the pipeline, storage or processing facility, as applicable, by the value at which the imbalance was either cashed out, made up or sold, or if otherwise undeterminable then using existing fair market value of, or price for, said Hydrocarbons. Buyer shall be solely responsible for any liability and solely entitled to any benefit from such pipeline imbalances relating to the Assets from and after the Effective Time. If the imbalance cannot be determined by Closing or if the pipeline storage or processing facility makes any adjustments attributable to Pre-Effective Time periods subsequent to Closing but prior to the Final Settlement Statement, then the value adjustment associated with any imbalance will be made in connection with the Final Settlement Statement.

## ARTICLE 14

## 14. INTERIM OPERATIONS

## 14.1 Standard of Care.

Subject to the additional restrictions set forth in this Section 14.1, Seller shall operate the Seller-operated Assets in accordance with all applicable laws, using the standard of care as a reasonable and prudent operator and consistent with past practices until Closing, or such later time as any applicable joint operating agreement may require, when such operation shall be turned over to, and become the responsibility of, Buyer. During the period from the Execution Date to Closing, Seller shall (i) permit Buyer to have access for inspection only to those Assets operated by Seller; (ii) except for emergency action taken in the face of risk to life, property or the environment, shall not, without the prior written consent of Buyer (which shall not be unreasonably withheld) approve or authorize any AFE’s or capital expenditures over One Hundred Thousand Dollars ($100,000) net to the interest of Seller which are received by Seller with respect to any Assets, settle any gas imbalances and incur costs for discretionary expenditures for operations in excess of One Hundred Thousand Dollars ($100,000) net to the interest of Seller for which AFE’s are not prepared; (iii) operate, or if Seller is not the operator, use reasonable efforts to ensure that the operator operates the Assets in its ordinary course of business and in accordance with applicable industry standards and the terms and conditions of all applicable Contracts, laws and regulations; (iv) not transfer, sell, hypothecate, encumber, abandon or otherwise dispose of any portion of the Assets (other than the sale of Hydrocarbons in the ordinary course of business or as required in connection with the exercise by third-parties of Preferential Purchase Rights) any of the Assets or agree to undertake any of the foregoing; (v) assist the Buyer (without incurring any third party expenses) in preserving the present relationships related to the Assets with parties having significant business relations therewith, such as suppliers, customers, brokers, agents or otherwise; (vi) not amend, modify or terminate (or enter into any new) Material Contracts; (vii) take any and all actions necessary to ensure that the Assets are free and clear of all liens and

encumbrances as of Closing; (viii) not waive, compromise or settle any material right or claim if such waiver, compromise or settlement would adversely affect the use, ownership or operation of any of the Assets in any material respect, and (ix) cause the Assets to be maintained in accordance with the terms and conditions of the applicable Contracts and applicable laws and regulations and consistent with past practices, and consult with Buyer with respect to same. However, notwithstanding the above restrictions, insofar as none of the same would reduce the interest in the Assets being delivered to Buyer at Closing, increase any liability or obligation that Buyer would be assuming as of the Closing, or materially and adversely affect Buyer’s ability to own, operate and maintain the Assets in substantially the same manner that Seller owned, operated and maintained the Assets, it is agreed that prior to Closing, Seller shall be permitted to take those actions described on Schedule 14.1 or execute any document intended to cure an actual or potential Title Defect.

14.2 Liability of Operator - Notwithstanding Section 14.1, Seller shall not be liable to Buyer for any claims, demands, causes of action, damages, or liabilities arising out of Seller’s operation of the Assets after the Effective Time, insofar as Seller continues to operate and maintain the Assets in accordance with the terms of this Agreement (including, without limitation, Section 14.1 above) and as a reasonable and prudent operator, and insofar as no such Claims, demands, causes of action, damages, or liabilities relating to such interim operation are attributable to the gross negligence or willful misconduct of, or any breach of this ARTICLE 14 by, Seller.

14.3 Removal of Signs - Seller shall have the option to remove Seller’s name and signs from the Seller-operated Assets or to require Buyer to do so after Closing. Buyer hereby grants Seller a right of access after Closing, upon reasonable prior written notice to Buyer, at Seller’s sole cost, expense and liability, to such Assets to remove Seller’s signs and names from the Assets, or to confirm that Buyer has done so after Closing. If Seller’s signs or name remain on the Assets after Closing, Buyer shall promptly, but no later than required by applicable rules and regulations or thirty (30) days thereafter, whichever is earlier, remove any remaining signs and references to Seller and shall erect or install all signs complying with any applicable governmental rules and regulations, including, but not limited to, those showing the Buyer as operator of the Assets.

14.4 Non-Operated Assets - As to non-operated Assets, Seller shall exercise the same standard of care as a reasonable and prudent working



interest owner under the same or similar circumstances until Closing, subject to the other provisions of Section 14.1 above.

14.5 Third-Party Notifications - Buyer shall make all notifications to all Regulatory Authorities, “one call services” and similar groups associated with the operation of the Assets within fifteen (15) days of Closing. A copy of all such notifications shall be provided to Seller pursuant to the notice provisions contained in ARTICLE 18 hereof.

14.6 Accounting Cooperation - In accordance with the rules and regulations of the U.S. Securities and Exchange Commission and pursuant to other reporting obligations of Buyer, including any rules of the New York Stock Exchange, Buyer and its Affiliates may be obligated to provide certain audited financial information related to the Assets. Accordingly, from and after the Execution Date until Closing, and then, should it occur, the three year anniversary of the Closing Date, Seller shall grant Buyer and its Affiliates, and its and their independent accountants and other representatives, access, during normal business hours, to the books and records in the possession or control of Seller related to the Assets as may be reasonably requested by Buyer, and its and their

independent accountants and other representatives, for the purpose of auditing and otherwise verifying revenue and expense and other information related to the Assets to be included in any required financial statements of Buyer and its Affiliates; provided, however, that Seller shall have no liability or obligation for the accuracy or completeness of such information or otherwise with respect to the financial statements of Seller in which such information is reflected.

## ARTICLE 15

## 15. EXCHANGE PROVISION

Seller and Buyer, respectively, shall have the right, prior to Closing, to elect to effect a Tax-deferred exchange under Code Section 1031 (a "Tax Deferred Exchange") for the Assets at any time prior to Closing. If such Party elects to effect a Tax-Deferred Exchange, the other Party agrees to execute escrow instructions, documents, agreements or instruments to effect the exchange; provided, however, that the other Party shall incur no additional costs, expenses, fees or liabilities as a result of or connected with the exchange. Seller and Buyer, as the case may be, may assign any of its rights and delegate performance of any of its duties under this Agreement in whole or in part to a third party in order to effect such an exchange; provided, however, that each such Seller and/or Buyer shall remain responsible to the other Party for the full and prompt performance of its respective delegated duties. The electing Party shall indemnify and hold the other Party and its affiliates harmless from and against all claims, expenses (including reasonable attorneys' fees), loss and liability resulting from its participation in any exchange undertaken pursuant to this ARTICLE 15 pursuant to the request of the electing Party.

## ARTICLE 16

## 16. ASSUMPTION OF LIABILITY AND GENERAL INDEMNIFICATION

## 16.1 Buyer’s Assumption of Obligations

16.1.1 Subject to Closing occurring, and further subject to Seller’s indemnification provisions of Section 16.4, Buyer hereby assumes and agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of the Seller, known or unknown, with respect to the Assets, insofar as the same arise on or after, and are attributable to actions, occurrences and operations conducted from and after, the Effective Time, together with (a) those liabilities and obligations described in Sections 16.1.1(i) and 16.1.1(ii) below and (b) following the expiration of Seller’s indemnity obligations as set forth in Section 16.4, any and all duties and obligations or claims which would fall under Section 16.4(i) through (vi), inclusive, whether arising before, on or after the Effective Time (collectively, the “Assumed Obligations”). The Assumed Obligations include, without limitation, the payment and/or performance of all Taxes, leasehold and equipment rentals and release payments, royalties, excess royalties, in-lieu royalties, overriding royalty interests, production payments, net profit obligations, carried working interests and any other matters with which the Assets may be burdened, insofar as the same are attributable to the periods from and after the Effective Time.

(i) THE ASSUMED OBLIGATIONS SHALL INCLUDE, AND BUYER, FROM AND AFTER THE CLOSING ACCEPTS SOLE

RESPONSIBILITY FOR AND AGREES TO PAY, ALL COSTS AND EXPENSES ASSOCIATED WITH PLUGGING AND ABANDONMENT OF ALL WELLS, DECOMMISSIONING OF ALL FACILITIES, AND CLEARING AND RESTORATION OF ALL SITES, IN EACH CASE INCLUDED IN, OR ASSOCIATED WITH, THE ASSETS, AND BUYER MAY NOT CLAIM THE FACT THAT PLUGGING AND ABANDONMENT, DECOMMISSIONING, SITE CLEARANCE OR RESTORATION OPERATIONS ARE NOT COMPLETE OR THAT ADDITIONAL COSTS AND EXPENSES ARE REQUIRED TO COMPLETE ANY SUCH OPERATIONS AS A BREACH OF SELLER'S REPRESENTATIONS OR WARRANTIES MADE HEREUNDER OR THE BASIS FOR ANY OTHER REDRESS AGAINST SELLER.

(ii) THE ASSUMED OBLIGATIONS SHALL INCLUDE, AND BUYER, FROM AND AFTER THE CLOSING ACCEPTS SOLE RESPONSIBILITY FOR AND AGREES TO PAY, ANY AND ALL COSTS AND EXPENSES ARISING OUT OF ENVIRONMENTAL LAWS (INCLUDING, WITHOUT LIMITATION, ANY COMPLIANCE OR NON-COMPLIANCE THEREWITH, ANY ADVERSE ENVIRONMENTAL CONDITIONS, AND THE



DISPOSAL, RELEASE, DISCHARGE OR EMISSION OF HYDROCARBONS, HAZARDOUS SUBSTANCES, HAZARDOUS WASTES, HAZARDOUS MATERIALS, SOLID WASTES OR POLLUTANTS INTO THE ENVIRONMENT), KNOWN OR UNKNOWN, WITH RESPECT TO THE ASSETS, REGARDLESS OF WHETHER SUCH OBLIGATIONS OR LIABILITIES AROSE PRIOR TO, ON, OR AFTER THE EFFECTIVE TIME. BUYER EXPRESSLY AGREES TO ASSUME THE RISK THAT THE ASSETS MAY CONTAIN WASTE MATERIALS, INCLUDING, WITHOUT LIMITATION, NORM, HAZARDOUS SUBSTANCES, HAZARDOUS WASTES, HAZARDOUS MATERIALS, SOLID WASTES, OR OTHER POLLUTANTS, PROVIDED HOWEVER, THAT THE ASSUMED OBLIGATIONS SHALL NOT INCLUDE (A) ANY COSTS, EXPENSES, OR LIABILITIES ATTRIBUTABLE TO SELLER'S OFF-SITE DISPOSAL OF WASTES, HAZARDOUS OR OTHER MATERIALS, OR (B) ANY FINES AND PENALTIES RELATING TO ENVIRONMENTAL LAWS RESULTING FROM THE ACTIONS OF SELLER, ITS AFFILIATES OR ANY OF ITS OR THEIR RESPECTIVE EMPLOYEES.

16.1.2 Buyer covenants and agrees that it will not attempt to avoid the effect of the release made by it above by later arguing that at the time of the release it did not fully appreciate the extent of any such claims.

16.2 Definitions - For purposes of ARTICLE 16 and all other provisions of this Agreement which contain an indemnification provision, the term "Buyer Group" shall be deemed to include Buyer and its affiliates, all successors, heirs and assigns of Buyer and its affiliates, and the officers, directors, shareholders, members, managers, employees, representatives, co-owners, contractors, subcontractors, or agents of any of the foregoing. For purposes of ARTICLE 16 and all other provisions of this Agreement which contain

an indemnification provision, the term “Seller Group” shall be deemed to include Seller and its affiliates, all successors, heirs and assigns of Seller and its affiliates, and the officers, directors, shareholders, members, managers, employees, representatives, co-owners, contractors, subcontractors, or agents of any of the foregoing.

16.3 Buyer’s General Indemnity - Buyer shall, upon Closing, defend, indemnify, release and hold Seller Group harmless from and against any and all Claims in favor of any person for personal injury, death or damage to property or for any other Claims arising from or relating to (i) Buyer’s breach of any of its representations and warranties in this Agreement, (ii) Buyer’s breach of any of its covenants in and under this Agreement, and (iii) the Assumed Obligations, REGARDLESS OF WHETHER ANY OF SUCH CLAIMS MAY BE ATTRIBUTABLE, IN WHOLE OR IN PART, TO THE STRICT LIABILITY OR NEGLIGENCE OF SELLER GROUP, BUYER GROUP OR THIRD PARTIES, WHETHER SUCH NEGLIGENCE IS ACTIVE OR PASSIVE, JOINT, CONCURRENT OR SOLE, EXCLUDING ANY SOLE OR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER GROUP.

16.4 Seller’s General Indemnity - Seller shall, upon Closing, defend, indemnify, release and hold Buyer Group harmless from and against any and all Claims in favor of any person for personal injury, death or damage to property or for any other Claims arising from or related to (i) Seller’s breach of any of its representations and warranties in this Agreement, (ii) Seller’s breach of any of its covenants in and under this Agreement, (iii) subject to the provisions of ARTICLE 8, any and all duties and obligations of Seller, or Claims, express or implied with respect to the Assets, or the use, ownership, operation or disposition of the Assets arising before (or otherwise attributable to periods, or to actions, occurrences or operations conducted prior to) the Effective Time under any theory of liability, including, without limitation, by virtue of the Leases, Easements, Contracts and/or any permit, applicable statute, rule, regulation or order of any Governmental Authority, (iv) subject to the provisions of ARTICLE 8, personal injury, illness, bodily injury, death, damage to property or for any other Claims arising directly or indirectly from, or incident to, the use, occupation, operation (including, but not limited to, royalty and accounting Claims) or maintenance of any of the Assets, and arising or accruing prior to the Effective Time, (v) subject to the provisions of ARTICLE 8, personal injury, illness, bodily injury, death, or damage to property arising directly or indirectly from, or incident to, the use, occupation, operation or maintenance of any of the Assets, and arising or accruing between the Effective Time and Closing but only insofar as said matters are covered by Seller’s insurance policies in excess of all deductibles and loss loads, and limited to the amount of coverage provided thereby, (vi) the failure of Seller to properly pay when due all royalties, overriding royalties, production payments, and working interest payments relating to the Assets and attributable to periods prior to the Effective Time, (vii) the failure of Seller to properly pay when due all taxes as determined under ARTICLE 12, (viii) any liability or obligation relating to the Litigation, and (ix) any Excluded Assets, REGARDLESS OF WHETHER ANY OF SUCH CLAIMS MAY BE ATTRIBUTABLE, IN WHOLE OR IN PART, TO THE STRICT LIABILITY OR NEGLIGENCE OF BUYER GROUP, SELLER GROUP OR THIRD PARTIES, WHETHER SUCH NEGLIGENCE IS ACTIVE OR PASSIVE, JOINT, CONCURRENT OR SOLE, EXCLUDING ANY SOLE OR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF BUYER GROUP; PROVIDED, HOWEVER, THAT SELLER’S OBLIGATION TO INDEMNIFY BUYER PURSUANT TO SECTION 16.4(i)-(vii), AND SECTION 9.4(h) ABOVE, INCLUSIVE, SHALL APPLY ONLY FOR A PERIOD OF ONE (1) YEAR

FOLLOWING THE CLOSING DATE, EXCEPT WITH RESPECT TO CLAIMS RELATING TO A BREACH OF SELLER'S REPRESENTATIONS SET FORTH IN SECTIONS 5.1, 5.2, 5.3 AND 5.6, WHICH CLAIMS SHALL SURVIVE FOR THE APPLICABLE STATUTE OF LIMITATIONS. THEREAFTER, BUYER SHALL, PURSUANT TO SECTION 16.3, ASSUME RESPONSIBILITY FOR, AND SHALL ALSO AGREE TO PROTECT, DEFEND, INDEMNIFY AND HOLD SELLER GROUP HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS ARISING IN FAVOR OF ANY PERSON FOR PERSONAL INJURY, DEATH, DAMAGE TO PROPERTY OR FOR ANY OTHER CLAIMS ARISING DIRECTLY OR INDIRECTLY FROM, OR INCIDENT TO, THE USE, OCCUPATION, OPERATION OR MAINTENANCE OF ANY OF THE ASSETS OR ANY OTHER CLAIMS WHICH WOULD OTHERWISE BE SUBJECT TO SELLER'S GENERAL INDEMNITY UNDER SECTION 16.4(i) THROUGH (vii) ABOVE, INCLUSIVE.

16.5 Limitation on Indemnification - Notwithstanding anything to the contrary contained herein, Seller shall have no obligation to indemnify Buyer



unless, and then only to the extent that, (i) any individual claim exceeds $50,000 per item and (ii) the aggregate Losses to which Buyer would be entitled to indemnification (but for the provision of this Section 16.5) exceed a deductible equal to one and one-half percent (1.5%) of the Base Purchase Price; provided, however, that the foregoing limitations shall not apply to any Claim made by Buyer Group pursuant to Sections 9.4(h), 16.4(ii), 16.4(vi), 16.4(vii), 16.4(viii), 16.4(viii) or 16.4(x), or a claim under Section 16.4(i) to the extent results from a breach of Seller's representation and warranty set forth in Sections 5.1, 5.2, 5.3, 5.6, and 5.12. Notwithstanding anything to the contrary contained herein, Seller's aggregate liability for the indemnification under Section 16.4(i) above (except with respect to claims relating to a breach of seller's representations set forth in Sections 5.1, 5.2, 5.3, and 5.6), shall not exceed fifty percent (50%) of the Base Purchase Price.

16.6 Further Limitation on Indemnification - Neither Party shall have any obligation under ARTICLE 16 with respect to any amount which has already been taken into account and applied to or against the Base Purchase Price in the Closing Settlement Statement or the Final Settlement Statement, provided such Party has paid all amounts due pursuant to this Agreement.

## 16.7 Indemnification Procedures

16.7.1 All claims for indemnification under this Agreement shall be asserted and resolved pursuant to this Section 16.7. Any person claiming indemnification hereunder is hereinafter referred to as the “Indemnified Party” and any person against whom such claims are asserted hereunder is hereinafter referred to as the “Indemnifying Party.”

16.7.2 In the event that a Party wishes to assert a claim for indemnity hereunder, such Party shall with reasonable promptness provide to the Indemnifying Party a written notice of the indemnity claim it wishes to assert on behalf of itself or another Indemnified Party, including the specific details of and specific basis under this Agreement for its indemnity claim (a "Claim Notice"). To the extent any Losses for which indemnification is sought are asserted against or sought to be collected from an Indemnified Party by a third party, such Claim Notice shall include a copy of all papers served on the applicable Indemnified Party with

respect to such claim. The Indemnifying Party shall have thirty (30) days from the personal delivery or receipt of the Claim Notice (the "Notice Period") to notify the Indemnified Party (i) whether or not it disputes its liability hereunder with respect to such Losses and/or (ii) with respect to any Losses arising out of, associated with, or relating to third party claims, whether or not it desires, at the sole cost and expense of the Indemnifying Party, to defend the Indemnified Party against any such Losses. In the event that the Indemnifying Party notifies the Indemnified Party within the Notice Period that it desires to defend the Indemnified Party against such Losses, the Indemnifying Party shall have the right to defend all appropriate proceedings with counsel of its own choosing. If the Indemnified Party desires to participate in, but not control, any such defense or settlement it may do so at its sole cost and expense. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate with the Indemnifying Party and its counsel in contesting any Losses that the Indemnifying Party elects to contest or, if appropriate and related to the claim in question, in making any counterclaims against the third party asserting such Losses, or any cross-complaint against any third party (other than a Seller Indemnified Party, if the Indemnified Party is a Seller Indemnified Party; and other than a Buyer Indemnified Party, if the Indemnified Party is a Buyer Indemnified Party). Such cooperation shall include the retention and provision to the Indemnifying Party of all records and other information that are reasonably relevant to the losses at issue. No third party claim that is the subject of indemnification hereunder may be settled or otherwise compromised without the prior written consent of the Indemnifying Party. No such claim may be settled or compromised by the Indemnifying Party without the prior written consent of the Indemnified Party unless such settlement or compromise (i) entails a full and unconditional release of the Indemnified Party (and any other members of the Indemnified Party's group, i.e., all Seller Indemnified Parties or all Buyer Indemnified Parties) without any admission or finding of fault or liability and (ii) does not impose on the Indemnified Party any material non-financial obligation or any financial obligation that is not fully paid by the Indemnifying Party.

## ARTICLE 17

## 17. CASUALTY LOSS

If prior to Closing any of the Assets are substantially damaged or destroyed by fire or other casualty (“Casualty Defect”), Seller shall notify Buyer promptly after Seller learns of such event. Seller shall have the right, but not the obligation, to cure any such Casualty Defect by repairing such damage or, in the case of Equipment, replacing the damaged Equipment with equivalent items, no later than the Closing, insofar as the same are done to Buyer’s reasonable satisfaction. If any Casualty Defect exists at Closing, at Seller’s option, Buyer shall proceed to purchase the damaged Assets, and the Base Purchase Price shall be reduced by the aggregate reduction in value of all affected Assets on account of such Casualty Defect. In the event the parties cannot agree on the value, the dispute shall be resolved in accordance with the dispute resolution provisions set forth in Section 20.3. Notwithstanding any of the preceding provisions of this ARTICLE 17, all adjustments applicable to Casualty Defects shall be made prior to Closing which Closing shall be extended until resolution of any disputes relating to the Casualty Defects (subject to Section 19.1(c)); provided, however, that if adjustments for alleged Title Defects, Environmental Defects, Casualty Defects, Open Defects and contested Environmental Defects do not, in the aggregate, exceed 10% of the Base Purchase Price, then Closing shall occur as to the

other Assets that are not subject to the dispute (with the portion of the Assets subject to the dispute being excluded, and the Base Purchase Price reduced for the entire Allocated Values thereof) and Closing shall subsequently close and consummate the transactions as to the Assets made the subject of the dispute within thirty (30) days following the final resolution of the dispute. Notwithstanding anything to the contrary contained in this ARTICLE 17, Seller shall be entitled to retain all insurance proceeds, if any, and claims against other parties relating to any such Casualty Defect. For purposes of this provision, normal wear and tear shall not be considered a Casualty Defect.



All communications between Buyer and Seller required or permitted under this Agreement shall be in writing, and any communication or delivery hereunder shall be deemed to have been fully made if actually delivered, by facsimile transmission, or if mailed by registered or certified mail, postage prepaid, to the address as set forth below:

## BUYER

## HALCON ENERGY PROPERTIES, INC.

1000 Louisiana Street, Suite 6700
Houston, Texas 77002
Attention: Steve W. Herod
Phone: (832) 538 0506
Fax: (713) 589 8019
Email: sherod@halconresources.com

with a copy to:

Halcon Energy Properties, Inc.
1000 Louisiana Street, Suite 6700
Houston, Texas 77002
Attention: David Elkouri
Phone: (832) 538 0514
Fax: (713) 589 8019
Email: delkouri@halconresources.com

## SELLER

SAMSON EXPLORATION, LLC
110 West 7^{th} Street, Suite 2000
Tulsa, Oklahoma 74119
Attention: Scott Rowland
Phone: (918) 879-9812
Fax: (918) 878-8321
Email: srowland@samsonco.com

with a copy to:

Samson Energy Company, LLC
110 West 7^{th} Street, Suite 2000
Tulsa, Oklahoma 74119
Attention: Mark M. Lauer
Phone: (918) 879-9612
Fax: (918) 878-9312
Email: mlauer@samsonco.com

## ARTICLE 19

## 19. TERMINATION

19.1 Termination - This Agreement and the transactions contemplated hereby may be terminated at any time prior to the Closing:

(a) by the mutual written agreement of Buyer and Seller;

(b) by written notice from either Buyer or Seller if Closing has not occurred on or before June 1, 2017; provided, however, that no Party may terminate this Agreement pursuant to this Section 19.1(b) if such Party’s breach of its

representations and warranties or its failure to comply with its obligations or covenants under this Agreement caused the Closing not to occur on or before this date; or

(c) by written notice from either Buyer or Seller if ten percent (10%) of the Base Purchase Price is less than the aggregate sum of (i) the Title Defect amounts for all Title Defects timely and properly asserted pursuant to ARTICLE 7 (excluding all Title Defects related to any Reversionary Interests), (ii) the Environmental Defect amounts for all Environmental Defects timely and properly asserted pursuant to ARTICLE 8, and (iii) the Casualty Defect amounts pursuant to ARTICLE 17; provided, however, that Buyer shall have the right to waive or reduce the amount of any previously asserted Title Defects and Environmental Defects, by written notice to Seller within three (3) Business Days after receipt of a termination notice, such that the aggregate sum of the foregoing defects is less than 10%, thereby enabling the Parties to proceed to Closing in lieu of termination.

19.2 Liabilities Upon Termination; Deposit Amount - If this Agreement terminates, as described in Section 19.1 above, then the entire Deposit will be returned and paid to Buyer and all obligations of the Parties under this Agreement will thereafter terminate and be of no further force and effect, except that the provisions of Section 20.4 and 20.5 will survive; provided, however, that if this Agreement is terminated because of either (i) a willful or intentional breach of this Agreement by Seller or because Seller’s conditions to Closing are not satisfied as a result of Seller’s willful or intentional failure to comply with its obligations under this Agreement, then Buyer’s sole and exclusive remedy for any breach or failure to perform by Seller under this Agreement shall be to terminate this Agreement, to receive the Deposit from the Escrow Agent, and to pursue all remedies available at law for damages or other relief, in equity or otherwise, including, without limitation, specific performance; or (ii) a willful or intentional breach of this Agreement by Buyer or because Buyer’s conditions to Closing are not satisfied as a result of Buyer’s willful or intentional failure to comply with its obligations under this Agreement, then Seller’s sole and exclusive remedy for any breach or failure to perform by Buyer under this Agreement shall be to terminate this Agreement, to receive and retain the Deposit as liquidated damages from the Escrow Agent (and the Parties hereby acknowledge that the extent of damages to Seller occasioned by such breach or default or failure to proceed by Buyer would be impossible or extremely impractical to ascertain and that the Deposit is a fair and reasonable estimate of such damage).

## ARTICLE 20

## 20. MISCELLANEOUS

20.1 Entire Agreement - This Agreement and all Exhibits and Schedules hereto constitute the entire agreement between the Parties. Any previous negotiations or communications between the Parties are merged herein.



20.2 Survival - This Agreement shall be binding upon and shall inure to the benefit of the undersigned, their successors, heirs, assigns and corporate successors and may be supplemented, altered, amended, modified, or revoked by writing only, signed by both Parties. The representations made by Seller and Buyer under ARTICLE 5 and ARTICLE 6 shall continue in full force and effect for a period of twelve (12) months from and after

the Closing Date; provided, however, that the representations made by Seller in Sections 5.1, 5.2, 5.3 and 5.6 and the representations made by Buyer in 6.4 shall further survive for the applicable statute of limitations. All other representations, promises, agreements, releases, and indemnities made in this Agreement or in the Conveyances shall survive Closing.

## 20.3 Arbitration and Dispute Resolution Procedures

(a) If a Party notifies the other Party of any disputed items regarding either (i) the existence of any Title Defects asserted by Buyer, or the value of any adjustments to the Base Purchase Price therefor, (ii) the existence of any Environmental Defects asserted by Buyer, or the value of any adjustments to the Base Purchase Price therefor (iii) the existence of any Casualty Defects asserted by Buyer, or the value of any adjustments to the Base Purchase Price therefor, or (iv) any other proposed adjustments to the Base Purchase Price to be made at Closing, or to be made after Closing in connection with the Final Settlement Statement, then Seller and Buyer shall promptly meet and attempt to resolve the dispute within fifteen (15) days following written notification of the dispute in accordance with the applicable terms of this Agreement. In the event the Parties fail to resolve their differences, then all such items remaining in dispute after the later of Closing or the end of such 15-day period shall be submitted by Seller and Buyer (i) in the case of Title Defects or Casualty Defects (or adjustments relating thereto), a "Title/Casualty Expert" mutually agreed to by the Parties, (ii) in the case of Environmental Defects (or adjustments relating thereto), an "Environmental Expert" mutually agreed to by the Parties, and (iii) in the case of any other proposed adjustments to the Base Purchase Price to be made at Closing, or to be made after Closing in connection with the Final Settlement Statement, then to one of the nationally recognized independent auditors or accounting firms ("Accounting Experts") mutually agreed to by the Parties (in each case, the Title/Casualty Expert, the Environmental Expert and the Accounting Expert, as applicable, is herein referred to as the "Neutral Auditor"). All fees and expenses of the Neutral Auditor relating to the work, if any, to be performed thereby pursuant to this Section 20.3(a) shall be borne 50% by Seller and 50% by Buyer; provided, however, that in the event that the Neutral Auditor determines that the actual adjustment to the Base Purchase Price relative to a disputed item varies less than 10% of the original adjustment proposed for the applicable Title Defect, Casualty Defect, Environmental Defect or other adjustment to the Base Purchase Price and made the subject of the dispute, then the Party disputing the same shall be charged 100% of the costs of the Neutral Auditor. Except as provided in the preceding sentence, all other costs and expenses incurred by the Parties in connection with resolving any dispute hereunder before the Neutral Auditor shall be borne by the Party incurring such cost and expense. The Neutral Auditor shall act as an arbitrator to determine only those items still in dispute at the end of the 15-day resolution period. In no event shall the Neutral Auditor's determination be outside of the range of amounts claimed by the respective Parties with respect to those items in dispute. The Parties shall instruct the Neutral Auditor to render its reasoned written decision as soon as practicable but in no event later than 30 days after his, her or its engagement (which engagement shall be made no later than ten (10) Business Days after the end of the fifteen-day period in which the Parties were to have attempted to reach mutual agreement and resolution of the disputed item). Such

decision shall be set forth in a written statement delivered to Seller and Buyer and shall be final, binding, conclusive and nonappealable for all purposes hereunder. In all cases, the Neutral Auditor must be independent of the Parties to the dispute, have the type of applicable experience described in Section 20.3(c) below and render a decision on a neutral basis, in accordance with the terms of this Agreement.

(b) Except for the type of dispute described and addressed in Section 20.3(a) above, any other dispute arising under this Agreement (an "Arbitrable Dispute") shall be referred to and resolved by binding arbitration in Houston, Texas by three (3) arbitrators, using the Commercial Arbitration Rules of the American Arbitration Association ("AAA"), but not using the offices or auspices of the AAA; and, to the maximum extent applicable, the Federal Arbitration Act (Title 9 of the United States Code). If there is any inconsistency between this Article and any statute or rules, this Article shall control. Arbitration shall be initiated within the applicable limits set forth in this Agreement and not thereafter or if no time limit is given, within the time period allowed by the applicable statute of limitations, by one Party ("Claimant") giving written notice to the other Party ("Respondent"), that the Claimant elects to refer the Arbitrable Dispute to arbitration, and that the Claimant has appointed an arbitrator, who shall be identified in such notice. The Respondent shall notify the Claimant within thirty (30) days after receipt of Claimant's notice, identifying the arbitrator the Respondent has appointed. The two (2) arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed (upon failure of a Party to act within the time specified for naming an arbitrator, such arbitrator shall be appointed by the presiding Federal District Judge for the Southern District of Texas (the "Designating Judge")). Seller shall pay the compensation and expenses of the arbitrator named by or for it, Buyer shall pay the compensation and expenses of the arbitrator named by or for it, and Seller and Buyer shall each pay one-half of the compensation and expenses of the third arbitrator.

(c) Each arbitrator must be a neutral party who has never been an officer, director or employee of the Parties or any of their affiliates or any entity in which a Party owns or controls, or owned or controlled, more than a ten percent (10%) interest, has not provided professional or consulting services for either Party within the five (5) years preceding the commencement of the proceedings, has more than ten (10) years' experience in the oil and gas industry, and must have a formal financial/accounting, engineering or legal education. The hearing for an Arbitral Dispute shall be commenced within sixty (60) days after the selection of the third arbitrator. The parties and the arbitrators shall proceed diligently in accordance with the procedures set forth in Section 20.3 in order that the arbitral award shall be made as promptly as possible. All statutes of limitation that would otherwise be applicable shall apply to any arbitration proceeding. The tribunal shall not have the authority to grant or award indirect or consequential damages, punitive



damages or exemplary damages.

(d) If the arbitration panel determines that an Arbitrable Dispute does not present a valid Claim, the panel shall deny the Claim and no damages shall be awarded.

(e) If, as a result of the initial decision making process, the arbitration panel determines that a valid Claim was presented as an Arbitrable Dispute, the arbitration hearing shall be scheduled and conducted as promptly as possible in Houston, Texas. The amount of the award relating to the Claim shall be determined by the majority vote of the three (3) arbitrators. Except as provided in clause (b), all costs and expenses incurred by the Parties in connection with resolving any dispute hereunder shall be borne by the Party incurring such cost and expense; provided, however, that the arbitration panel shall have the authority to award attorney's fees and costs of arbitration to the prevailing Party if the panel determines that the non-prevailing Party's position was not based on a commercially reasonable interpretation of the applicable standards, law or facts.

20.4 Confidentiality - The parties understand and agree that the terms and provisions of that certain Confidentiality Agreement dated November 23, 2016 by and between Seller and Halcon Resources Corporation (the "Confidentiality Agreement") shall remain in full force and effect until the Closing of this transaction. In the event of termination of this Agreement pursuant to ARTICLE 19, the Buyer agrees to keep all of the terms of this transaction confidential for a period equal to the later of the date of termination of the Confidentiality Agreement or two (2) years following termination of this Agreement. Furthermore, any additional information obtained as a result of Buyer's access to the Assets which does not specifically relate to the Assets shall continue to be treated as confidential for a period of two (2) years following the date of this Agreement and shall not be disclosed by the Buyer without the prior written consent of the Seller. The above restrictions on disclosure and use of information obtained pursuant to this Agreement shall not apply to information to the extent it:

(a) is or becomes publicly available through no act or omission of the Buyer or any of their consultants or advisors; or

(b) is subsequently obtained lawfully from a third party, where the Buyer has made reasonable efforts to ensure that such third party is not a party to or bound by any confidentiality agreement with the Seller; or

(c) is already in the Buyer’s possession at the time of disclosure, without restriction on disclosure.

If the Buyer employs consultants, advisors or agents to assist in its review of the Assets, Buyer shall be responsible to Seller for ensuring that such consultants, advisors and agents comply with the restrictions on the use and disclosure of information set forth in this Section 20.4.

20.5 Choice of Law - THIS AGREEMENT AND ITS PERFORMANCE SHALL BE CONSTRUED IN ACCORDANCE WITH, AND GOVERNED BY, THE LAWS OF THE STATE OF TEXAS.

20.6 Assignment - The rights and obligations under this Agreement may not be assigned by any Party without the prior written consent of the other Party and any nonpermitted assignment shall be void.

20.7 No Admissions - Neither this Agreement, nor any part hereof, nor any performance under this Agreement shall constitute or be construed as a finding, evidence of, or an admission

or acknowledgment of any liability, fault, or past or present wrongdoing, or violation of any law, rule, regulation, or policy, by either Seller or Buyer or by their respective officers, directors, employees, or agents.

20.8 Amendments - Except for waivers specifically provided for in this Agreement, this Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the other Party claiming the benefit of such amendment or waiver.

20.9 Counterparts - This Agreement may be executed by Buyer and Seller in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute one and the same instrument. Execution can be evidenced by facsimile transmission of signatures pages with original signature pages to promptly follow in due course.

20.10 Third-Party Beneficiaries - Except to the limited extent expressly provided otherwise in Sections 8.5, 16.3, and 16.4, neither this Agreement nor any performances hereunder by Seller or Buyer shall create any right, claim, cause of action, or remedy on behalf of any person not a party hereto.

20.11 Public Communications - After Closing, either Party may make a press release or public communication concerning this transaction; provided, however, any such press release or public communication is subject to the other Party’s prior review and written approval; provided, further, however, that, if either Party is required by law or the rules of the New York Stock Exchange to make such public announcement or statement, then the same may be made without the approval of the other Party.

20.12 Headings - The headings of the Articles and Sections of this Agreement are for guidance and convenience of reference only and shall not limit or otherwise affect any of the terms or provisions of this Agreement.

20.13 Expenses - Each of the Parties hereto shall pay its own fees and expenses incident to the negotiation and preparation of this Agreement and consummation of the transactions contemplated hereby, including brokers' fees. Buyer shall be responsible for the cost of all fees for the



recording of the Conveyances relating to the Assets. All other costs shall be borne by the Party incurring them.

20.14 Waiver of Consumer and Other Rights - Seller and Buyer intend that Buyer’s rights and remedies with respect to the transaction contemplated by this Agreement and with respect to all acts or practices of Seller, past, present or future, in connection with the transaction contemplated by this Agreement shall be governed by legal principles other than the Texas Deceptive Trade Practices Consumer Protection Act, Tex. Bus. & Com. Code Ann. §17.41, et seq. (Vernon 1987) (the “DTPA”) or similar laws in other states. BUYER WAIVES IT RIGHTS UNDER THE DTPA SPECIFICALLY INCLUDING SECTION 17.41 ET. SEQ., VERNON’S TEXAS CODE ANNOTATED, BUSINESS AND COMMERCE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS, OR ANY SIMILAR STATE OR FEDERAL LAW. AFTER AN OPPORTUNITY TO CONSULT WITH AN ATTORNEY OF ITS OWN SELECTION, BUYER ACKNOWLEDGES THAT THE DISCLAIMERS AND WAIVERS GIVEN IN AND UNDER THIS AGREEMENT SHALL BE CONSIDERED MATERIAL AND

INTEGRAL PARTS OF THIS AGREEMENT, WITH CONSIDERATION GIVEN THEREFORE, AND ACKNOWLEDGES THAT ALL DISCLAIMERS AND WAIVERS ARE “CONSPICUOUS” AND HAVE BEEN BROUGHT TO THE ATTENTION OF BUYER, AND THAT BUYER HAS VOLUNTARILY AND KNOWINGLY CONSENTED TO ALL DISCLAIMERS AND WAIVERS. Buyer hereby warrants and represents to Seller, as of the date hereof and as of the Closing Date, that (i) Buyer is not in a significantly disparate bargaining position, (ii) Buyer has been represented by legal counsel in connection with the transaction contemplated by this Agreement, which transaction does not involve the purchase or lease of a family residence occupied or to be occupied as a residence, and which transaction is for a consideration paid or to be paid that exceeds $500,000.00 and (iii) Buyer is a business consumer with assets of $5,000,000.00 or more according to Buyer’s most recent financial statement prepared in accordance with GAAP and has knowledge and experience in financial and business matters that enable Buyer to evaluate the merits and risks of the transaction. Buyer acknowledges that the Base Purchase Price is predicated upon this waiver of the DTPA and similar laws in other states and the inapplicability of the DTPA and similar laws in other states and Buyer’s representations and warranties contained in this Section 20.14, and the Seller, in determining to proceed with entering into this Agreement, has expressly relied upon this waiver and the inapplicability of the DTPA and similar laws in other states and Buyer’s representations and warranties contained in this Section 20.14.

20.15 Non-Compensatory Damages. - None of the Buyer Group or Seller Group shall be entitled to recover from Seller or Buyer, as applicable, or their respective affiliates, any indirect, consequential, punitive or exemplary damages or damages for lost profits of any kind arising under or in connection with this Agreement or the transactions contemplated by this Agreement, except to the extent any such Party suffers such damages (including costs of defense and reasonable attorney's fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Group, and Seller, on behalf of the Seller Group, each waive any right to recover punitive, special, exemplary and consequential damages, including damages for lost profits of any kind, arising in connection with this Agreement or the transactions contemplated by this Agreement. This Section 20.15 shall not restrict any Party's right to obtain specific performance or other equitable remedies (other than rescission) pursuant to this Agreement.

[Signature page follows.]

50

IN WITNESS WHEREOF, the parties have executed this Agreement on the date first written above.

“SELLER”

SAMSON EXPLORATION, LLC

By: /s/ Scott Rowland
Scott Rowland
Vice President—Business Development

“BUYER”

HALCON ENERGY PROPERTIES, INC.

By: /s/ Floyd C. Wilson
Floyd C. Wilson
Chief Executive Officer and President



AGREEMENT OF SALE AND PURCHASE
BY AND AMONG
HALCÓN ENERGY PROPERTIES, INC.,
HALCON HOLDINGS, INC.,
HK ENERGY, LLC,
HK OIL & GAS, LLC,
HRC ENERGY, LLC,
THE 7711 CORPORATION,
HALCÓN OPERATING CO., INC.,
AND
HALCÓN FIELD SERVICES, LLC,
AS SELLERS,
AND
HAWKWOOD ENERGY EAST TEXAS, LLC
AS PURCHASER
JANUARY 24, 2017

## TABLE OF CONTENTS

Article 1. PURCHASE AND SALE 1
Section 1.1. Purchase and Sale 1
Section 1.2. Assets 1
Section 1.3. Excluded Assets 7
Section 1.4. Effective Time; Proration of Costs and Revenues 8
Section 1.5. Delivery and Maintenance of Records 9
Article 2. PURCHASE PRICE 10
Section 2.1. Purchase Price 10
Section 2.2. Adjustments to Purchase Price 10
Section 2.3. Allocation of Purchase Price 12
Section 2.4. Deposit 12
Section 2.5. Tax Allocation 13
Article 3. TITLE MATTERS 13
Section 3.1. Sellers' Title 13
Section 3.2. Definitions of Title Matters 14
Section 3.3. Definition of Permitted Encumbrances 15
Section 3.4. Notice of Title Defect Adjustments 17
Section 3.5. Casualty or Condemnation Loss 24
Section 3.6. Limitations on Applicability 25
Section 3.7. Government Approvals Respecting Assets 25
Article 4. ENVIRONMENTAL MATTERS 26
Section 4.1. Assessment 26
Section 4.2. NORM, Wastes and Other Substances 27
Section 4.3. Environmental Defects 27



Section 4.4. Inspection Indemnity 30
Article 5. REPRESENTATIONS AND WARRANTIES OF SELLERS 31
Section 5.1. Generally 31
Section 5.2. Existence and Qualification 31
Section 5.3. Power 32
Section 5.4. Authorization and Enforceability 32
Section 5.5. No Conflicts 32
Section 5.6. Liability for Brokers' Fees 32
Section 5.7. Litigation 32
Section 5.8. Taxes and Assessments 33
Section 5.9. Compliance with Laws 33
Section 5.10. Contracts 34
Section 5.11. Payments for Hydrocarbon Production 34
Section 5.12. Governmental Authorizations 34
Section 5.13. Preference Rights and Transfer Requirements 35
Section 5.14. Payout Balances 35
Section 5.15. Outstanding Capital Commitments 35
Section 5.16. Imbalances 35
Section 5.17. Condemnation 36
Section 5.18. Bankruptcy 36
Section 5.19. Foreign Person 36
Section 5.20. Suspended Funds 36
Section 5.21. Hydrocarbon Marketing 36
Section 5.22. Insurance 37
Section 5.23. Employees 37
Article 6. REPRESENTATIONS AND WARRANTIES OF PURCHASER 37
Section 6.1. Existence and Qualification 37
Section 6.2. Power 38
Section 6.3. Authorization and Enforceability 38
Section 6.4. No Conflicts 38
Section 6.5. Liability for Brokers' Fees 38
Section 6.6. Litigation 38
Section 6.7. Limitation and Independent Evaluation 39
Section 6.8. SEC Disclosure 39
Section 6.9. Bankruptcy 39
Section 6.10. Qualification 40
Section 6.11. Financing 40
Article 7. COVENANTS OF THE PARTIES 40
Section 7.1. Access 40
Section 7.2. Government Reviews 41
Section 7.3. Notification of Breaches 42
Section 7.4. Letters in Lieu; Assignments; Operatorship 42
Section 7.5. Public Announcements 43
Section 7.6. Operation of Business 43
Section 7.7. Preference Rights and Transfer Requirements 44
Section 7.8. Tax Matters 46
Section 7.9. Further Assurances 49
Section 7.10. Notice of Claims 49
Section 7.11. Enforcement of Third Party Warranties, Guarantees and Indemnities 49
Section 7.12. Non-Compete 49
Section 7.13. Transferred Employees 50



Article 8. CONDITIONS TO CLOSING 50
Section 8.1. Conditions of Sellers to Closing 50
Section 8.2. Conditions of Purchaser to Closing 51
Article 9. CLOSING 52
Section 9.1. Time and Place of Closing 52
Section 9.2. Obligations of Sellers at Closing 53
Section 9.3. Obligations of Purchaser at Closing 54
Section 9.4. Closing Adjustments 55
Article 10. TERMINATION 56
Section 10.1. Termination 56
Section 10.2. Remedies 57
Article 11. POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS 58
Section 11.1. Receipts 58
Section 11.2. Expenses 58
Section 11.3. Assumed Seller Obligations 59
Section 11.4. Survival and Limitations; Exclusive Remedy 60
Section 11.5. Indemnification by Each Seller 62
Section 11.6. Indemnification by Purchaser 62
Section 11.7. Indemnification Proceedings 63
Section 11.8. Release 65
Section 11.9. Disclaimers 65
Section 11.10. Recording 66
Article 12. MISCELLANEOUS 67
Section 12.1. Counterparts 67
Section 12.2. Notice 67
Section 12.3. Sales or Use Tax Recording Fees and Similar Taxes and Fees 68
Section 12.4. Expenses 68
Section 12.5. Change of Name 68
Section 12.6. Replacement of Bonds, Letters of Credit and Guarantees 69
Section 12.7. Governing Law and Venue 69
Section 12.8. Captions 69
Section 12.9. Waivers 69
Section 12.10. Assignment 69
Section 12.11. Entire Agreement 70
Section 12.12. Amendment 70
Section 12.13. No Third-Party Beneficiaries 70
Section 12.14. References 70
Section 12.15. Construction 71
Section 12.16. Conspicuousness 71
Section 12.17. Severability 71
Section 12.18. Time of Essence 71
Section 12.19. Limitation on Damages 71
Section 12.20. Suspended Funds 72
Section 12.21. Joint and Several Liability 72
Section 12.22. Seller Representative 72
Section 12.23. No Recourse 72
iv
EXHIBITS

Exhibit A Leases
Exhibit A-1 Wells and Units
Exhibit A-2 Oil and Gas Equipment
Exhibit A-3 Gathering System Plat
Exhibit A-4 Midstream Surface Rights



Exhibit B-1 Oil and Gas Conveyance
Exhibit B-2 Midstream Conveyance
Exhibit C Indemnity Agreement
Exhibit D Acquisition Area
Exhibit E Transition Services Agreement

## SCHEDULES

Schedule 1.2(a)(iv) Oil and Gas Contracts
Schedule 1.2(a)(xii) Seismic Data
Schedule 1.2(a)(xiii) Vehicles
Schedule 1.2(b)(vi) Midstream Contracts
Schedule 1.3(d) Excluded Assets
Schedule 1.4 Overhead Costs
Schedule 2.3 Allocated Values
Schedule 5.1 Identification of Certain Officers and Employees of Seller and Identification of Certain Officers and Employees of Purchaser
Schedule 5.7(a) Party Proceedings
Schedule 5.7(b) Non-Party Proceedings
Schedule 5.8 Taxes and Assessments
Schedule 5.9 Compliance with Laws
Schedule 5.10 Contract Matters
Schedule 5.11 Hydrocarbon Production Payments
Schedule 5.12 Governmental Authorizations
Schedule 5.13 Preference Rights and Transfer Requirements
Schedule 5.14 Payout Balances
Schedule 5.15 Outstanding Capital Commitments
Schedule 5.16 Imbalances
Schedule 5.20 Suspended Funds
Schedule 5.21 Hydrocarbon Marketing
Schedule 5.22 Insurance
Schedule 7.6 Operation of Business
Schedule 9.4(d) Account Information

## AGREEMENT OF SALE AND PURCHASE

This Agreement of Sale and Purchase (“Agreement”) is executed as of January 24, 2017, by and among HALCÓN ENERGY PROPERTIES, INC. a Delaware corporation, HALCON HOLDINGS, INC., a Delaware corporation, HK ENERGY, LLC, a Texas limited liability company, HK OIL & GAS, LLC, a Texas limited liability company, HRC ENERGY, LLC, a Colorado limited liability company, THE 7711 CORPORATION, a Texas corporation, HALCÓN OPERATING CO., INC., a Texas corporation, and HALCÓN FIELD SERVICES, LLC, a Delaware limited liability company (each a “Seller” and collectively, the “Sellers”), and Hawkwood Energy East Texas, LLC, a Delaware limited liability company (“Purchaser”).

## RECITALS

A. Each Seller owns certain interests in the Assets as more fully described in Section 1.2 and the exhibits hereto.

B. Sellers desire to sell to Purchaser and Purchaser desires to purchase from Sellers the properties and rights of each Seller hereafter described, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound by the terms hereof, agree as follows:

## ARTICLE 1.
PURCHASE AND SALE

## Section 1.1. Purchase and Sale.

(a) At the Closing, and upon the terms and subject to the conditions of this Agreement, each Seller agrees to sell, assign, transfer and convey its interests in the Oil and Gas Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the interests of each Seller in the Oil and Gas Assets and to assume the Assumed Oil and Gas Obligations.

(b) At the Closing, and upon the terms and subject to the conditions of this Agreement, each Seller agrees to sell, transfer and convey its interests in the Midstream Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the interests of each Seller in the Midstream Assets and to assume the Assumed Midstream Obligations.

Section 1.2. Assets.



(a) As used herein, the term “Assets” means, collectively, the Oil and Gas Assets and Midstream Assets. As used herein, the term “Oil and Gas Assets” means subject to the terms and conditions of this Agreement, all of Sellers’ right, title, interest and estate, in and to the following (but excluding the Excluded Assets):

(i) All of the oil and/or gas leases; subleases and other leaseholds; interests in fee; carried interests; reversionary interests; net profits interests; royalty interests; overriding royalty interests; forced pooled interests; farmout rights; options; mineral interests and other properties and interests described on Exhibit A, subject to such depth limitations and other restrictions as may be set forth in the oil and gas leases or other agreements of record in respect thereof, together with all rights, privileges, benefits and powers conferred upon the holder of said interests with respect to the use and occupation of the lands covered thereby (collectively, the “Leases”), together with each and every kind and character of right, title, claim, interest and estate that each Seller has in and to the lands covered by the Leases and the interests currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

(ii) All oil, gas, water supply wells or injection wells located on the Lands, whether producing, shut-in, or temporarily abandoned, and the interests in the wells shown on Exhibit A-1 attached hereto (collectively, the “Wells”);

(iii) All interests of Sellers in or to any currently existing pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units related to the Oil and Gas Properties and associated with the Wells shown on Exhibit A-1 (the "Units"; the Units, together with the Leases, Lands, and Wells, being hereinafter referred to as the "Oil and Gas Properties"), and including all interests of Sellers in the production of Hydrocarbons from any such Units, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(iv) All contracts, agreements and instruments by which the Oil and Gas Properties are bound or subject, or that relate to or are otherwise applicable to the Oil and Gas Properties, only to the extent applicable to the Oil and Gas Properties rather than Sellers' or any of their Affiliates' other properties, including operating agreements, unitization, pooling and commutation agreements, declarations and orders, joint venture agreements, farm and farmout agreements, exploration agreements, participation agreements, area of mutual interest agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of oil, gas or casigned gas, and processing agreements, to the extent applicable to the Oil and Gas Properties or the production of Hydrocarbons therefrom or allocable thereto, including those identified on Schedule 1.2(a)(iv) (collectively, the "Oil and Gas Contracts"), but excluding any contracts, agreements and instruments to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7, and provided that "Oil and Gas Contracts" shall not include the instruments constituting the Leases;

(v) All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases, water rights or water leases, any single or multiyear water allocations from the Brazos River Authority or other similar entity, and other surface rights (collectively, "Oil and Gas Surface Rights") appurtenant to, and used or held for use primarily in connection with the Oil and Gas Properties, whether part of the premises covered by the Leases or Units or otherwise, but excluding (A) the Midstream Surface Rights and (B) any permits and other rights to the extent the transfer thereof would result in a violation of applicable Law or is

restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7;

(vi) All equipment, machinery, fixtures and other tangible personal and mixed property and improvements, whether movable or immovable, located either on or off the Oil and Gas Properties and that is used or held for use in connection with the ownership, use, development, and operation of the Oil and Gas Properties and Oil and Gas Surface Rights and the production, treatment, gathering, storage, processing, transportation, and marketing of Hydrocarbons produced therefrom or allocable thereto, including those items of personal property and equipment identified on Exhibit A-2 (the "Oil and Gas Equipment");

(vii) All water ponds that are used or held for use in connection with the ownership, use, development, and operation of the Oil and Gas Properties and the hydraulic fracturing operations thereon;

(viii) All Hydrocarbons (A) produced from or allocable to the Oil and Gas Properties and existing in storage tanks or other storage facilities upstream of the delivery points to the relevant purchasers as of the Effective Time, or (B) produced from or allocable to the Oil and Gas Properties from and after the Effective Time;

(i) All claims of Sellers against other Persons pertaining to Imbalances in existence as of the Effective Time;

(x) all lease files, land files, well files, gas and oil sales contract files, gas processing and transportation files, division order files, abstracts, title opinions, title curative, land surveys, land broker work products including tract information and shape files, log graphics, LAS format log data, original format log data (DLIS,LIS), cores, data derived from cores, maps, engineering data and reports, interpretive data (proprietary and third party), technical evaluations (proprietary and third party) and technical outputs (proprietary and third party), operations, production, facility, and environmental records and files, marketing files, property, severance, and production Tax records and files, regulatory compliance records and files (including reports to Governmental Bodies), and other books, records, data, files, and accounting records (including, but not limited to, records showing all funds payable to owners of working interests, royalties, overriding royalties and other interests in the Oil and Gas Properties held in suspense by a Seller as of the Closing Date), in each case to the extent related to the Oil and Gas Properties, or used or held for use in connection therewith and in Sellers' possession and subject to any limitations with respect to any applicable attorney-client privilege or confidentiality restrictions (the "Oil and Gas Records");

(xi) All offices, field offices, warehouses and storage facilities, whether owned or leased, that are used or held for use in connection with the ownership, use, development, and operation of the Oil and Gas Properties, including that certain Office Lease dated December 20, 2013 by and between Crystal Park Plaza LLC and Halcon Resources Corporation regarding that office lease in College Station, Texas for approximately 9,000 square feet, as



(xii) Except for Excluded Assets, to the extent transferable, and subject to the payment by Purchaser of all applicable third Person transfer and license fees all geological,

geophysical and other scientific and technical information, samples, whole core, sidewalk cores, tests, reports, maps, and data (including all seismic data, as well as reprocessed data), and interpretations thereof, related primarily to the Oil and Gas Properties, including those items identified in Schedule 1.2(a)(xii);

(xiii) All vehicles identified on Schedule 1.2(a)(xiii); and

(xiv) All Suspended Funds payable to owners of working interests, royalties and overriding royalties, and other interests in the Oil and Gas Properties held in suspense by a Seller as of the Closing Date.

(b) As used herein, the term “Midstream Assets” means, subject to the terms and conditions of this Agreement, all of Sellers’ right, title, interest, and estate in and to the following (but excluding the Excluded Assets):

(i) The gas gathering system described more particularly on the plat attached hereto as Exhibit A-3 (the “Gathering System”), including all pipelines, trunk lines, laterals, pipeline interconnects and other receipt and delivery facilities, meters, check meters, and metering stations, measurement and regulation equipment, dehydration equipment, compressors and compression facilities and all other personal property and equipment that are located on or are appurtenant to, or that affect the Gathering System or are used in connection with, installed in or on, or otherwise relate to the ownership and operation of the Gathering System and the gathering and transportation of Hydrocarbons pursuant thereto;

(ii) All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (collectively, the “Midstream Surface Rights”) on which the Gathering System is located or that are otherwise appurtenant to, and used or held for use in connection with, the Gathering System (including those identified on Exhibit A-4), but excluding (A) any Oil and Gas Surface Rights and (B) any permits and other rights to the extent the transfer thereof would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7;

(iii) All gas and other Hydrocarbons present as line pack in the Gathering System as of the Effective Time;

(iv) All fees, rentals, proceeds, payments, revenues, and other rights and economic benefits of every kind and character accruing or payable to the owners of the items listed in this Section 1.2(b) that are attributable to the period from and after the Effective Time;

(v) All contracts and agreements to which the items described in clauses (i) through (iv) of this Section 1.2(b) are subject or by which such items are bound, or that relate or are otherwise applicable to such items, including Hydrocarbon purchase, sale, exchange, gathering, storage, processing, fractionation, condensate removal, handling, and stabilization, dehydration, treatment, compression, transportation and marketing agreements, communications, facilities, and equipment leases and

licenses, and balancing agreements, to the extent applicable to the Gathering System or the other items listed in this Section 1.2(b), including those identified on Schedule 1.2(b)(v) (collectively, the “Midstream Contracts”), but excluding any contracts or agreements to the extent transfer would result in a violation of applicable Law or is restricted by any transfer requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7;

(vi) All field-based electronic field monitoring and field installed communications and computer hardware, networks, and systems used to record, process, and communicate the telemetry associated with the operation of the Gathering System, but specifically excluding all software and custom configurations of the same identified in Section 1.3 as Excluded Assets;

(vii) All land files, contract files, abstracts, title opinions, policies of title insurance, title curative, land surveys, alignment and other system maps, construction, testing, and inspection records, operations, facility, and environmental records and files, property, severance, and production Tax records and files, regulatory compliance records and files (including reports to Governmental Bodies), and accounting records, in each case to the extent related to the Gathering System or the other items listed in this Section 1.2(b), or used or held for use in connection therewith, and in Sellers' possession (the "Midstream Records");

(viii) All equipment, machinery, fixtures and other tangible personal and mixed property and improvements, whether movable or immovable that is used or held for use in connection with the ownership, use, development, and operation of the Gathering System (the “Midstream Equipment”); and

(ix) All field offices, warehouses and storage facilities, whether owned or leased, that are used or held for use in connection with the ownership, use, development, and operation of the Gathering System.

(c) From and after the date of this Agreement and continuing until the date that is 60 days after the Closing Date (the “Supplemental Acquisition Period”), if Sellers acquire an oil and gas lease on lands located within the boundaries of the maps attached hereto as Exhibit D (the “Acquisition Area”) (collectively, the “Offered Leases”) prior to the expiration of the Supplemental Acquisition Period, then Sellers shall provide Purchaser with written notice of Sellers’ acquisition of such additional Offered Leases prior to the expiration of the Supplemental Acquisition Period, and such notice shall contain:

(i) copies of the Offered Lease(s) acquired (and any other conveyances into Sellers covering such acquired Offered Leases);



(ii) any ownership and/or title opinions or reports covering the surface and/or mineral estates of the acreage leased;

(iii) a statement of the Net Mineral Acres covered thereby, as well as the Net Revenue Interest and Working Interest attributable to such Offered Leases;

(iv) statement or summary of the pooling permitted under such Offered Lease; and

(v) with respect to Supplemental Properties covering Net Mineral Acres in excess of the Target Acreage, the acquisition costs associated with such Supplemental Properties,

provided, that any such lease must have a term of not less than three years and a Net Revenue Interest of not less than 75% in order to qualify as an Offered Lease.

If the Target Acreage has not been attained as of the Closing Date, then until the expiration of the Supplemental Acquisition Period, Purchaser will be obligated to purchase Offered Leases, as they are offered, at the price per Net Mineral Acre set forth on Exhibit D and attributable to such Offered Leases until the Target Acreage is attained. If the Target Acreage has been obtained, either by the Closing Date or as a result of Purchaser purchasing Offered Leases in accordance with this Section 1.2(c), then Purchaser shall have 10 days after receipt of each such written notice to provide Seller with written response notice whether it elects to acquire any of such Offered Leases under the terms and conditions set forth in this Agreement. Unless otherwise stipulated in the written notice from Sellers to Purchaser, Seller shall be deemed to have represented (and hereby represents) that all such Offered Leases cover lands located within the boundaries of the Acquisition Area. Once Offered Leases have been acquired to attain the Target Acreage as provided above (and if applicable), thereafter, Purchaser is under no obligation to acquire any Offered Leases. To the extent that any Offered Leases are acquired by Sellers after the date of this Agreement and prior to the expiration of the Supplemental Acquisition Period, and Purchaser elects to acquire them, as described above, then there shall be a supplemental closing (the "Supplemental Closing") on a date mutually agreed to by the Parties, but in no event earlier than 30 days or later than 45 days (subject to extension for the resolution of any Title Defect Amounts with respect thereto) after the expiration of the Supplemental Acquisition Period (the "Supplemental Closing Date"), at which time, subject to the terms and conditions hereof, Sellers shall sell all of their interests in and to such Offered Leases, together with all related interests related thereto, and otherwise on the terms set forth in this Agreement as modified by this Section with regard thereto (collectively, the "Supplemental Properties"). All of the representations, warranties and covenants regarding Oil and Gas Properties and the Closing shall apply correspondingly with regard to the Supplemental Properties and the Supplemental Closing (and, without limitation, representations and warranties in Article V shall be deemed to apply with regard to Supplemental Properties), conditions to closing that must be satisfied or waived in connection with the Closing, must likewise be satisfied or waived for purposes of a Supplemental Closing, and notices that must be provided within certain periods prior to or after the Closing in connection with the Oil and Gas Properties, will, likewise, be required to be provided within such same periods prior to or after the Supplemental Closing in connection with the Supplemental Properties (and, by way of example, the notices for Title Defects and Environmental Defects regarding the Supplemental Properties shall be due no later than five Business Days prior to the Supplemental Closing). The purchase price to be paid by Purchasers to Seller for the Supplemental Properties covering Net Mineral Acres in excess of the Target Acreage accepted by Purchaser shall be the acquisition costs incurred by Sellers for the Supplemental Properties. Acquisition costs for Supplemental Properties include landman and brokerage costs, bonuses and other consideration paid, pre-paid surface damages, recording fees,

attorneys’ fees for title review, costs of title curative and any other costs incurred by Sellers to acquire Supplemental Properties.

Section 1.3. Excluded Assets.

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the transaction contemplated hereby (collectively, the “Excluded Assets”):

(a) except to the extent necessary to satisfy Sellers’ obligations under Section 7.1, (i) all corporate, financial, income and franchise tax and legal records of each Seller that relate to such Seller’s business generally (and not relating to the Assets), (ii) all books, records and files that relate to the Excluded Assets (but only to the extent related to the Excluded Assets), (iii) all geological and geophysical data not transferred by a Seller pursuant to Section 1.2(a)(xii), (iv) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the extent disclosure or transfer would result in a violation of applicable Law, (v) computer or communications software or intellectual property (Clear SCADA, Field Direct, Flow Cal, AES, and other software and custom configurations of the same, as well as all tapes, codes, data and program documentation, and all tangible manifestations and technical information relating thereto), (vi) attorney-client privileged communications and work product of each Seller’s or any of such Seller’s Affiliates’ legal counsel (other than title opinions), (vii) reserve studies and evaluations, (viii) records relating to the marketing, negotiation, and consummation of the sale of the Assets and (ix) copies of any other Records retained by a Seller pursuant to Section 1.5(a);

(b) except to the extent related to any Assumed Seller Obligation, all rights to any refund attributable to periods prior to the Effective Time related to the Excluded Seller Obligations or Taxes or other costs or expenses borne by Sellers or Sellers’ predecessors in interest;

(c) a Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of such Seller’s business generally;

(d) those items listed in Schedule 1.3(d);

(e) except to the extent related to any Assumed Seller Obligation, all trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable, pre-paid expenses and deposits, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time;



(f) all exchange traded futures contracts and over-the-counter derivative or hedge contracts of a Seller;

(g) all right, title and interest of Sellers in and to vehicles used in connection with the Assets, other than those identified on Schedule 1.2(a)(xi);

(h) all rights, titles, claims and interests of a Seller or any Affiliate of a Seller (i) to or under any policy or agreement of insurance or any insurance proceeds, except to the extent provided in Section 3.5, and (ii) to or under any bond or bond proceeds;

(i) subject to Section 12.5, any patent, patent application, logo, service mark, copyright, trade name or trademark of or associated with a Seller or any Affiliate of a Seller or any business of a Seller or of any Affiliate of a Seller;

(j) all Retained Assets not conveyed to Purchaser pursuant to Section 7.7 and any Asset excluded pursuant to Section 3.4, Section 4.3(b) or Section 4.3(d); and

(k) all abandoned or unclaimed property reportable under or subject to any state or local unclaimed property, escheat or similar Law where the dormancy period elapsed prior to the Effective Time.

## Section 1.4. Effective Time; Proration of Costs and Revenues.

(a) Subject to Section 1.5, possession of the Assets shall be transferred from Sellers to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be transferred to and assumed as described below by Purchaser, effective as of 7:00 A.M., local time, where the Assets are located, on January 1, 2017 (the “Effective Time”).

(b) Purchaser shall be entitled to (i) all Hydrocarbon production from or allocable to the Oil and Gas Properties occurring at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, revenues, receipts and credits earned with respect to the Oil and Gas Assets at or after the Effective Time, and all fees, rentals, proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets at or after the Effective Time. Purchaser shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred with respect to the Assets acquired by Purchaser at and after the Effective Time. Each Seller shall be entitled to its proportionate share of all Hydrocarbon production from or allocable to the Oil and Gas Properties occurring prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, revenues, receipts, and credits earned with respect to the Oil and Gas Assets prior to the Effective Time. Sellers shall be entitled to all fees, rentals, proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets prior to the Effective Time. Each Seller shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred with respect to the Assets owned by such Seller prior to the Effective Time.

(c) As used in this Agreement, the terms “earned” and “incurred” shall be interpreted in accordance with GAAP and Council of Petroleum Accountants Society (“COPAS”) standards, as applicable.

(d) As used in this Agreement, the term “Property Costs” means all costs attributable to the ownership and operation of the Assets (including costs of insurance relating specifically to the Assets, but excluding all applicable Taxes) and capital expenditures incurred in the ownership and operation of the Assets, and in the case of the Oil and Gas Assets, where applicable, in accordance with the terms of the relevant operating or unit agreement, if any, and

regardless of whether charged by an Affiliate of a Seller or by a third Person, or, if none, the amounts shown under Schedule 1.4 shall be the overhead amounts deemed charged to the Oil and Gas Assets.

(e) For purposes of this Section 1.4, the determination of whether Property Costs are attributable to the period before or after the Effective Time shall be based on when services are rendered, when the goods are delivered, or when the work is performed. For clarification, the date an item or work is ordered is not the date of a pre-Effective Time transaction for settlement purposes, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, shall be the relevant date. For purposes of allocating Hydrocarbon production (and accounts receivable with respect to the term) and other revenues and income under this Section 1.4, (i) liquid Hydrocarbons shall be deemed to be “from or allocable to” the Oil and Gas Properties when such Hydrocarbons are placed into the storage facilities, and (ii) gaseous Hydrocarbons shall be deemed to be “from or allocable to” the Oil and Gas Properties when such Hydrocarbons pass through the delivery point sales meters on the pipelines through which they are gathered or, if not first gathered, transported.

(f) Sellers shall utilize reasonable interpolative procedures to arrive at an allocation of Hydrocarbon production when exact meter readings or gauging and strapping data is not available. Sellers have provided to Purchaser all data available to Sellers as of five Business Days prior to the Closing Date to support the estimated allocation, for purposes of establishing the adjustments to the Purchase Price pursuant to Section 2.2, used to determine the Closing Payment. Property Costs that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at or after the Effective Time, except that production, severance and similar Taxes shall be prorated based on the number of units actually produced, purchased, or sold, or the proceeds of such sale, as applicable, before, and at or after, the Effective Time. In each case, each Purchaser shall be responsible for the portion attributable to the Assets acquired by such Purchaser allocated to the period at and after the Effective Time, and each Seller shall be responsible for the portion attributable to the Assets owned by such Seller allocated to the period before the Effective Time.

## Section 1.5. Delivery and Maintenance of Records.

(a) Sellers shall deliver the Records (FOB at Sellers' office) to Purchaser within 15 days following termination of the Transition Services Agreement. Purchaser shall be entitled to all original Records maintained by Sellers. Sellers shall be entitled to keep copies of all Records; provided,



however, that from and after the Closing and except in connection with its obligations under this Agreement, each Seller shall not, and shall cause its respective Affiliates and its and their respective officers, directors, employees, agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (with respect to each Seller, the "Subject Representatives") not to, disclose, permit to be disclosed, use, permit to be used, copy or permit to be copied, the Records or any trade secrets or proprietary or confidential information to the extent relating to the Assets, except for (i) disclosures and uses required by applicable Law or stock exchange rules or of information that has become part of the public domain through no action of any Seller or any Subject Representative after the Closing, and (ii) disclosures to financial institutions or other third Persons in connection with

the evaluation of financing or a sales or acquisition transaction provided that such financial institution or other third Person is bound by an obligation of confidentiality no less restrictive than the obligation of confidentiality contained in this Section 1.5 covering such information. Purchaser shall preserve the Records following the Closing in Purchaser's offices in accordance with Purchaser's record retention policy following the Closing and, subject to the foregoing confidentiality obligations, will allow each Seller and their respective representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records in order for a Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute with an un-Affiliated third party for which such Seller is responsible. Any such access shall be at the sole cost and expense of such Seller.

(b) Sellers shall, during normal business hours, make available to Purchaser and Purchaser’s audit firm, KPMG, all supporting schedules, including reserve reports and SMOG calculations, related to the Assets and prepared in connection with the audited financial statements of Sellers’ parent for the years ended December 31, 2015 and 2016. Sellers shall also authorize Sellers’ audit firm, Deloitte, to grant Purchaser and Purchaser’s audit firm, KPMG, reasonable access to all workpapers related to the Assets prepared in connection with the audited financial statements of Sellers’ parent for the years ended December 31, 2015 and 2016.

## ARTICLE 2.
PURCHASE PRICE

## Section 2.1. Purchase Price.

The purchase price for the Assets (the “Purchase Price”) shall be $530,000,000, adjusted as provided in Section 2.2.

## Section 2.2. Adjustments to Purchase Price.

The Purchase Price for the Assets shall be adjusted in the manner specified below (without duplication), with all such amounts being determined in accordance with GAAP and COPAS standards, as applicable, in order to reach the “Adjusted Purchase Price”:

(a) Reduced by the aggregate amount of the following proceeds actually received by Sellers between (and including) the Effective Time and the Closing Date (with the period between and including the Effective Time up to the Closing Date referred to as the “Adjustment Period”): (i) proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Sellers by the purchaser of production) produced from or attributable to the Assets during the Adjustment Period, and (ii) other proceeds earned with respect to the Assets during the Adjustment Period;

(b) Reduced to the extent provided in Section 7.7 with respect to Preference Rights and Retained Assets;

(c) (i) If the Parties make the election under Section 3.4(d)(i) with respect to a Title Defect, subject to the Individual Title Threshold and the Aggregate Defect Deductible, reduced by the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined prior to Closing and (ii) subject to the Individual Title Benefit Threshold and Aggregate Benefit Deductible, increased by the Title Benefit Amount with respect to each Title Benefit for which the Title Benefit Amount has been determined prior to Closing;

(d) Increased by the amount of all Property Costs and other costs attributable to the ownership and operation of the Assets which are paid by Sellers and incurred during the Adjustment Period (including any overhead costs listed on Schedule 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except (i) any Property Costs and other such costs already deducted in the determination of proceeds in Section 2.2(a), (ii) any costs incurred by Sellers in connection with curing any Title Defect or Environmental Defect or with respect to any casualty loss and (iii) any costs incurred as a result of any breach by any Sellers of this Agreement;

(e) Reduced to the extent provided in Section 3.4(d)(iii) for any Oil and Gas Properties excluded from the Assets pursuant to Section 3.4(d)(iii) or retained by Sellers pursuant to Section 3.4(d)(iii) and reduced to the extent provided in Section 4.3 for Environmental Defects or Assets retained by Sellers pursuant to Section 4.3;

(f) Reduced to the extent provided in Section 3.5 in connection with a casualty loss or governmental taking;

(g) To the extent the proceeds from the sale thereof have not been received by Sellers, increased by the value of the amount of any and all Hydrocarbons stored in tanks above the load level and gaseous Hydrocarbons that have passed through the delivery point sales meters to Energy Transfer Company or any other third party buyer on the pipelines through which they are gathered or, if not first gathered, transported and attributable to the ownership and operation of the Assets that belong to Sellers as of the Effective Time (which value shall be computed by Sellers at the applicable third-party contract prices for the month of January 2017 for such stored Hydrocarbons);

(h) (i) Reduced by the product obtained by multiplying the aggregate amount of Unscheduled (Negative) Imbalances by $2.50 per mcf; and (ii) increased by the product obtained by multiplying the aggregate amount of Unscheduled (Positive) Imbalances by $2.50 per mcf;



(i) Reduced by the Deposit (as described in Section 2.4 below);

(j) Reduced by an amount equal to all Suspended Funds; and

(k) Each adjustment made pursuant to Section 2.2(a) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable to the Oil and Gas Properties during the Adjustment Period, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and as such, Purchaser shall not have any separate rights to receive any Hydrocarbon production or income, proceeds, receipts and credits with respect to which an adjustment has been made. Similarly, the adjustment described in Section 2.2(d)

11

shall serve to satisfy, up to the amount of the adjustment, Purchaser’s obligation under Section 1.4 to pay Property Costs and other costs attributable to the ownership and operation of the Assets which are incurred during the Adjustment Period.

## Section 2.3. Allocation of Purchase Price.

The values assigned to the Assets are set forth on Schedule 2.3 (the “Allocated Values”). Purchaser shall be responsible for assigning the Allocated Values included on Schedule 2.3, subject to each Seller’s right to review the Allocated Values for reasonableness.

## Section 2.4. Deposit.

(a) A deposit in the amount of $32,500,000 (the “Deposit”) shall be paid on or before one Business Day after execution of this Agreement by Purchaser, by wire transfer in immediately available funds, to the Escrow Agent to be held pursuant to the terms and conditions of the Escrow Agreement. The Deposit shall be credited to the Purchase Price to be paid by Purchaser at the Closing.

(b) In the event the transaction contemplated hereby is not consummated in accordance with the terms hereof on or before the Closing Date solely because of: (i) the failure of Purchaser to materially perform any of its obligations hereunder, or (ii) the failure of any of Purchaser's representations or warranties hereunder to be true and correct in all material respects (without regard to materiality qualifiers) as of the date of this Agreement and as of the Closing, then Sellers shall have the right to terminate this Agreement and receive the Deposit (A) as liquidated damages and not as a penalty, (B) as their sole and exclusive remedy for Purchaser's breach of this Agreement and (C) free of any claims by Purchaser thereto. The Parties agree that the damages set forth in this Section 2.4(b) will be deemed liquidated damages and that the amount of liquidated damages is reasonable considering all of the circumstances existing as of the date hereof and constitute the Parties' good faith estimate of the actual damages reasonably expected to result from Purchaser's failure to tender performance on the Closing Date. Purchaser shall execute Joint Instructions (as defined in the Escrow Agreement) consistent with the foregoing and deliver them to the Escrow Agent.

(c) Subject to Section 2.4(e), if this Agreement is terminated by the mutual written agreement of the Parties, or if the Closing does not occur on or before the Closing Date for any reason other than as set forth in Section 2.4(b), then Purchaser shall be entitled to the delivery of the Deposit, free of any claims by Sellers with respect thereto. Seller Representative shall execute Joint Instructions consistent with the foregoing and deliver them to the Escrow Agent.

(d) In the event of any termination of this Agreement, the Parties shall have the rights and obligations set forth in Section 10.2.

(e) Notwithstanding anything in this Agreement to the contrary, if Purchaser fails to deliver the Deposit to the Escrow Agent within one Business Day following the execution of this Agreement, Sellers shall be entitled to immediately terminate this Agreement.

## Section 2.5. Tax Allocation.

For purposes of Section 1060 of the Code and the Treasury Regulations promulgated thereunder (and any similar provision of state, local or foreign law, as appropriate), the amounts paid hereunder shall be allocated among the Assets consistently with the Allocated Values and in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder (the "Tax Allocation"). Promptly following the determination of the Allocated Values, Purchaser shall provide Sellers with a draft of the Tax Allocation, including a draft of IRS Form 8594, and Sellers shall provide any comments within 30 days of receipt of such drafts, after which Purchaser shall adjust the Tax Allocation as needed to reflect any reasonable comments. If the Purchase Price is adjusted pursuant to this Agreement, the Tax Allocation shall be adjusted in a manner consistent with the procedures set forth in this Section 2.5 by Purchaser. Purchaser and Sellers shall file all Tax Returns (including, but not limited to, Internal Revenue Service Form 8594) consistent with the Tax Allocation. None of Purchaser, Sellers, or their respective Affiliates shall take any Tax position inconsistent with such Tax Allocation and none of Purchaser, Sellers, or their respective Affiliates shall agree to any proposed adjustment to the Tax Allocation by any Taxing authority without first giving the other Party prior written notice and a reasonable time to respond; provided, however, that nothing contained herein shall prevent Purchaser or Sellers from settling any proposed deficiency or adjustment by any Taxing authority based upon or arising out of the Tax Allocation, and neither Purchaser nor Sellers shall be required to litigate before any court any proposed deficiency or adjustment by any taxing authority challenging such Tax Allocation.

## ARTICLE 3.
TITLE MATTERS

## Section 3.1. Sellers' Title.

(a) Except for the special warranty of title contained in each Conveyance, SELLERS MAKE NO WARRANTY OR REPRESENTATION,



EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, WITH RESPECT TO SELLERS' TITLE TO ANY OF THE ASSETS AND PURCHASER HEREBY ACKNOWLEDGES AND AGREES THAT PURCHASER'S SOLE REMEDY FOR ANY DEFECT OF TITLE, INCLUDING ANY TITLE DEFECT, WITH RESPECT TO ANY OF THE ASSETS SHALL BE PURSUANT TO THE PROCEDURES SET FORTH IN THIS ARTICLE 3 AND UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE.

(b) Sellers shall convey the Assets to Purchaser pursuant to the execution and delivery by Sellers to Purchaser, at the Closing, of an Assignment, Bill of Sale, and Conveyance (Oil and Gas Assets) (the "Oil and Gas Conveyance") and an Assignment, Bill of Sale, and Conveyance (Midstream Assets) (the "Midstream Conveyance") substantially in the forms attached hereto as, respectively, Exhibit B-1 and Exhibit B-2 (each a "Conveyance" and, collectively, the "Conveyances"). Each Conveyance will contain a limited warranty of title as set forth therein with respect to the portion of the Assets covered thereby, subject, however, to the Permitted Encumbrances, and will grant to Purchaser full rights of substitution

and subrogation in and to all rights and actions of warranty of title which each Seller has or may have against all preceding owners and vendors relating to the relevant Assets.

## Section 3.2. Definitions of Title Matters.

As used in this Agreement, the term “Defensible Title” means that title of Sellers with respect to the Units, Wells or other Assets, except for and subject to Permitted Encumbrances that as of the Effective Time and the Closing which:

(a) Entities Sellers to receive an interest (expressed as a percentage or decimal fraction) of the Hydrocarbons produced, saved and marketed from any Unit, Well or other Asset shown in Exhibit A-1 (after satisfaction of all royalties, overriding royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “Net Revenue Interest”), of not less than the Net Revenue Interest shown in Exhibit A-1 for such Unit, Well or other Asset (but limited to the applicable Target Interval set forth in Exhibit A-1 for such Unit, Well or other Asset and any currently producing formation (for such Unit or Well)), except (solely to the extent that such actions do not cause a breach of Sellers’ covenants under Section 7.6(a)) for decreases resulting from the establishment or amendment from and after the date hereof of pools or Units, and except as stated in such Exhibit A-1;

(b) Obligates Sellers to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, any Unit, Well or other Asset shown in Exhibit A-1 (including the formation(s) set forth on Exhibit A-1 for such Unit, Well or other Asset) not greater than the “working interest” percentage shown in Exhibit A-1 for such Unit, Well or other Asset, without increase throughout the period when such Unit, Well or other Asset is producing (but limited to the applicable Target Interval set forth in Exhibit A-1 for such Unit, Well or other Asset and any currently producing formation (for such Unit or Well)), except as stated in Exhibit A-1 and except for increases from and after the date hereof resulting from contribution requirements with respect to non-consenting or defaulting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in such Seller’s Net Revenue Interest;

(c) Is free and clear of liens, encumbrances, obligations, security interests, irregularities, pledges, or other defects; and

(d) With respect to the Leases, has not been the subject of any demand letters or other written notice letters from any lessor of any Lease to any Seller or, to Sellers’ knowledge, any third party operator of such Lease alleging or otherwise indicating that such Lease and the acreage subject thereto no longer contains a well producing in paying quantities or is no longer held by production pursuant to the terms of such Lease.

As used in this Agreement, the term “Title Defect” means any of the following: any lien, charge, encumbrance, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or working interest) that causes the applicable Seller not to have Defensible Title. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i) defects based solely on lack of information in such Seller’s files unless information in the records of the applicable county reflect that any information in Seller’s files is incorrect;

(ii) defects arising out of lack of corporate or similar entity authorization unless Purchaser provides affirmative written evidence that causes Purchaser to reasonably believe that the action was not authorized and results in another Person’s superior claim of title;

(iii) defects based on a gap in Sellers’ chain of title in the state’s records as to state Leases, or in the county records as to other Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in a Title Defect Notice;

(iv) defects based on failure to record any Lease issued by any state or federal Governmental Body, or any assignments of such Lease, (in each case) in the real property, conveyance or other records of the county in which such Lease is located;

(v) defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(vi) defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Purchaser provides affirmative evidence that causes Purchaser to reasonably believe that such failure or omission has resulted in another Person’s superior claim of title;

(vii) defects that have been cured by applicable Laws of limitation or prescription; and



(viii) defects based solely on claims that a Well was drilled pursuant to an “allocation well” permit or the failure to obtain a production sharing agreement, as allowed by the Railroad Commission of Texas, so long as each holder of a Lease or leasehold tract that such Well crosses has agreed in writing to its share of Hydrocarbons produced from such Well.

As used in this Agreement, the term “Title Benefit” shall mean any right, circumstance or condition that operates to increase the Net Revenue Interest of Sellers in any Unit, Well or other Asset shown on Exhibit A-1, without causing a greater than proportionate increase in Sellers’ working interest above that shown in Exhibit A-1 as of the Effective Time.

## Section 3.3. Definition of Permitted Encumbrances.

As used herein, the term “Permitted Encumbrances” means any or all of the following:

(a) Royalties and any overriding royalties, reversionary interests, net profit interests, production payments, carried interests, and other burdens on production, to the extent that any such burden does not reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers’ working interest above that shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest;

(b) All Leases, unit agreements, pooling agreements, operating agreements, Hydrocarbon production sales contracts, division orders and other contracts, agreements and instruments applicable to or affecting the Assets, to the extent that they do not, individually or in the aggregate, (i) reduce Sellers' Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers' working interest above that shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest or (ii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(c) Preference Rights applicable to this or any future transaction and set forth on Schedule 5.13;

(d) Transfer Requirements applicable to this or any future transaction and set forth on Schedule 5.13;

(e) Liens for Taxes not yet due and payable;

(f) Any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing oil, gas or other Hydrocarbons therefrom or therein and (ii) materialman's, mechanics', repairman's, employees', contractors', operators' or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business to construction, maintenance, development, production or operation of the Assets or the production or processing of oil, gas or other Hydrocarbons therefrom, (in each case) that are not delinquent (including any amounts being withheld as provided by Law) and that will be paid by Sellers in the ordinary course of business;

(g) All rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or interests therein pursuant to this or to any future transaction if they are not required and are not customarily obtained prior to such a sale or conveyance;

(h) To the extent set forth in the applicable Lease, rights of notice or reassignment (or granting an opportunity to receive a reassignment) of a leasehold interest to the holders of such reassignment rights prior to surrendering or releasing such leasehold interest;

(i) Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, to the extent that they do not (i) reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 or increase Sellers’ working interest above that

shown in Exhibit A-1 without a proportionate increase in the corresponding Net Revenue Interest or (ii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(j) Calls on Hydrocarbon production under existing Contracts that are listed on Schedule 1.2(a)(iv);

(k) All rights reserved to or vested in any Governmental Body to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable Laws or under any franchise, grant, license or permit issued by any such Governmental Body;

(I) Imbalances associated with the Assets; and

(m) Liens granted under applicable joint operating agreements and other similar agreements listed on Schedule 1.2(a)(iv) for amounts that are not delinquent.

## Section 3.4. Notice of Title Defect Adjustments.

(a) To assert a claim of a Title Defect prior to Closing, Purchaser must deliver claim notices to Sellers (each a “Title Defect Notice”) on or



before March 3, 2017 at 5:00 p.m. C.S.T. (the “Title Claim Date”); provided, however, that Purchaser agrees that it shall furnish Sellers once at the end of every two week period until the Title Claim Date with a preliminary Title Defect Notice if any officer of Purchaser or its Affiliates discovers or learns of any Title Defect during such two week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Title Claim Date; provided further that failure to provide preliminary notice of a Title Defect shall not prejudice Purchaser’s right to assert any Title Defect hereunder on or before the Title Claim Date. To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s), (ii) Leases, Units, Wells or other Assets in Exhibit A or Exhibit A-1, as applicable, affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for Sellers to verify the existence of and extent of such Title Defect and the amount by which the Allocated Value of each affected Asset is increased by such Title Defect, provided, however, that the sufficiency or volume of documents delivered pursuant to this Section 3.4(a)(iv) shall not serve as any basis to dispute the validity of the Title Defect Notice, and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. EXCEPT FOR PURCHASER’S RIGHTS UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ITS RIGHT TO ASSERT TITLE DEFECTS OF WHICH EACH SELLER HAS NOT BEEN GIVEN NOTICE ON OR BEFORE THE TITLE CLAIM DATE.

(b) Sellers shall have the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date, with respect to each Title Benefit, a notice (a “Title Benefit

Notice”), which notice to be effective shall include (i) a description of the alleged Title Benefit, (ii) the Leases, Units, Wells or other Assets in Exhibit A or Exhibit A-1, as applicable, affected by such Title Benefit, (iii) the Allocated Value of each Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, subject to such Title Benefit, (iv) supporting documents reasonably necessary for Purchaser to verify the existence of and extent of such Title Benefit and the amount by which the Allocated Value of each affected Asset is increased by such Title Benefit, provided, however, that the sufficiency or volume of documents delivered pursuant to this Section 3.4(b)(iv) shall not serve as any basis to dispute the validity of the Title Benefit Notice, and (v) the amount by which Sellers reasonably believe the Allocated Value of each affected Asset is increased by such Title Benefit and the computations and information upon which Sellers’ belief is based.

(c) Sellers shall have the right, but not the obligation, to attempt, at their sole cost, to cure or remove Title Defects at any time prior to Closing (the “Cure Period”), unless the Parties otherwise agree, any Title Defects of which Sellers have been advised in writing by Purchaser. Any asserted Title Defects which are cured within the Cure Period or waived in writing by Purchaser shall be deemed Permitted Encumbrances hereunder.

(d) Remedies for Title Defects.

In the event that any Title Defect is not waived by Purchaser in writing or cured on or before Closing, the Parties shall mutually agree upon one of the following remedies for such Title Defect:

(i) subject to the Individual Title Threshold and the Aggregate Defect Deductible, have the Purchase Price reduced by an amount agreed upon (“Title Defect Amount”) pursuant to Section 3.4(g) by Purchaser and Sellers as being the value of such Title Defect, taking into consideration the Allocated Value of the Property affected by such Title Defect, the portion of the Property affected by such Title Defect and the legal effect of such Title Defect on the Property affected thereby; provided, however, that the methodology, terms and conditions of Section 3.4(g) shall control any such determination;

(ii) have Sellers indemnify Purchaser against all liability, loss, cost and expense resulting from such Title Defect pursuant to an indemnity agreement (the “Indemnity Agreement”) in the form attached hereto as Exhibit C; or

(iii) have Sellers retain the entirety of the Property that is affected by such Title Defect, together with all Assets solely related to such Property, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property and related Assets. Thereafter, Sellers shall have 120 days after Closing in which to cure the Title Defect with respect to such retained Property and related Assets. Any Property and related Assets so held back from the initial Closing and retained by Sellers will be conveyed to Purchaser (subject to the satisfaction of the conditions set forth in Section 8.2 with respect to such Property and related Assets) at a delayed Closing (which shall become the new Closing Date with respect to such Property and related

Assets) 10 Business Days following the date that the Title Defect is cured, at which time Purchaser shall pay to Sellers the full Allocated Value of the Property and related Assets (as adjusted pursuant to Section 2.2 through the new Closing Date therefor), and provided further that if multiple delayed Closings are contemplated as a result of this provision and/or Section 7.7(c), the delayed Closings may be consolidated on dates mutually agreeable to the Parties. An election to delay the Closing with respect to certain Assets pursuant to this Section 3.4(d)(iii) shall not waive Sellers' right to dispute the existence of a Title Defect or to contest the Title Defect Amount asserted with respect thereto. In the event that Sellers are unable to cure the Title Defect with respect to any Property and related Assets held back at the initial Closing within 120 days of the initial Closing, then Sellers shall retain the Property and related Assets affected thereby, such Property and related Assets shall become Excluded Assets hereunder and Purchaser shall have no further obligation to purchase such Property and related Assets. Any disputes regarding whether such Title Defect has been cured by Sellers within such 120 day cure period shall be resolved pursuant to Section 3.4(k) (provided that the Title Expert shall be selected within 15 Business Days following the end of the 120 day cure period with respect to such dispute and all other provisions of Section 3.4(k) shall apply as written).

In the event Sellers and Purchaser are unable to mutually agree upon a remedy for any asserted Title Defect prior to Closing, then Sellers and Purchaser shall be deemed to have selected the remedy set forth in Section 3.4(d)(i). In the event Sellers and Purchaser mutually agree to select the remedy set forth in Section 3.4(d)(i) (or are deemed to have selected such remedy in accordance with the foregoing sentence) but are unable to agree on the Title Defect



Amount by the Scheduled Closing Date, then unless the Parties otherwise mutually agree in writing the dispute shall be resolved pursuant to the provisions of Section 3.4(k).

(e) Subject to the Individual Title Benefit Threshold and the Aggregate Benefit Deductible, with respect to each Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, affected by Title Benefits reported under Section 3.4(b), the Purchase Price shall be increased by an amount (the "Title Benefit Amount") equal to the increase in the Allocated Value for such Lease, Unit, Well or other Asset in Exhibit A or Exhibit A-1, as applicable, caused by such Title Benefits, as determined pursuant to Section 3.4(j). In the event that Purchaser and Sellers are unable to agree on the Title Benefit Amount, the affected Assets will nevertheless be conveyed to Purchaser at Closing with no increase to the Purchase Price for such Title Benefit, subject to Sellers' right to a subsequent adjustment in the Purchase Price for such Title Benefit as may result under the provisions of Section 3.4(k), or as may otherwise be agreed to by the Parties.

(f) Section 3.4(d) shall be the exclusive right and remedy of Purchaser with respect to Title Defects asserted by Purchaser pursuant to Section 3.4(a). Section 3.4(e) shall be the exclusive right and remedy of Sellers with respect to Title Benefits asserted by Sellers pursuant to Section 3.4(b).

(g) The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property (determined in accordance with

Schedule 2.3) is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i) if Purchaser and Sellers agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii) if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect affecting the Title Defect Property;

(iii) if the Title Defect results from a Seller having a lesser Net Revenue Interest in such Title Defect Property than the Net Revenue Interest specified therefor in Exhibit A-1 and there is a proportional decrease in the working interest for the affected Title Defect Property the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Title Defect Property (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the reduction in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Title Defect Property in Exhibit A-1;

(iv) if the Title Defect results from a Seller owning fewer Net Mineral Acres in such Title Defect Property than the Net Mineral Acres specified therefor in Exhibit A, the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Title Defect Property (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the reduction in Net Mineral Acres and the denominator of which is the number of Net Mineral Acres specified for such Title Defect Property in Exhibit A;

(v) if the Title Defect results from any matter not described in subsections (i), (ii), (iii) or (iv) above, the Title Defect Amount shall be an amount equal to the difference between the value of the Title Defect Property affected by such Title Defect with such Title Defect and the value of such Title Defect Property without such Title Defect (taking into account the portion of the Purchase Price allocated in accordance with Schedule 2.3 to such Title Defect Property and the cost to cure such Title Defect if such Title Defect is reasonably susceptible of being cured);

(vi) if a Title Defect is not effective or does not affect a Title Defect Property throughout the entire remaining productive life of such Title Defect Property, such fact shall be taken into account in determining the Title Defect Amount; and

(vii) notwithstanding anything to the contrary in this Article 3, the aggregate Title Defect Amounts attributable to the effects of all Title Defects

upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(h) The Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder. For example, if a lien affects more than one Title Defect Property or the curative work with respect to one Title Defect results (or is reasonably expected to result) in the curing of any other Title Defect affecting the same or another Title Defect Property, the amount necessary to discharge such lien or the cost and expense of such curative work shall be allocated among the Title Defect Properties so affected (in the ratios of the respective portions of the Purchase Price allocated to such Title Defect Properties) and the amount so allocated to a Title Defect Property shall be included only once in the Title Defect Amount.

(i) No Title Defect Amount shall be allowed on account of and to the extent that an increase in a Seller’s working interest in a Property has the effect of proportionately increasing such Seller’s Net Revenue Interest in such Property;

(j) The Title Benefit Amount for any Title Benefit shall mean, with respect to an affected Lease, Unit, Well or other Asset, the amount by which the value of the affected Lease, Unit, Well or other Asset is enhanced by virtue of such Title Benefit, which amount shall be determined as follows:

(i) If Purchaser and Sellers agree on the Title Benefit Amount, that agreed amount shall be the Title Benefit Amount.



(ii) If the Title Benefit Amount results from a Seller having a greater Net Revenue Interest in such Unit, Well or other Asset than the Net Revenue Interest specified therefor in Exhibit A-1 with a proportional increase in the working interest of the affected Unit, Well or other Asset, the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Unit, Well or other Asset (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the increase in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Unit, Well or other Asset in Exhibit A-1.

(iii) if the Title Benefit results from a Seller owning greater Net Mineral Acres in such Lease than the Net Mineral Acres specified therefor in Exhibit A, the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Lease (determined in accordance with Schedule 2.3) by a fraction, the numerator of which is the increase in Net Mineral Acres and the denominator of which is the number of Net Mineral Acres specified for such Title Defect Property in Exhibit A;

(iv) If the Title Benefit results from any matter not described in subsections (i), (ii) or (iii) above, the Title Benefit Amount shall be an amount equal to the difference between the value of the Property affected by such Title Benefit and the value of such Property without such Title

Benefit (taking into account the portion of the Purchase Price allocated to such Property in accordance with Schedule 2.3).

(v) In determining the amount of Title Benefit Amounts, the principles and methodology set forth in Section 3.4(g) shall generally be applied, mutatis mutandis.

(k) Sellers and Purchaser shall attempt in good faith to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to the Scheduled Closing Date. If Seller and Purchaser are unable to agree by the Scheduled Closing Date, the Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k); in addition, should the Parties dispute whether or not any Title Defect has been cured by Sellers, such dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k), in each case as follows:

(i) There shall be a single arbitrator, who shall be a title attorney with at least 10 years' experience in oil and gas titles involving properties in the regional area in which the relevant Oil and Gas Properties are located and who shall not have performed professional services for either Party or any of their respective Affiliates during the previous three years, as selected by mutual agreement of Purchaser and Sellers within 15 Business Days after the Applicable Date (and absent such agreement, by the Houston office of the American Arbitration Association) (the "Title Expert"). Within 10 Business Days following the selection of the Title Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Title Expert written explanations of their respective positions in the disputed title matters. The Title Expert's determination shall be made within 15 Business Days after submission of the title matters in dispute and shall be final and binding upon the Parties, without right of appeal. In making his determination, the Title Expert shall be bound by the provisions of this Article 3, and may consider such other matters as in the opinion of the Title Expert are necessary or helpful to make a proper determination. The Title Expert may allow the Parties to make written submissions of their positions in the manner and to the extent the Title Expert deems appropriate, and the Title Expert may call on the Parties to submit such other materials as the Title Expert deems helpful and appropriate to resolution of the dispute. Additionally, the Title Expert may consult with and engage disinterested third parties to advise the Title Expert, including without limitation petroleum engineers. The Title Expert shall act as an expert for the limited purpose of determining the specific disputed title matters submitted by either Party and may not award damages, interest or penalties to any Party with respect to any matter. Any determination by the Title Expert of an amount in dispute must be the amount proposed either by Sellers or by Purchaser, or be a compromise between the two proposed amounts. Sellers and Purchaser shall each bear their own legal fees and other costs of presenting its case. The costs and expenses of the Title Expert shall be borne and paid one-half by Sellers and

one-half by Purchaser, including any costs incurred by the Title Expert that are attributable to such third party consultation.

(ii) If the Title Defect Amounts alleged by Purchaser that are applicable to the disputed title matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Environmental Defect Amounts alleged by Purchaser pursuant to Section 4.3) that are not resolved prior to the Scheduled Closing Date, exceed 20% of the Purchase Price, then the date for Closing shall be extended until the disputed title matters are resolved pursuant to Section 3.4(k)(i). Upon resolution of such disputed title matters pursuant to Section 3.4(k)(i), then, subject to the other terms and conditions of this Agreement, the Closing shall occur on the 10th Business Day following the date upon which the Title Expert delivers written notice to Purchaser and Sellers of his determination with respect to any disputed title matters, including any applicable Title Defect Amount or a Title Benefit Amount.

(iii) If the Title Defect Amounts alleged by Purchaser that are applicable to the disputed title matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Environmental Defect Amounts alleged by Purchaser pursuant to Section 4.3), are equal to or less than 20% of the Purchase Price, then the affected Assets will nevertheless be conveyed to Purchaser at Closing with no reduction in the Purchase Price for any such Title Defect and a portion of the Purchase Price equal to the disputed Title Defect Amount alleged by Purchaser shall be placed in escrow by Purchaser pursuant to an escrow agreement in a form to be mutually agreed upon by Seller Representative, Purchaser and JP Morgan Chase Bank, NA as escrow agent. The Purchase Price shall be subject to a subsequent adjustment for any such Title Defect upon the resolution of such disputed title matters pursuant to Section 3.4(k)(i) or as may be otherwise be mutually agreed by the Parties. Upon such resolution of such disputed title matters pursuant to Section 3.4(k)(i), then (A) Purchaser and Seller Representative shall instruct



escrow agent to deliver to Sellers the amount, if any, so awarded by the Title Expert to Sellers, plus interest accrued on such amount pursuant to the terms of the Escrow Agreement, if any, and (B) Purchaser and Seller Representative shall instruct escrow agent to pay to Purchaser the amount, if any, so awarded by the Title Expert to Purchaser, plus interest accrued on such amount pursuant to the terms of the escrow agreement, if any.

(iv) If any title disputed matter under this Article 3 relates to whether or not any Title Defect has been cured post-Closing pursuant to Section 3.4(d)(iii), then such title disputed matter shall be resolved pursuant to the determination of the Title Expert pursuant to Section 3.4(k)(i).

(1) Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any individual uncured Title Defect affecting a Title Defect Property for which the Title Defect Amount therefor does not exceed $75,000 (“Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for uncured Title Defects unless the aggregate Title Defect Amounts attributable to all uncured Title Defects, taken together with the aggregate Environmental Defect Amounts attributable to all uncured Environmental Defects, exceeds a deductible in an amount equal to 1.25% of the unadjusted Purchase Price (“Aggregate Defect Deductible”), after which point adjustments to the Purchase Price or other remedies shall be made available to Purchaser only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible.

(m) Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual Title Benefit for a Property for which the Title Benefit Amount therefor does not exceed $75,000 (“Individual Title Benefit Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price for Title Benefits unless the aggregate Title Benefits attributable to all Title Benefits exceeds a deductible in an amount equal to 1.25% of the unadjusted Purchase Price (“Aggregate Benefit Deductible”), after which point adjustments to the Purchase Price shall be made available to Sellers only with respect to Title Benefits where the aggregate Title Benefit Amounts are in excess of such Aggregate Benefit Deductible; for the avoidance of doubt, Title Benefit Amounts which do not meet the Individual Title Benefit Threshold shall not be included in reaching the Aggregate Benefit Deductible.

(n) If the aggregate upward adjustment (if any) of the Purchase Price which will result from adjustments related to Title Benefit Amounts pursuant to this Section 3.4 (net of any downward adjustments for any Title Defects) exceeds 5% of the Purchase Price (the “Maximum Upward Adjustment”), Purchaser may elect, in its sole discretion, to deem one or more Assets subject to a Title Benefit to be Excluded Assets for purposes of this Agreement, such that the upward adjustment of the Purchase Price due to Title Benefit Amounts is less than the Maximum Upward Adjustment.

## Section 3.5. Casualty or Condemnation Loss.

(a) From and after the Effective Time, but subject to the provisions of Section 3.5(b), Purchaser shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including but not limited to the watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

(b) If, prior to the Closing Date, all or a material part of any of the Assets are damaged or destroyed by fire, flood, storm or other casualty or are taken in condemnation or under the right of eminent domain, or if proceedings for such purposes shall be pending or

threatened, Sellers shall promptly notify Purchaser in writing of the nature and extent of such casualty loss or government taking and Sellers' estimate of the cost required to repair or replace that portion of the Assets affected by the casualty loss or value of the Assets taken or threatened to be taken by the government. If all or any portion of the Assets are affected by a casualty loss or government taking, the Purchase Price will be adjusted downward by the agreed cost required to repair or replace that portion of the Assets affected by the casualty loss or the agreed value of the Assets taken or threatened to be taken by the government, and the Parties will proceed with Closing, subject to the other terms and conditions of this Agreement; provided that if the Parties mutually agree, in lieu of adjustments to the Purchase Price, Sellers shall (i) pay over to Purchaser: (A) all insurance proceeds payable to Sellers with respect to any such casualty loss (if applicable), (B) all sums paid to Sellers by third parties by reason of any such casualty loss (if applicable), and (C) all compensation paid to Sellers with respect to any such government taking (if applicable), and (ii) assign to Purchaser any and all claims that Seller may have against any third party with respect to such casualty loss or government taking, as applicable.

## Section 3.6. Limitations on Applicability.

The right of Purchaser to assert a Title Defect under this Agreement and Sellers’ rights to assert a Title Benefit under this Agreement shall terminate as of the Title Claim Date, provided there shall be no termination of Purchaser’s or Sellers’ rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit Claim properly reported in a Title Benefit Notice on or before the Title Claim Date.

## Section 3.7. Government Approvals Respecting Assets.

(a) Federal and State Approvals. Purchaser shall, within 30 days after Closing and at Purchaser's own expense, file for approval with the applicable Governmental Bodies all assignment documents and other state and federal transfer documents required to effectuate the transfer of the Assets representing state or federal Leases or other Lands. Purchaser further agrees, promptly after Closing, to take all other actions reasonably required of Purchaser by federal or state agencies having jurisdiction to obtain all requisite regulatory approvals with respect to this transaction with respect to Assets representing state or federal Leases or other Lands, and to use its commercially reasonable efforts to obtain such approval by such federal or state agencies, as applicable, of Sellers' assignment documents requiring such federal or state approval in order for Purchaser to be recognized by the federal or state agencies as the owner of the Assets representing state or federal Leases or other Lands. Purchaser shall provide each Seller with approved copies of such



assignment documents and other state and federal transfer documents, as soon as they are available.

(b) Title Pending Governmental Approvals. Until all of the governmental approvals provided for in Section 3.7(a) have been obtained, the following shall occur with respect to the affected portion of the Assets representing state or federal Leases or other Lands:

(i) Sellers shall continue to hold record title to the affected Leases and other affected portion of the Assets as nominee for Purchaser, and Purchaser shall be entitled to all economic benefits of ownership of the affected Assets;

(ii) Purchaser shall be responsible for all Assumed Seller Obligations with respect to the affected Leases and other affected portion of the Assets as if Purchaser was the record owner of such Leases and other portion of the Assets as of the Effective Time;

(iii) Sellers shall act as Purchaser’s nominee but shall be authorized to act only upon and in accordance with Purchaser’s instructions, and Sellers shall have no authority, responsibility or discretion to perform any tasks or functions with respect to the affected Leases and other affected portion of the Assets other than those which are purely administrative or ministerial in nature, unless otherwise specifically requested and authorized by Purchaser in writing;

(iv) Sellers shall not be obligated to incur any expenses in Sellers' capacity as nominee for the benefit of Purchaser under this Section 3.7(b), and, provided that Sellers give Purchaser prior written notice of any expenses that Sellers are required to incur to comply with their obligations under the applicable Leases or applicable Law, Purchaser agrees to pay or reimburse Sellers for any such expenses promptly upon receiving notice thereof; and

(v) For purposes of Article 11, Sellers and Purchaser shall treat and deal with such affected Leases and other affected portions of the Assets as if full legal and equitable title to the same had passed from Sellers to Purchaser at Closing.

## ARTICLE 4.
ENVIRONMENTAL MATTERS

## Section 4.1. Assessment.

From and after the date of execution of this Agreement until the Closing Date, each Seller shall afford to Purchaser and Purchaser's Representatives access to the Assets, including the Records in accordance with Section 7.1. Upon reasonable notice to Sellers, Purchaser shall be entitled to conduct a Phase I environmental property assessment of the Assets that satisfies the basic assessment requirements set forth under the current American Society for Testing and Material Standard Practice for Phase I environmental property assessments (Designation E1527-13) but such Phase I environmental property assessment shall not include any environmental sampling or testing (the "Phase I Assessment" or "Phase I, " whether one or more). The Phase I Assessment and Purchaser's other diligence activities shall be conducted at the sole cost, risk and expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4. Each Seller or its respective designee shall have the right to accompany Purchaser and Purchaser's Representatives whenever they are onsite on Assets. Notwithstanding anything herein to the contrary, Purchaser shall not have access to, and shall not be permitted to conduct any environmental due diligence (including all or any part of the Phase I Assessments) with respect to any Assets where Sellers or their Affiliates do not have the authority to grant access for such due diligence; provided, however, Sellers and their Affiliates shall use their commercially reasonable efforts to obtain permission from any other Person to allow Purchaser and Purchaser's Representatives such access and the ability to conduct environmental due diligence.

in accordance herewith and as long as Sellers and their Affiliates have exercised such commercially reasonable efforts, Sellers shall have no liability to Purchaser for failure to obtain any such other Person's permission. Notwithstanding anything herein to the contrary, Purchaser shall not have the right to conduct any Phase II environmental property assessments or such other activities intended to constitute the conduct of "all appropriate inquiries" under 40 CFR Part 312 without the prior written consent of Sellers; provided, however, that if any Seller fails to provide such written consent, then Purchaser shall have the option to (a) withdraw its request to perform such Phase II assessment or (b) cause Sellers to retain the affected Asset, in which event such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset. Purchaser and Sellers shall maintain, and shall cause their respective officers, employees, representatives, consultants and advisors to maintain, all information obtained by Purchaser pursuant to any Phase I or other due diligence activity as strictly confidential until the Closing occurs (and thereafter, with respect to Sellers if Closing occurs), unless disclosure of any facts discovered through such Phase I or other due diligence activity is required under any Laws. Purchaser shall provide each Seller with a copy of the final version of all environmental reports prepared by, or on behalf of, Purchaser with respect to any Phase I activity conducted on the Oil and Gas Properties. In the event that any necessary disclosures under applicable Laws are required before Closing with respect to matters discovered by any Phase I activity conducted by, for or on behalf of Purchaser, Purchaser agrees that Sellers shall be the responsible Parties for disclosing such matters to the appropriate Governmental Bodies; provided that, if Sellers fail to promptly make such disclosure and Purchaser or any of its Affiliates is legally obligated to make such disclosure, Purchaser or any such Affiliate shall have the right to fully comply with such legal obligation.

## Section 4.2. NORM, Wastes and Other Substances.

Purchaser acknowledges that the Assets have been used for the exploration, development, and production of Hydrocarbons and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Oil and Gas Properties or associated with the Assets. Equipment and sites included in the Assets may contain Hazardous Materials, including NORM. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on, in or under the Oil and Gas Properties or included in the Assets may contain Hazardous Materials, including NORM. Hazardous Materials, including NORM, may have come in contact with various environmental media, including without limitation, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media and Hazardous Materials, including NORM, from the Assets.



(a) If, as a result of its investigation pursuant to Section 4.1, Purchaser determines that with respect to the Assets, there exists an Environmental Liability with respect to any Asset (other than with respect to NORM) (in each case an “Environmental Defect”), then on or prior to March 3, 2017 at 5:00 p.m. C.S.T. (the “Environmental Claim Date”), Purchaser may notify each Seller in writing of such Environmental Defect (an “Environmental Defect Notice”). EXCEPT WITH RESPECT TO PURCHASER’S RIGHTS FOR ANY

BREACH BY SELLERS OF THEIR REPRESENTATIONS SET FORTH IN SECTION 5.9 OR ANY BREACH BY SELLERS OF THEIR COVENANTS HEREUNDER, FOR ALL PURPOSES OF THIS AGREEMENT, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ANY ENVIRONMENTAL DEFECT WHICH PURCHASER FAILS TO ASSERT AS AN ENVIRONMENTAL DEFECT BY AN ENVIRONMENTAL DEFECT NOTICE RECEIVED BY EACH SELLER ON OR BEFORE THE ENVIRONMENTAL CLAIM DATE. To be effective, each such notice must set forth (i) a description of the matter constituting the alleged Environmental Defect, (ii) the Units, Wells and associated Assets affected by the Environmental Defect, (iii) the estimated Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”) and (iv) supporting documents reasonably necessary for Sellers to verify the existence of the alleged Environmental Defect and the Environmental Defect Amount, provided, however, that the sufficiency or volume of documents delivered pursuant to this Section 4.3(a)(iv) shall not serve as any basis to dispute the validity of the Environmental Defect Notice. Purchaser agrees that it shall furnish Sellers once at the end of every two week period until the Environmental Claim Date with a preliminary Environmental Defect Notice if any officer of Purchaser or any of its Affiliates discovers or learns of any Environmental Defect during such two week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Environmental Claim Date; provided further that failure to provide preliminary notice of an Environmental Defect shall not prejudice Purchaser’s right to assert any Environmental Defect hereunder on or before the Environmental Claim Date.

(b) Sellers shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the Parties shall have mutually agreed to the general plan of remediation with respect to such Environmental Defect and the time period by which such remediation shall take place, after Closing. If Sellers disagree with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the Environmental Defect Amount or the cure thereof prior to the Scheduled Closing Date, Purchaser and Sellers will attempt to resolve the dispute prior to the Scheduled Closing Date. If such dispute or any dispute among the Parties on whether or not any Environmental Defect has been cured by Sellers by the Scheduled Closing Date (unless the Parties have mutually agreed to allow Sellers to cure such Environmental Defect after Closing) has not been resolved by the Scheduled Closing Date, then such matters remaining in dispute shall be exclusively and finally resolved pursuant to this Section 4.3(b) as follows:

(i) The Parties shall submit such dispute to an environmental consultant approved in writing by Sellers and Purchaser (and absent such mutual approval, appointed by the Houston office of the American Arbitration Association) that is experienced in environmental corrective action at oil and gas properties in the regional area where the relevant Oil and Gas Properties are located and that shall not have performed professional services for either Party or any of their respective Affiliates during the previous three years (the “Independent Expert”). Within 10 Business Days following the selection of the Independent Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Independent Expert written explanations of their respective positions in the disputed environmental matters. The Independent

Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Sellers with exhibits, including interrogatories, supplemented with appearances by Purchaser and Sellers, if necessary, as the Independent Expert may deem necessary. After the Parties and Independent Expert have had the opportunity to review all such submissions, the Independent Expert shall call for a final, written offer of resolution from each Party. The Independent Expert shall render its decision within 15 Business Days of receiving such offers by selecting one or the other of the offers, or by crafting a decision that represents a compromise between the two offers.

(ii) If the Environmental Defect Amounts alleged by Purchaser that are applicable to the disputed environmental matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Title Defect Amounts alleged by Purchaser pursuant to Article 3) that are not resolved prior to the Scheduled Closing Date, exceed 20% of the Purchase Price, then the date for Closing shall be extended until the disputed environmental matters are resolved pursuant to Section 4.3(b)(i). Upon resolution of such disputed environmental matters pursuant to Section 4.3(b)(i), then, subject to the other terms and conditions of this Agreement, the Closing shall occur on the 10th Business Day following the date upon which the Independent Expert delivers written notice to Purchaser and Sellers of his determination with respect to any disputed environmental matters, including any applicable Environmental Defect Amount.

(iii) If the Environmental Defect Amounts alleged by Purchaser that are applicable to the disputed environmental matters that are not resolved prior to the Scheduled Closing Date, when taken together with the other adjustments to the Purchase Price described in Section 8.1(f) and Section 8.2(f) (including any Title Defect Amounts alleged by Purchaser pursuant to Article 3), are equal to or less than 20% of the Purchase Price, then the Assets affected by such Environmental Defects shall be retained by Sellers at Closing, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Assets. If the Allocated Value of an Asset so held back from the initial Closing is greater than the Environmental Defect Amount determined by the Independent Expert or agreed by the Parties, then such Asset will be conveyed to Purchaser (subject to the satisfaction of the conditions set forth in Section 8.2 with respect to such Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Asset) within 10 Business Days following the date that the Independent Expert delivers written notice to Purchaser and Sellers of his award with respect to such Environmental Defect and/or Environmental Defect Amount, at which time Purchaser shall pay to Sellers the full Allocated Value of the Asset less such Environmental Defect Amount (as adjusted pursuant to Section 2.2 through the new Closing Date therefor with respect to such Asset). If the Allocated Value of an Asset so held back from the initial Closing is less than the Environmental Defect Amount determined by the



Asset hereunder and Purchaser shall have no further obligation to purchase such Asset.

(c) The Independent Expert may not award damages, interest or penalties to either Party with respect to any matter. The decision of the Independent Expert shall be final and binding upon the Parties, without right of appeal. Sellers and Purchaser shall each bear its own legal fees and other costs of presenting its case to the Independent Expert. The costs and expenses of the Independent Expert shall be borne and paid one-half by Sellers and one-half by Purchaser.

(d) Subject to Section 4.3(b) and the following provisions of this Section 4.3(d), the Parties shall adjust the Purchase Price to reflect the Environmental Defect Amounts, as agreed by the Parties or as determined by the Independent Expert, as applicable, for all uncured Environmental Defects; provided that, notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual uncured Environmental Defect (affecting one or more Assets) for which the Environmental Defect Amounts therefor do not exceed $75,000 ("Individual Environmental Threshold"); (ii) if the Parties agree or the Independent Expert determines that the Environmental Defect Amount with respect to any Asset exceeds the Allocated Value thereof, then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, (iii) if the Environmental Defect Amounts for all Environmental Defects affecting any Asset, when combined with the Title Defect Amounts for all Title Defects affecting the same Asset, exceeds the Allocated Value of such affected Asset then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, and (iv) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental Defect Amounts attributable to all such Environmental Defects, taken together with the aggregate Title Defect Amounts attributable to all uncured Title Defects, exceed the Aggregate Defect Deductible, after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts attributable thereto are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible.

## Section 4.4. Inspection Indemnity.

PURCHASER HEREBY AGREES TO DEFEND, INDEMNIFY, RELEASE, PROTECT, SAVE AND HOLD HARMLESS THE SELLER INDEMNIFIED PERSONS FROM AND AGAINST ANY AND ALL LOSSES ARISING OUT OF, OR RELATING TO, ANY DUE DILIGENCE ACTIVITY CONDUCTED ON THE ASSETS BY PURCHASER OR ITS AGENTS OR REPRESENTATIVES, WHETHER BEFORE OR AFTER THE EXECUTION OF THIS AGREEMENT, EXCEPT TO THE EXTENT SUCH LOSSES ARE CAUSED BY THE WILLFUL OR INTENTIONAL CONDUCT OF

A SELLER OR ITS AGENTS OR REPRESENTATIVES. The indemnity obligation set forth in this Section 4.4 shall survive the Closing or termination of this Agreement.

## ARTICLE 5.
REPRESENTATIONS AND WARRANTIES OF SELLERS

## Section 5.1. Generally.

(a) Any representation or warranty qualified “to the knowledge of Sellers” or “to Sellers’ knowledge” or with any similar knowledge qualification is limited to matters within the Actual Knowledge of the officers and employees of each Seller who have direct responsibility for the Assets, as specified on Schedule 5.1. “Actual Knowledge”, for purposes of this Agreement, means information actually and personally known by the individuals specified on Schedule 5.1 after due investigation, in their individual capacities and as officers and employees of any Seller or its Affiliates. Inclusion of a matter on a Schedule to a representation or warranty which addresses matters possibly having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on such Schedule. Matters may be disclosed on a Schedule or Exhibit to this Agreement for purposes of information only. Nothing in the Schedules of Sellers is intended to broaden the scope or effect of any representation or warranty contained in this Agreement. Nothing in the Schedules constitutes an admission of any liability or obligation to any third Person, or an admission to any third Person against the interest of Sellers. Descriptions of or references to particular contracts, agreements, notices and other documents herein are qualified in their entirety by reference to such documents. Certain sections of this Agreement may be qualified by the matters set forth in the related Schedule, and the disclosure of any fact or item in any of the Schedules shall, should the existence of such fact or item be relevant to any other of the Schedules or sections in this Agreement, be deemed to be disclosed with respect to that other section or Schedule, in each case as long as it is readily apparent on its face. In disclosing information pursuant to the Schedules, no Seller waives any attorney-client privilege associated with such information or any protection afforded by the work-product doctrine.

(b) Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in Section 11.9 and the other terms and conditions of this Agreement, Sellers, jointly and severally, represent and warrant to Purchaser the matters set out in the remainder of this Article 5.

## Section 5.2. Existence and Qualification.

Each Seller is a corporation or limited liability company duly organized, validly existing and in good standing under the laws of the state of its incorporation or organization, as applicable, and is duly qualified to do business as a corporation or limited liability company in the jurisdictions where the Assets it owns are located.



## Section 5.3. Power.

Each Seller has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

## Section 5.4. Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of each Seller. This Agreement has been duly executed and delivered by each Seller (and all documents required hereunder to be executed and delivered by any Seller at Closing will be duly executed and delivered by such Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of each Seller, enforceable against each Seller in accordance with their terms subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium, and other similar Laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based on public policy.

## Section 5.5. No Conflicts.

Subject to compliance with or waiver of the Preference Rights and Transfer Requirements set forth in Schedule 5.13, the execution, delivery and performance of this Agreement by each Seller, and the transactions contemplated by this Agreement will not (i) violate any provision of the certificate of formation or incorporation, as applicable, bylaws or limited liability company agreement or any similar governing document of any Seller, (ii) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage or indenture to which any Seller is a party or which affect the Assets, (iii) violate any judgment, order, ruling, or decree applicable to any Seller as a party in interest, (iv) violate any Laws applicable to any Seller or any of the Assets, except for rights to consent by, required notices to, filings with, approval or authorizations of, or other actions by any Governmental Body where the same are not required prior to the assignment of the related Asset and that are customarily obtained subsequent to the sale or conveyance thereof.

## Section 5.6. Liability for Brokers' Fees.

Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of any Seller or its Affiliates, for brokerage fees, finder's fees, agent's commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

## Section 5.7. Litigation.

With respect to the Assets and any Seller’s or any of its Affiliates’ ownership, operation, development, maintenance, or use of any of the Assets, except as set forth in: (i) Schedule 5.7(a), no proceeding, claim, arbitration, action, suit, audit, investigation, pending settlement, or other legal proceeding of any kind or nature before or by any Governmental Body (each, a “Proceeding,” and collectively “Proceedings”) (including any take-or-pay claims) to which such Seller or any of its Affiliates is a party is pending or, to such Seller’s knowledge,

threatened in writing against such Seller or any of its Affiliates; and (ii) Schedule 5.7(b), to Sellers' knowledge, no Proceeding to which such Seller is not a party which relates to the Assets is pending or threatened.

## Section 5.8. Taxes and Assessments.

(a) Except as set forth on Schedule 5.8, all Tax reports, returns, statements (including estimated reports, returns or statements), and other similar filings relating to Sellers' acquisition, ownership or operation of the Assets (the "Tax Returns") required to be filed with respect to such Taxes have been duly and timely filed with the appropriate Governmental Body in all jurisdictions in which such Tax Returns are required to be filed, and all such Tax Returns are true, complete and correct in all material respects, and all Taxes related to Sellers' acquisition, ownership, or operation of the Assets have been timely paid in full (whether or not shown on any Tax Return), and no Seller is delinquent in the payment of such Taxes.

(b) Except as set forth on Schedule 5.8, with respect to all Taxes related to Sellers' acquisition, ownership or operation of the Assets, (i) there are not currently in effect any extensions or waivers of any statute of limitations of any jurisdiction regarding the assessment or collection of any such Tax; (ii) there are no Proceedings or Tax audits pending or, to Sellers' knowledge, threatened against the Assets or such Seller by any Governmental Body; and (iii) there are no Tax liens on any of the Assets except for liens for Taxes not yet due and payable. No Asset is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

(c) The transactions contemplated by this Agreement will not terminate any Tax incentive, holiday, abatement, or special appraisal used by Sellers with respect to the Assets.

## Section 5.9. Compliance with Laws.

Except as disclosed on Schedule 5.9, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are in material compliance with the provisions and requirements of all Laws applicable to the Assets. Except as disclosed on Schedule 5.9, (i) no Seller has received any written notice that the Assets are not in material compliance with any Environmental Laws and (ii) no Seller has received any written notice of any material claims with respect to Environmental Liabilities with respect to the Assets or any demands to clean-up any portion of the Assets. Notwithstanding the foregoing, except as set forth in this Section 5.9, Sellers make no representation or warranty, express or implied, relating to any Environmental Liabilities or Environmental Laws.



All Material Contracts are included within the list of Contracts in Schedule 1.2(a)(iv) and Schedule 1.2(b)(vi). Sellers are in material compliance with and, to Sellers' knowledge, all counterparties are in material compliance with, all Material Contracts, except as disclosed on Schedule 5.10. Except as set forth on Schedule 5.10, no event has occurred that with notice or lapse of time or both would constitute any material default under any such Material Contract by any Seller or, to Sellers' knowledge, by any other Person who is a party to such Material

Contract. No Seller has received or given any unresolved written notice of default, amendment, waiver, price redetermination, market out, curtailment or termination with respect to any Material Contract. "Material Contracts" means any of the following types of Contracts: (a) any Contract that could reasonably be expected to result in aggregate payments or receipts of revenues by Sellers or Purchaser with respect to the Assets of more than $150,000 during the current or any subsequent year (based solely on the terms thereof and without regard to any expected increase in volumes or revenues); (b) any Hydrocarbon purchase and sale, gathering, transportation, processing or similar Contract unless terminable by each party without penalty on 90 days or less notice; (c) any Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, any Seller conducts business, including area of mutual interest Contracts; (d) any Contract with any Affiliate of any Seller which will be binding on Purchaser after the Effective Time; (e) any joint operating agreement, unit operating agreement or similar operating agreement to the extent they relate to a Well producing from the Eagle Ford formation; and (f) any Contract that contains a call on production or any Contract that commits Purchaser to drill any wells.

## Section 5.11. Payments for Hydrocarbon Production.

## Except as set forth on Schedule 5.11.

(a) all rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by any Seller to overriding royalty interest holders and other interest owners under or with respect to the Assets and the Hydrocarbons produced therefrom or attributable thereto (collectively "Production Payments"), have been paid in full, or if not paid, Sellers are otherwise entitled under applicable Law and the terms of any applicable Lease to withhold payment, without penalty or interest, while resolving questions of title or obtaining division orders; and

(b) Sellers are not obligated under any contract or agreement for the sale of Hydrocarbons from the Assets containing a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering, transmission, or any other contract or agreement with respect to any of the Assets to gather, deliver, process, or transport any Hydrocarbons attributable to the Assets without then or thereafter receiving full payment therefor.

## Section 5.12. Governmental Authorizations.

Except as disclosed on Schedule 5.12, each Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the "Governmental Authorizations") that are presently necessary or required for the ownership and operation of the Seller Operated Assets operated by such Seller as currently owned and operated (excluding Governmental Authorizations required by Environmental Law). To Sellers' knowledge, except as disclosed in Schedule 5.7(a), Schedule 5.7(b) or Schedule 5.12, (i) each Seller has operated its Seller Operated Assets in all material respects in accordance with the conditions and provisions of such Governmental Authorizations, and (ii) no written notices of material violation have been received by any Seller, and no Proceedings are

pending or, to Sellers' knowledge, threatened in writing that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any material corrective or remedial action by any Seller.

## Section 5.13. Preference Rights and Transfer Requirements.

None of the Assets, or any portion thereof, is subject to any Preference Right or Transfer Requirement which may be applicable to the transactions contemplated by this Agreement, except for the Preference Rights and Transfer Requirements set forth on Schedule 5.13.

## Section 5.14. Payout Balances.

To Sellers’ knowledge, Schedule 5.14 contains a complete list in all material respects, of the status, as of December 31, 2016, of any “payout” balance for the Wells and Units listed on Exhibit A-1 that are subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

## Section 5.15. Outstanding Capital Commitments.

As of the date hereof, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which any Seller reasonably anticipates will individually require expenditures by the owner of the Assets after the Effective Time in excess of $100,000 other than those shown on Schedule 5.15.

## Section 5.16. Imbalances.

Schedule 5.16 accurately sets forth in all material respects all of the Imbalances of Sellers arising with respect to the Assets or production therefrom and, except as disclosed in Schedule 5.16, (i) no Person is entitled to receive any material portion of any Sellers' Hydrocarbons produced from the Assets or to receive material cash or other payments to "balance" any disproportionate allocation of Hydrocarbons produced from the Assets under any operating



agreement, gas balancing or storage agreement, gas processing or dehydration agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, (ii) Sellers are not obligated to deliver any material quantities of Hydrocarbons or to pay any material penalties or other material amounts, in connection with the violation of any of the terms of any gas contract or other agreement with shippers with respect to the Assets, and (iii) Sellers are not obligated to pay any material penalties or other material payments under any gas transportation or other agreement as a result of the delivery of quantities of Hydrocarbons from the Wells in excess of the contract requirements. Except as set forth on Schedule 5.16, Sellers have not received, or are not obligated to receive, prepayments (including payments for gas not taken pursuant to “take-or-pay” arrangements) for any of Sellers’ share of the Hydrocarbons produced from the Oil and Gas Properties, as a result of which the obligation exists to deliver Hydrocarbons produced from the Oil and Gas Properties after the Effective Time without then or thereafter receiving payment therefor.

## Section 5.17. Condemnation.

There is no actual or, to Sellers’ knowledge, threatened taking (whether permanent, temporary, whole or partial) of any part of the Assets by reason of condemnation or the threat of condemnation.

## Section 5.18. Bankruptcy.

There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Sellers’ knowledge, being contemplated by or threatened against any Seller. Each Seller is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

## Section 5.19. Foreign Person.

No Seller is a “foreign person” within the meaning of Section 1445 of the Code.

## Section 5.20. Suspended Funds.

Schedule 5.20 lists all funds held in suspense (including funds held in suspense for unleased interests) by any Seller or its Affiliates as of the date of this Agreement that are attributable to the Assets, a description of the source of such funds and the reason they are being held in suspense, and, if known, the name or names of the Persons claiming such funds or to whom such funds are owed.

## Section 5.21. Hydrocarbon Marketing.

There are no calls on production, options to purchase, or similar rights in effect with respect to any portion of the Hydrocarbons produced from or allocable to the Oil and Gas Properties, and, except as set forth on Schedule 5.21, all Contracts for the sale of Hydrocarbons are terminable without penalty on no more than 30 days' prior notice. Except as set forth in Schedule 5.21, none of the Oil and Gas Properties is subject to any acreage, well, or reserve commitment or dedication under the terms of any Hydrocarbon sales, gathering, processing, transportation, or similar agreement, or any obligation under any such agreement to pay any capacity charge, reservation charge, through-put fee, or similar charge or fee without regard to the quantity of Hydrocarbons actually delivered. To the knowledge of Sellers, all proceeds from the sale of Hydrocarbons attributable to the interests of each Seller in the Oil and Gas Properties have been and are being disbursed to such Seller under appropriate division orders, transfer orders, or similar documents signed by or otherwise binding on such Seller, and no portion of any such proceeds is being held in suspense, subject to a Claim for refund by the purchaser, used as an offset or as collateral for other obligations (whether disputed or undisputed), or otherwise not being paid to such Seller as it becomes due in the ordinary course of business.

## Section 5.22. Insurance.

Schedule 5.22 sets forth a true, correct and complete list of all insurance policies with un-Affiliated insurance providers currently maintained by Sellers with respect to the Assets, and indicates for each such policy the insurance company, policy number, terms of coverage, limits and carrier. No material claims of any nature under any such insurance policies are pending or, to Sellers’ knowledge, threatened, and Seller has not received any written notice from any

insurance company canceling or materially amending any of said insurance policies and, to Sellers’ knowledge, no such cancellation or material amendment thereof is threatened by such insurance company.

## Section 5.23. Employees.

(a) Sellers have furnished to Purchaser a list of all Field Employees (its “Field Employee List”) that includes each Field Employee’s (i) name, current job title and principal work location, (ii) employing entity (including any leasing agency), (iii) date of hire and (if different) length of service, (iv) current annualized base salary or hourly rate of compensation, (v) rights to receive severance, termination pay or advance notice of termination, and (vi) prior year’s actual and current year’s target bonus and incentive compensation. The Field Employee List also specifies, for each Field Employee, whether the Field Employee is employed on a part-time or a full-time basis. The Field Employee List also specifies, for each Field Employee, whether the Field Employee is on Leave and in the case of a Field Employee on Leave, the current expected return-to-work date if known by Sellers. Sellers shall promptly update its Field Employee List from time to time prior to the Closing Date to ensure its continuing accuracy. Sellers have furnished to Purchaser copies of all material contracts between any Field Employee and Sellers or any their Affiliates.

(b) None of Sellers nor any of their Affiliates is a party to a collective bargaining agreement or legally binding agreement with any labor union, similar employee association or works council in respect of Field Employees and, to Sellers’ knowledge, no labor union, similar employee association or works council is engaged in any formal procedure to organize the Field Employees for the purpose of collective bargaining.



(c) There does not exist any circumstance that could reasonably be expected to, on or after the consummation of the transactions contemplated by this Agreement, result in any Taxes in respect of the employment or engagement of any Field Employee prior to the Closing owed by or imposed upon, or “controlled group liability” to, Purchaser or any of its Affiliates. As used in the preceding sentence, the term “controlled group liability” means any and all liabilities and Losses (i) under Title IV of ERISA, (ii) under Section 302 of ERISA, (iii) under Sections 412 and 4971 of the Code or (iv) under the Coal Industry Retiree Health Benefit Act of 1992.

## ARTICLE 6.
REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to each Seller the following:

## Section 6.1. Existence and Qualification.

Purchaser is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a foreign entity in every jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to so qualify would not have a material adverse effect on Purchaser; and Purchaser is or will be as of Closing duly qualified to do business as a foreign entity in the jurisdictions where the Assets are located.

## Section 6.2. Power.

Purchaser has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

## Section 6.3. Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar Laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based on public policy.

## Section 6.4. No Conflicts.

The execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated by this Agreement will not (i) violate any provision of the organizational documents of Purchaser, (ii) result in a default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage or indenture to which Purchaser is a party, (iii) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, (iv) violate any Law applicable to Purchaser or any of its assets, or (v) require any filing with, notification of or consent, approval or authorization of any Governmental Body or authority, except any matters described in clauses (ii), (iii), (iv) or (v) above which would not have a material adverse effect on Purchaser or Purchaser's ability to perform its obligations with respect to the transactions contemplated hereby.

## Section 6.5. Liability for Brokers' Fees.

Sellers shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder's fees, agent's commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

## Section 6.6. Litigation.

There are no Proceedings pending, or to the Actual Knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to materially impair Purchaser’s ability to perform its obligations under this Agreement.

## Section 6.7. Limitation and Independent Evaluation.

Except for the representations and warranties expressly made by each Seller in Article 5 of this Agreement, or in the Conveyances or in any certificate furnished or to be furnished to Purchaser pursuant to this Agreement and absent fraud by any Seller, Purchaser acknowledges that (a) there are no representations or warranties, express, statutory or implied, as to the Assets or prospects the reof made by any Seller, and (b) Purchaser has not relied upon any oral or written information provided by Sellers. Without limiting the generality of the foregoing, subject to Section 5.9, Purchaser acknowledges that no Seller has made nor will make any representation or warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment or any other environmental condition of the Assets. Purchaser further acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller, and that it has retained and taken advice concerning the Assets and transactions herein from advisors and consultants which are knowledgeable about the oil and gas business, and that is aware of the risks inherent in the oil and gas business. Subject to Sellers' compliance with Section 4.1, Purchaser acknowledges that it has or will have access to the Assets, the officers and employees of Sellers, and the books, records and files made available by Sellers relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the representations of Sellers contained in



Article 5 and the basis of its own independent evaluation and due diligence investigation of the Assets, and its own independent evaluation of the business, economic, legal, tax, or other consequences of this transaction including its own estimate and appraisal of the extent and value of the oil, natural gas, and other reserves attributable to the Oil and Gas Properties.

## Section 6.8. SEC Disclosure.

Purchaser is acquiring the Oil and Gas Properties for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act and applicable state securities Laws. Purchaser understands and acknowledges that: (a) an investment

in the Assets involves certain risks; and (b) neither the SEC nor any federal, state or foreign agency has passed upon the Assets or made any finding or determination as to the fairness of an investment in the Assets or the accuracy or adequacy of the disclosures made to Purchaser.

## Section 6.9. Bankruptcy.

There are no bankruptcy, reorganization or receivership proceedings pending against, or, to the knowledge of Purchaser, being contemplated by, or threatened against Purchaser. Purchaser is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

## Section 6.10. Qualification.

As of Closing, Purchaser will be qualified to own and assume operatorship of the Leases in the jurisdictions where the Assets to be transferred to Purchaser are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser to be disqualified as such an owner or operator. To the extent required by applicable Law, as of the Closing, Purchaser will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, such Law (or other requirements) governing the ownership and operation of the Assets.

## Section 6.11. Financing.

Purchaser will have at Closing sufficient cash, available lines of credit or other sources of immediately available funds to enable it to pay the Purchase Price to Sellers.

## ARTICLE 7.
COVENANTS OF THE PARTIES

## Section 7.1. Access.

(a) From and after the date of this Agreement up to and including the date the Records are delivered to Purchaser pursuant to Section 1.5(a) (or the earlier termination of this Agreement), Sellers shall cooperate with Purchaser and provide Purchaser and its officers, directors, employees, agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (“Purchaser’s Representatives”), access to the Assets, the Records, and the Field Employees, but only to the extent that Sellers may do so without violating any obligations to any un-Affiliated third party or any Laws and to the extent that Sellers have authority to grant such access without breaching any restriction legally or contractually binding on Sellers; provided, however, that each Seller shall use its commercially reasonable efforts to obtain any necessary consents or approvals from un-Affiliated third parties or applicable Governmental Bodies in order to provide Purchaser and Purchaser’s Representatives such access. Purchaser shall conduct all such inspections and other information gathering described above only (i) (x) during regular business hours and (y) during any weekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, and (ii) in a manner which will not unduly interfere with Sellers’ operation of the Assets. All information obtained by Purchaser and its representatives pursuant to this Section 7.1 shall be subject to the terms of that certain confidentiality agreement dated December 13, 2016 (the “Confidentiality Agreement”), by and between Halcon Resources Corporation (Sellers’ parent) and Purchaser; provided, however, that if the Closing should occur, the foregoing confidentiality restriction on Purchaser, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets). Sellers shall also make available to Purchaser and Purchaser’s Representatives, upon reasonable notice during normal business hours, Sellers’ personnel knowledgeable with respect to the Assets (including the Field Employees) in order that Purchaser may make such diligence investigation as Purchaser considers necessary or appropriate.

(b) ALL MATERIALS, DOCUMENTS, AND OTHER INFORMATION, MADE AVAILABLE TO PURCHASER AT ANY TIME IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY, WHETHER MADE AVAILABLE

PURSUANT TO THIS SECTION OR OTHERWISE, ARE MADE AVAILABLE TO PURCHASER AS AN ACCOMMODATION, AND, EXCEPT TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT AND IN THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCES, ARE MADE WITHOUT REPRESENTATION OR WARRANTY OF ANY KIND, WHETHER EXPRESS, IMPLIED OR STATUTORY, AS TO THE ACCURACY AND COMPLETENESS OF SUCH MATERIALS, DOCUMENTS, AND OTHER INFORMATION OR AS TO WHETHER SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION CONTAINS A MISREPRESENTATION FOR THE PURPOSES OF APPLICABLE SECURITIES LAWS (WHETHER NOW OR HEREAFTER IN EFFECT). TO THE MAXIMUM EXTENT PERMITTED BY LAW, EXCEPT FOR PURCHASER'S RIGHTS WITH RESPECT TO THE REPRESENTATIONS SET FORTH IN ARTICLE 5 OF THIS AGREEMENT OR THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCES AND EXCLUDING FRAUD BY ANY SELLER, ANY RELIANCE UPON OR CONCLUSIONS DRAWN BY PURCHASER FROM SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION SHALL BE AT PURCHASER'S RISK AND SHALL NOT GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLERS, AND PURCHASER HEREBY ACKNOWLEDGES THAT IT IS NOT RELYING ON ANY REPRESENTATIONS OTHER THAN



THOSE REPRESENTATIONS AND WARRANTIES SET FORTH IN ARTICLE 5 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCES. EXCEPT FOR PURCHASER'S RIGHTS WITH RESPECT TO THE REPRESENTATIONS AND WARRANTIES OF SELLERS SET FORTH IN ARTICLE 5 OF THIS AGREEMENT, THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCES AND THE INDEMNITY OBLIGATIONS SET FORTH IN THIS AGREEMENT, AND EXCLUDING FRAUD BY ANY SELLER, PURCHASER HEREBY WAIVES AND RELEASES ANY CLAIMS ARISING UNDER THIS AGREEMENT, COMMON LAW OR ANY STATUTE (WHETHER NOW OR HEREAFTER IN EFFECT) ARISING OUT OF OR RELATED TO ANY MATERIALS, DOCUMENTS OR INFORMATION PROVIDED TO PURCHASER IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY.

## Section 7.2. Government Reviews.

Sellers and Purchaser shall in a timely manner (i) make all required filings, if any, with, prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations by such Party are necessary or appropriate in connection with the consummation of the transactions contemplated hereby and (ii) provide such information to the other Parties as Sellers or Purchaser, as applicable, may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each Party shall cooperate with and use all commercially reasonable efforts to assist the other Parties with respect to such filings, applications and negotiations.

## Section 7.3. Notification of Breaches.

Until the Closing,

(a) Purchaser shall notify Sellers promptly after Purchaser obtains Actual Knowledge that any representation or warranty of a Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by a Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b) Sellers shall notify Purchaser promptly after any Seller obtains Actual Knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c) If any of Purchaser’s or Sellers’ representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Sellers’ covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing, then, so long as the non-breaching Party does not incur any costs of liabilities on account of such breach (and, if the non-breaching Party is Purchaser, no Asset suffers a diminution in value on account of such breach), such breach shall be considered not to have occurred for all purposes of this Agreement.

(d) No notification by a Party of any breach pursuant to this Section 7.3 shall affect the representations, warranties or covenants of the Parties or the conditions to their respective obligations hereunder.

(e) There shall be no breach of the covenants in this Section 7.3 as a result of a Party’s failure to report a breach of any representation or warranty or a breach of an obligation to perform or observe any covenant or agreement of which it had Actual Knowledge if the Party subject to the breach or failure also had knowledge thereof prior to Closing.

## Section 7.4. Letters in Lieu; Assignments; Operatorship.

(a) Sellers will execute on the Closing Date letters in lieu of division and/or transfer orders relating to the Assets, on forms prepared by Sellers and reasonably satisfactory to Purchaser, to reflect the transactions contemplated hereby.

(b) Sellers will prepare and execute, and Purchaser will execute, on the Closing Date, the Conveyances and any additional assignments necessary to convey to Purchaser all federal and state Leases and Surface Rights in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Sellers.

(c) Except as set forth in Article 5 and the special warranty of title contained in the Conveyances, Sellers make no representations or warranties to Purchaser, express, implied or by statute, as to transferability or assignability of operatorship of any Seller Operated Assets. Rights and obligations associated with operatorship of any such Seller Operated Assets may be governed by operating and similar agreements that control the appointment of a successor operator, and in such case, whether Purchaser will succeed as operator of the subject Seller

Operated Assets (or portions thereof) will be determined in accordance with the terms of such agreements. However, Sellers will assist Purchaser in Purchaser's efforts to succeed Sellers or Sellers' Affiliate(s) as operator of any Oil and Gas Properties included in the Assets, including designating and/or appointing by assignment, to the extent legally possible, Purchaser as successor or operator or taking any other actions permitted or required under the applicable operating agreement or other governing document (including executing letters whereby the applicable Seller resigns as operator of all Seller Operated Assets). Purchaser shall, promptly following Closing, to the extent required by Law, file all appropriate forms, declarations or bonds with the applicable federal and/or state agencies relative to its assumption of operatorship with respect to the Oil and Gas Properties. For all Seller Operated Assets, Sellers and Purchaser shall execute appropriate change or transfer of operator forms on the Closing Date, and the applicable Seller shall thereafter promptly file said forms with the applicable Governmental Body transferring operatorship of such Assets to Purchaser.



## Section 7.5. Public Announcements.

Until the Closing, no Party shall make or issue, or cause or permit any agent or Affiliate to make or issue, any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the other Parties; provided, however, that the foregoing shall not restrict disclosures by any Party which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates. At or after Closing, any Party shall be permitted to issue press releases or other public announcements concerning the existence of this Agreement, the contents hereof and the transactions contemplated hereby; provided, however, that the content of any such press release or public announcement shall be subject to the prior review and reasonable approval of the other Parties (which shall not be unreasonably denied); and provided further, however, that the foregoing shall not restrict disclosures by any Party which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates.

## Section 7.6. Operation of Business.

(a) Except as set forth on Schedule 7.6, from and after the date of this Agreement until the Closing, Sellers: (i) will operate and maintain the Seller Operated Assets and the business thereof as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (ii) shall use their commercially reasonable efforts to cause the applicable un-Affiliated third party to operate and maintain any Assets not operated by a Seller (or an Affiliate of a Seller) as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (iii) shall maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of the applicable Seller, (iv) shall notify Purchaser of any authorizations for expenditure relating to the Assets that are received by any Seller or an Affiliate of any Seller, and keep Purchaser reasonably informed of ongoing operations and capital projects with respect to the Assets, (v) shall not propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by Purchaser as owner of the Assets in

excess of $100,000, or make any capital expenditures with respect to any operation, or series of related operations, in respect of the Assets in excess of $100,000 (net to Sellers' or its Affiliates' interest), (vi) shall not terminate (other than by failing to renew an existing term), amend or waive any material right under any Contract or Lease, extend the terms of any Contracts or enter into any contracts or agreements that if entered into prior to the date of this Agreement would be required to be listed in a Schedule attached to this Agreement, (vii) shall maintain insurance coverage on the Assets presently furnished by un-Affiliated third parties in the amounts and of the types presently in force as of the date of this Agreement, (viii) shall use commercially reasonable efforts to maintain in full force and effect all Leases and all Surface Rights, (ix) shall maintain all material Governmental Authorizations applicable to the Assets, (x) will not abandon, transfer, farmout, sell, hypothecate, mortgage, pledge, encumber, grant overriding royalties or other interests in, or otherwise dispose of any of the Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices and/or (B) sales of equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained, (xi) will not enter into any settlement, compromise or other agreement with respect to Taxes with any Governmental Body, or make or change any election with respect to Taxes, relating to the Assets, or consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Taxes relating to the Assets, (xii) shall not (A) settle or compromise any claim relating to the Assets for which Purchaser would have liability or (B) settle or compromise any claim relating to the Assets against a third party that would compromise or waive any claim in excess of $100,000, and (xiii) will not commit to do any of the items described in Section 7.6(a)(v), Section 7.6(a)(vi), Section 7.6(a)(x), Section 7.6(a)(xi) and Section 7.6(a)(xii) above. In the event of an emergency, Sellers may take such action as a prudent operator would take without the prior written consent of Purchaser; provided, however, that Sellers shall notify Purchaser of such action promptly thereafter.

(b) Purchaser acknowledges that Sellers may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners who are not a Seller or an Affiliate of a Seller shall not constitute a violation of the provisions of this Section 7.6 nor shall any action required by a vote of working interest owners constitute such a violation so long as each Seller (and any Affiliate of Sellers) has voted its interest in a manner consistent with the provisions of this Section 7.6.

## Section 7.7. Preference Rights and Transfer Requirements.

(a) The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements. Within 10 Business Days following the execution of this Agreement, Sellers shall initiate all procedures which are reasonably required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 5.13 with respect to the transactions contemplated by this Agreement. Sellers shall use commercially reasonable efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Sellers shall not be obligated to pay any consideration to (or incur any out of pocket cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith; and provided further that, except as provided in Section 7.7(c), any Transfer Requirement that states that consent thereto cannot

unreasonably be withheld (or words to similar effect), and as to which the lessor, or other holder of such Transfer Requirement, has not objected to the transfer or affirmatively stated that consent thereto will not be forthcoming, shall be deemed waived and otherwise satisfied 15 days after Sellers make written request to said lessor, or other holder of such Transfer Requirement, for consent to transfer the affected Asset(s) to Purchaser.

(b) If the holder of a Preference Right elects prior to Closing to purchase the Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Sellers receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.



(i) a third party brings any suit, action or other proceeding prior to the Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection with a claim to enforce a Preference Right;

(ii) an Asset is subject to a Transfer Requirement that (A) provides that the transfer of such Asset without compliance with such Transfer Requirement will, or that pursuant to applicable Law will, result in termination or other material impairment of any rights in relation to such Asset or the value thereof, (B) that is held by a Governmental Body, (C) provides that any assignment of the Asset affected thereby is, or that pursuant to applicable Law is, void or voidable or (D) is expressly denied by the holder thereof, and (in each case) such Transfer Requirement is not waived by the holder thereof or obtained prior to the Closing Date; or

(iii) the holder of a Preference Right does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date and the time in which the Preference Right may be exercised has not expired;

then, unless otherwise agreed by Sellers and Purchaser, the Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Purchaser at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset pursuant to Section 7.7(b). Any Retained Asset so held back at the initial Closing will be conveyed to Purchaser (subject to the satisfaction of the conditions in Section 8.2 with respect to such Retained Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within 10 Business Days following the date on which the suit, action or other proceeding, if any, referenced in clause (i) above is settled or a judgment is rendered (and no longer subject to appeal) permitting transfer of the Retained Asset to Purchaser pursuant to this Agreement and Sellers obtain a waiver of or notice of election not to exercise from the applicable third parties, or otherwise satisfy, all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section 7.7(c) (or if

multiple Assets are Retained Assets, on a date mutually agreed to by the Parties in order to consolidate, to the extent reasonably possible, the number of Closings). At the delayed Closing, Purchaser shall pay Sellers a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 2.2 through the new Closing Date therefor with respect to such Retained Asset); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained or waived by the holder thereof as contemplated by this Section within 120 days after the initial Closing has occurred with respect to any Asset, then such Retained Asset shall be eliminated from the Assets and shall become an Excluded Asset, unless Sellers and Purchaser agree to proceed with a closing on such Retained Asset, in which case Purchaser shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnified Persons for all Losses) with respect to non-compliance with such Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

(d) Purchaser acknowledges that Sellers desire to sell all of the Assets to Purchaser and would not have entered into this Agreement but for Purchaser’s agreement to purchase all of the Assets as herein provided. Accordingly, it is expressly understood and agreed that Sellers do not desire to sell any Property affected by a Preference Right to Purchaser unless the sale of all of the Assets is consummated by the Closing Date in accordance with the terms of this Agreement (other than the Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement). In furtherance of the foregoing, Sellers’ obligation hereunder to sell the Preference Properties to Purchaser is expressly conditioned upon the consummation by the Closing Date of the sale of all of the Assets (other than Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement) in accordance with the terms of this Agreement; provided that, nothing herein is intended or shall operate to extend or apply any Preference Right to any portion of the Assets which is not otherwise burdened thereby. Time is of the essence with respect to the Parties’ agreement to consummate the sale of the Assets by the Closing Date (or by any delayed Closing Date pursuant to Section 7.7(c)).

## Section 7.8. Tax Matters.

(a) Subject to the provisions of Section 12.3, Sellers shall be responsible for all Taxes related to the Assets (including ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom) attributable to any period of time prior to the Effective Time, and Purchaser shall be responsible for all such Taxes related to the Assets attributable to any period of time on and after the Effective Time (the “Prorated Taxes”). For the avoidance of doubt, Sellers shall be responsible for all Taxes related to the Excluded Assets. In the case of any Taxes upon or measured by the volume or dollar amount of Hydrocarbon production, Sellers and Purchaser shall each be allocated and responsible for all such Taxes attributable to the production allocated to each under Section 1.4; in the case of any Taxes based on net or gross income, each party shall be allocated and be responsible for its own taxable income; and in the case of any other Taxes, Sellers and Purchaser shall each be allocated and responsible for such other Taxes due with respect to a taxable period beginning prior to the Effective Time and ending on or after the Effective Time, based upon the number

of days in such period prior to the Effective Time (in the case of Sellers) or after the Effective Time (in the case of Purchaser). To the extent there is a conflict between the allocation provisions of this Section 7.8(a) and Section 1.4, this Section 7.8(a) shall control. Notwithstanding the foregoing, Sellers shall handle payment to the appropriate Governmental Body of all Taxes with respect to the Assets which are required to be paid prior to Closing (and shall file all Tax Returns with respect to such Taxes). Sellers (in consultation with Purchaser) shall also handle payment to the appropriate Governmental Body of all Taxes ad valorem and property Taxes based on units of Hydrocarbons produced prior to the Closing Date and for which payment is due after the Closing Date. If requested by Purchaser, Sellers will assist Purchaser with preparation of all ad valorem and property Tax Returns for periods ending on or before the Closing Date (including any extensions requested), but which are required to be paid after the Closing Date. Sellers shall deliver to Purchaser within 30 days of filing copies of all Tax Returns to be filed by Sellers relating to the Assets and any supporting documentation to be provided by Sellers to Governmental Bodies for



Purchaser’s approval, which shall not be unreasonably withheld, excluding Tax Returns related to income tax, franchise tax, or other similar Taxes. Purchaser shall file all Tax Returns covering Taxes treated as Property Costs that are required to be filed after the Closing Date unless covered above. With respect to such Tax Returns covering a taxable period which includes the Effective Time, Purchaser shall provide a copy of such Tax Return to Sellers within 30 days prior to filing for Sellers’ approval, which shall not be unreasonably withheld. If any Taxes allocated to Sellers pursuant to this Section 7.8 or Section 1.4 are actually paid by Purchaser, then, after the Closing Date and upon written request by Purchaser, Sellers shall, within 15 Business Days of such request, make a payment to Purchaser of the amount of any such Taxes paid by Purchaser but allocated to Sellers. If any Taxes allocated to Purchaser pursuant to this Section 7.8 or Section 1.4 are actually paid by Sellers and not already accounted for in an adjustment to the Purchase Price pursuant to Section 2.2(d), then, after the Closing Date and upon written request by Sellers, Purchaser shall, within 15 Business Days of such request, make a payment to Sellers of the amount of any such Taxes paid by Sellers but allocated to Purchaser.

(b) Purchaser and Sellers shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of any Tax Returns and any audit, litigation or other Proceeding with respect to Taxes. Such cooperation shall include the retention and (upon the other Party’s request) the provision of records and information which are reasonably relevant to any such audit, litigation or other Proceeding and making employees reasonably available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Purchaser and each Seller agree (i) to retain all books and records with respect to Tax matters pertinent to the Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Purchaser or Sellers, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Governmental Body, and (ii) to give the other Party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other Party so requests, each Party shall allow the other Party the option of taking possession of such books and records prior to their disposal. Purchaser and Sellers further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other document from any Governmental Body or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated hereby. Sellers shall promptly notify

Purchaser in writing upon receipt by any Seller of notice of any pending or threatened Tax audits or assessments relating to the income, properties or operations of Seller that reasonably may be expected to relate to or give rise to a lien on the Assets. Each of Purchaser and Sellers shall promptly notify the other in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the Allocated Values or the Tax Allocation.

(c) The parties acknowledge that reporting, compliance and payment obligations and procedures that apply to state unclaimed property and escheat obligations (“Unclaimed Property Matters”) differ significantly from those for income taxes, severance taxes and other types of Taxes, and that some of Sellers are currently under examination with respect to unclaimed property and escheat obligations. Accordingly, notwithstanding other provisions to the contrary in this Section 7.8, Section 1.4 and elsewhere in this Agreement, this Section 7.8(c) shall govern the obligations of the parties (as among themselves) with respect to Unclaimed Property Matters, which obligations shall not be prorated or treated as Property Costs. Since the Purchaser is assuming pre-Effective Time liabilities expected to be paid from the Suspended Funds (the “Suspended Funds Liabilities”) and Sellers are retaining any other pre-Effective Time liabilities arising from the Assets or from any Seller’s other operations, as between the parties the Purchaser shall be responsible for the reporting, compliance and payments required for Unclaimed Property Matters with respect to the Suspended Fund Liabilities, while the Sellers shall be responsible for the reporting, compliance and payments required for Unpaid Property Matters with respect to other liabilities incurred prior to the Effective Time. For the avoidance of doubt, Purchaser shall be responsible for Unclaimed Property Matters related to liabilities incurred in the operation of the Assets after the Effective Time. Purchaser and Sellers shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with such Unclaimed Property Matters with respect to liabilities incurred prior to the Effective Time. Such cooperation shall include the retention and (upon the other Party’s request) the provision of records and information which are reasonably relevant to any such Unclaimed Property Matters and making employees reasonably available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Purchaser and each Seller agree (i) to retain all books and records with respect to such Unclaimed Property Matters pertinent to liabilities incurred prior to the Effective Time during the pendency of any examination of until all obligations with respect to such Unclaimed Property Matters have ceased, and to abide by all record retention agreements entered into with any Governmental Body with respect to such books and records, and (ii) to give the other Party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other Party so requests, each Party shall allow the other Party the option of taking possession of such books and records prior to their disposal. Each of Purchaser and Sellers shall promptly notify the other in writing reasonably promptly after the commencement of examination or other proceedings by a Government Authority or its agents with respect to Unclaimed Property Matters (other than such examinations or proceedings disclosed prior to the Effective Time).

(d) Sellers and Purchaser hereby agree that Sellers shall have the right at any time prior to completion of all the transactions that are to occur at Closing to assign all or a portion of its rights and obligations under this Agreement to a Qualified Intermediary (as that term is defined in Section 1.1031(k)-1(g)(4) of the Treasury Regulations) in order to accomplish the transaction in a manner that will comply, either in whole or in part, with the requirements of a

like-kind exchange pursuant to Section 1031 of the Code (an “Exchange”). Likewise, Purchaser shall have the right at any time prior to completion of all the transactions that are to occur at Closing to assign all or a portion of its rights and obligations under this Agreement in an Exchange for the same purpose. If Sellers assign all or any of their rights under this Agreement for this purpose, Purchaser agrees to (i) consent to Sellers’ assignment of their rights in this Agreement, which assignment shall be in a form reasonably acceptable to Purchaser, and (ii) pay the Closing Payment (or a designated portion thereof as specified by Purchaser) and direct the Escrow Agent to disburse the Deposit into a qualified escrow or qualified trust account(s) at Closing as directed in writing. If Purchaser assigns all or any of its rights under this Agreement for this purpose, Sellers agree to (A) consent to Purchaser’s assignment of its rights in this Agreement, which assignment shall be in a form reasonably acceptable to Sellers, (B) accept the Purchase Price from a Qualified Intermediary, the qualified escrow or qualified trust account at Closing (as applicable), and (C) at Closing, convey and assign directly to Purchaser or a Qualified Intermediary (as applicable) the Assets (or any portion thereof) as directed by Purchaser. Sellers and Purchaser acknowledge and agree that (v) any Exchange shall not release any Party from any of its respective liabilities and obligations hereunder, (w) neither Party represents to the other Party that any particular Tax treatment will be given to any Party as a result thereof, (x) the Closing shall not be delayed or affected by reason of any Exchange, nor shall consummation or accomplishment of an Exchange be a condition precedent or condition subsequent to the exchanging Party’s obligations under this Agreement, and the



exchanging Party’s failure or inability to consummate an Exchange for any reason, or for no reason at all, shall not be deemed to excuse or release the exchanging Party from its obligations under this Agreement, (y) no Party shall be required to take an assignment of this Agreement for the relinquished or replacement property or be required to acquire or hold title to any real property for purposes of consummating an Exchange desired by the other Party, and (z) the exchanging Party shall pay any additional costs that would not otherwise have been incurred by the non-exchanging Party had the exchanging Party not consummated the transaction through an Exchange and the exchanging Party shall indemnify the non-exchanging Party against any such additional costs or liabilities. The Party electing to assign all or any of its rights under this Agreement pursuant to this Section shall defend, indemnify, and hold harmless the other Party and its Affiliates from all claims relating to or arising from such election.

(e) Any payments made to any Party pursuant to Article 11 shall constitute an adjustment of the Purchase Price for Tax purposes and shall be treated as such by Purchaser and Sellers on their Tax Returns to the extent permitted by Law.

## Section 7.9. Further Assurances.

After the Closing, Sellers and Purchaser shall, and shall cause their Affiliates, as applicable to, execute, acknowledge and deliver from time to time all such further conveyances, transfer orders, division orders, notices and such other instruments, and shall take such further actions as any Party may reasonably request and as may be necessary or appropriate to accomplish the transactions described in this Agreement (including that all of the Assets intended to be conveyed under the terms of this Agreement are so conveyed, including such Assets that are improperly described herein or inadvertently omitted from this Agreement and/or

the Conveyances and/or the Exhibits attached to each of the foregoing and to perfect Purchaser’s title thereto.

## Section 7.10. Notice of Claims.

Sellers shall promptly notify Purchaser as soon as reasonably practicable (but in any event within five Business Days) of any written notice received or given by any Seller or Affiliate of any Seller with respect to (a) any alleged material breach of any Lease or Contract, (b) any action to alter, terminate, rescind or procure a judicial reformation of any Lease or Contract or (c) any new claim for damages or any new investigation, suit, action or litigation with respect to the Assets.

## Section 7.11. Enforcement of Third Party Warranties, Guarantees and Indemnities.

Sellers agree that as of the Closing Date, to the extent relating to the Assumed Seller Obligations and at Purchaser’s request, Sellers shall use their commercially reasonable efforts to enforce, for the benefit of Purchaser and at Purchaser’s cost and expense, all of Sellers’ (or their respective Affiliates’) rights against un-Affiliated third parties under any warranties, guarantees or indemnities given by such third parties with respect to the Assets.

## Section 7.12. Non-Compete.

From the Closing Date until 12 months thereafter, no Seller shall, and each Seller shall cause its Affiliates not to, directly or indirectly, acquire in any capacity, or assist any Person to acquire, any interest in any oil, gas and mineral lease, oil and gas lease, mineral fee interest, fee interest or other mineral interest or contract to acquire any of the foregoing, in each case relating to lands located in (a) Brazos County, Texas, (b) Burleson County, Texas or (c) Robertson County, Texas; provided, that the foregoing restriction shall not apply to (i) the acquisition of any equity interests in a Person unless the aggregate value of the assets of such acquired Person within the foregoing counties comprise more than 25% of the total assets of such Person or (ii) any Excluded Assets, Assets which Sellers retain as a result of the title or environmental defect procedures set forth in this Agreement, or Offered Leases not acquired by Purchaser in accordance with Section 1.2(c).

## Section 7.13. Transferred Employees.

(a) From the date of this Agreement until the earlier of the Closing or the termination of this Agreement in accordance with Article 10, Sellers and their Affiliates shall make available to Purchaser each of the Field Employees to discuss post-Closing employment with Purchaser or an Affiliate of Purchaser. Purchaser or its applicable Affiliate may, in its sole discretion, make offers of employment to any of the Field Employees, which offers shall be on such terms and conditions as Purchaser may determine. With respect to each Field Employee who accepts an offer of employment from Purchaser or its Affiliate as contemplated by this Section 7.13 and commences such employment (each, a “Transferred Employee”), Sellers and their Affiliates shall (A) terminate the employment of such Transferred Employee as of the time immediately prior to the Closing and (B) waive and release, from and after the Closing, any confidentiality, non-competition, non-disclosure and similar agreements between Sellers or

any Affiliate of Sellers and such Transferred Employee that would prevent such Transferred Employee from commencing employment with Purchaser or its Affiliate or hinder such Transferred Employee from performing his/her duties for Purchaser or its Affiliate, or that relate to the businesses conducted by Sellers or their Affiliates. Purchaser will not assume or otherwise be responsible for any accrued vacation and paid time off for any Transferred Employees that accrued through the Closing Date or any other obligation or liability whatsoever arising under or relating to any Seller Benefit Plan, or from employment with or termination of employment by Sellers or their Affiliates.

(b) The provisions of this Section 7.13 are for the sole benefit of the Parties and nothing herein, expressed or implied, is intended or will be construed to confer upon or give to any Person (including, for the avoidance of doubt, any Field Employee or other current or former employee of Sellers or any of their Affiliates, other than the Parties and their respective permitted successors and assigns) any legal or equitable or other rights or remedies (including with respect to the matters provided for in this Section 7.13) under or by reason of any provision of this Agreement. Nothing in this Section 7.13 amends, or will be deemed to amend (or prevent the amendment or termination of) any Seller Benefit Plan. Sellers and Purchaser shall provide each other with such data and



# ARTICLE 8.
CONDITIONS TO CLOSING

## Section 8.1. Conditions of Sellers to Closing.

The obligations of Sellers to consummate the transactions contemplated by this Agreement are subject to the fulfillment on or prior to Closing of each of the following conditions, each of which may be waived by Sellers:

(a) Representations. Each of the representations and warranties of Purchaser contained in Article 6 shall be true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of such specified date;

(b) Performance. Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Purchaser under this Agreement prior to the Closing Date and shall be ready, willing and able to perform, in all material respects, all covenants and agreements to be performed by Purchaser under this Agreement on the Closing Date;

(c) Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial

damages in connection with (excluding any damage that Purchaser expressly agrees to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damage that Purchaser expressly agrees to be responsible for) in connection with, the transactions contemplated by this Agreement, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby;

(d) Deliveries. Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Sellers duly executed counterparts of the Conveyances and all other documents and certificates to be delivered by Purchaser under Section 9.3 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.3;

(e) No Material Adverse Effect. No Material Adverse Effect shall have occurred since the date of this Agreement; and

(f) Price Adjustment Limitations. The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4 (Notice of Title Defect Adjustments) (net of any upward adjustments for any Title Benefits), Section 3.5 (Casualty or Condemnation Loss), Section 4.3 (Environmental Defects) and Section 7.7 (Preference Rights and Transfer Requirements) does not exceed 20% of the Purchase Price.

## Section 8.2. Conditions of Purchaser to Closing.

The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject, at the option of Purchaser, to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions:

(a) Representations. Each of the representations and warranties of Sellers contained in Article 5 shall be true and correct (without regard to any materiality qualifiers) as of the date hereof and as of the Closing Date as though made on and as of the Closing Date, except (i) to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct (without regard to any materiality qualifiers) as of such specified date; and (ii) to the extent the failure of such representations or warranties to be true and correct (without regard to any materiality qualifiers) would not, individually or in the aggregate, result in a Material Adverse Effect; provided, that Sellers shall (and Seller Representative shall have prior to Closing acknowledged in writing Sellers' obligation to) indemnify Purchaser with respect to such failure pursuant to Section 11.5(a) without applicability of the Individual Indemnity Threshold, Aggregate Indemnity Deductible or other limitations in Section 11.4(c);

(b) Performance. Sellers shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Sellers under this Agreement prior to the Closing Date and shall be ready, willing and able to perform, in all material

respects, all covenants and agreements to be performed by Sellers under this Agreement on the Closing Date;

(c) Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial damages in connection with (excluding any damages that Sellers expressly agree to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damages that Sellers expressly agree to be responsible for) in connection with, the transactions contemplated by this Agreement, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains,



enjoins or invalidates the transactions contemplated hereby;

(d) Deliveries. Sellers shall have delivered or cause to be delivered (or be ready, willing and able to immediately deliver or cause to be delivered) to Purchaser duly executed counterparts of the Conveyances and all other documents and certificates to be delivered or caused to be delivered by Sellers under Section 9.2;

(e) No Material Adverse Effect. No Material Adverse Effect shall have occurred since the date of this Agreement; and

(f) Price Adjustment Limitations. The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4 (Notice of Title Defect Adjustments) (net of any upward adjustments for any Title Benefits), Section 3.5 (Casualty or Condemnation Loss), Section 4.3 (Environmental Defects) and Section 7.7 (Preference Rights and Transfer Requirements) does not exceed 20% of the Purchase Price.

## ARTICLE 9.
CLOSING

## Section 9.1. Time and Place of Closing.

(a) Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 10, and subject to the satisfaction or waiver of the conditions set forth in Article 8 (other than conditions the fulfillment of which by their nature is to occur at the completion of the transactions contemplated by this Agreement (the "Closing")), and subject to the provisions of Sections 3.4 and 7.7 relating to delayed Closings, the Closing, shall take place at 10:00 a.m., local time, on March 9, 2017 (such date the "Scheduled Closing Date"), at the offices of Halcón Resources Corporation, 1000 Louisiana, Suite 6700, Houston, Texas, unless the date for Closing is extended pursuant to Section 3.4(k) and/or Section 4.3(b), in which case the Closing shall take place on such extended date or such other date, time or place is mutually agreed to in writing by Purchaser and Sellers. If any of the conditions (other than conditions the fulfillment of which by their nature is to occur at the Closing) set forth in Article 8 are not satisfied or waived at the time

the Closing is to occur pursuant to this Section 9.1(a), then the Closing shall occur on a date that is the third Business Day after the satisfaction or waiver of all such conditions.

(b) The date on which the Closing occurs is herein referred to as the “Closing Date”.

## Section 9.2. Obligations of Sellers at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Sellers shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a) the Conveyances, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by each Seller;

(b) assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising part of the Assets, duly executed and (if applicable) acknowledged by each Seller;

(c) a transition services agreement in the form attached as Exhibit E hereto (the “Transition Services Agreement”), duly executed by each Seller;

(d) transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by the applicable Seller and prepared in accordance with Section 7.4(a);

(e) a certificate duly executed by an authorized corporate officer of each Seller, dated as of Closing, certifying on behalf of Sellers that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(f) evidence that all lien releases from Sellers’ current lenders have been obtained relating to all mortgages, deeds of trust, fixture filings and security agreements affecting the Assets, and that releases of any related financing statements have been obtained (where applicable, in accordance with the Uniform Commercial Code);

(g) the change or transfer of operator forms referenced in Section 7.4(c) to be executed by each applicable Seller and which forms shall be filed by Purchaser pursuant to Section 7.4(c) after Closing;

(h) a certificate, reasonably acceptable to Purchaser, that each Seller is not a foreign person within the meaning of the Code, as described in Treasury Regulation 1.1445-2(b)(2);

(i) the Preliminary Settlement Statement, duly executed by each Seller;

(j) a joint instruction letter to the Escrow Agent duly executed by Seller Representative instructing the Escrow Agent to release the Deposit to Sellers;



(k) a validly executed Texas Form 01-917, Statement of Occasional Sale, reasonably acceptable to Purchaser, with respect to each of (i) the Oil and Gas Assets and (ii) the Midstream Assets;

(I) a written acknowledgement from Seller Representative of Sellers' obligation to indemnify Purchaser with respect to each Pre-Closing Indemnity Claim for which Purchaser has submitted a Claim Notice prior to Closing, if any; and

(m) duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Sellers at the Closing.

## Section 9.3. Obligations of Purchaser at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shall deliver or cause to be delivered to Sellers, or perform or caused to be performed, the following:

(a) a wire transfer to each Seller (to the accounts designated in Schedule 9.4(d)) in an amount equal to such Seller’s Closing Payment, in immediately available funds;

(b) the Conveyances, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by Purchaser;

(c) assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising portions of the Assets, duly executed and (if applicable) acknowledged by Purchaser;

(d) the Transition Services Agreement, duly executed by Purchaser;

(e) a certificate by an authorized corporate officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled;

(f) transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by Purchaser and prepared in accordance with Section 7.4(a);

(g) the Preliminary Settlement Statement, duly executed by Purchaser;

(h) a joint instruction letter to the Escrow Agent duly executed by Purchaser instructing the Escrow Agent to release the Deposit to Sellers; and

(i) duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Purchaser at the Closing.

## Section 9.4. Closing Adjustments.

(a) Not later than five Business Days prior to the Closing Date, Sellers shall prepare in good faith and deliver to Purchaser, based upon the best information available to Sellers at such time, a draft preliminary settlement statement (the “Preliminary Settlement Statement”) estimating each Seller’s share of the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2 and any amounts to be escrowed pursuant to Section 3.4(k) and reflecting the calculation of the adjustments used to determine such amounts. Within three Business Days of receipt of the Preliminary Settlement Statement, Purchaser will deliver to Sellers a written report containing all changes, with the explanation therefor, that Purchaser proposes to be made to the Preliminary Settlement Statement. The Preliminary Settlement Statement, as agreed upon by Sellers and Purchaser, will be used to adjust the Adjusted Purchase Price and determine the dollar amount to be paid by Purchaser to each Seller at the Closing (each, the “Closing Payment”). If Sellers and Purchaser cannot agree on the Preliminary Settlement Statement prior to Closing, the Preliminary Settlement Statement as presented by Sellers (with such changes agreed to by the Parties) will be used to adjust the Adjusted Purchase Price and determine each Closing Payment.

(b) As soon as reasonably practicable after the Closing but not later than 120 days following the Closing Date, Sellers shall prepare and deliver to Purchaser a statement (the “Final Settlement Statement”) setting forth the final calculation of the Adjusted Purchase Price, and each Seller’s share thereof, and showing the calculation of each adjustment, based on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement, including any amount escrowed pursuant to Section 3.4(k) (the “Final Purchase Price”). Sellers shall, at Purchaser’s request, supply reasonable documentation in Sellers’ or their Affiliates’ possession available to support any credit, charge, receipt or other item for which adjustments are made. Sellers shall afford Purchaser and its representatives the opportunity to review such statement and the supporting schedules, analyses, workpapers, and other underlying records or documentation as are reasonably necessary and appropriate in Purchaser’s review of such statement. Each Party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto. As soon as reasonably practicable but not later than the 30th day following receipt of Sellers’ statement hereunder, Purchaser shall deliver to Sellers a written report containing any changes that Purchaser proposes be made to such statement.

(c) Sellers and Purchaser shall undertake to agree on the Final Settlement Statement, including the final statement of the Final Purchase Price, and each Seller’s share thereof, no later than 180 days after the Closing Date (the “Final Settlement Date”). In the event that Sellers and Purchaser cannot reach agreement by the Final Settlement Date, either Party may refer the remaining matters in dispute to a nationally-recognized independent accounting firm as may be mutually selected by Purchaser and Sellers (and absent such mutual selection, as appointed by the Houston office of the American Arbitration Association), for review and final determination (the “Agreed Accounting Firm”). Each of Purchaser, on the one hand, and Sellers, on the other hand, shall summarize its position with regard to the remaining matters in dispute in a written document of 25 pages or less and submit such summaries to the Agreed Accounting Firm, together with any other documentation such Party may desire to submit.



Within 15 Business Days after receiving the Parties’ respective submissions, the Agreed Accounting Firm shall render in writing a decision choosing Sellers’ position or Purchaser’s position, whichever is most accurate based on the terms of this Agreement and the materials described above. The Agreed Accounting Firm may not award damages or penalties to any Party. Any decision rendered by the Agreed Accounting Firm pursuant hereto shall be final, conclusive and binding on Sellers and Purchaser and will be enforceable against any of the Parties in any court of competent jurisdiction. The fees of the Agreed Accounting Firm shall be borne and paid one-half by Sellers and one-half by Purchaser. Sellers and Purchaser shall each bear its own legal fees and other costs of presenting its case. Within 10 Business Days after the date on which Sellers and Purchaser or the Agreed Accounting Firm, as applicable, finally determines the disputed matters, subject to Section 3.4(k) with respect to any amounts escrowed pursuant thereto (i) Purchaser shall pay to Sellers each Seller’s share of the amount by which the Final Purchase Price exceeds the Closing Payment or (ii) each Seller shall pay to Purchaser the amount by which such Seller’s share of the Closing Payment exceeds such Seller’s share of the Final Purchase Price, as applicable.

(d) All payments made or to be made hereunder to a Seller shall be by electronic transfer of immediately available funds to the account of such Seller as set forth on Schedule 9.4(d), for the credit of Sellers or to such other bank and account as may be specified by such Seller to Purchaser in writing. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Sellers.

## ARTICLE 10.
TERMINATION

## Section 10.1. Termination.

This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing:

(a) by mutual written consent of Sellers and Purchaser;

(b) by Sellers, if any of the conditions set forth in Section 8.1 (other than the conditions set forth in Section 8.1(f)) have not been satisfied by Purchaser on or before March 20, 2017, provided that if any title or environmental matters are submitted to a Title Expert and/or Independent Expert in accordance with Section 3.4(k) or Section 4.3(b), as applicable, such date will be extended to be the date that is the 10th Business Day following the decision of the Title Expert and/or Independent Expert pursuant to such Section or Sections, as applicable (such date, as may be so extended, the "Termination Date");

(c) by Purchaser, if any of the conditions set forth in Section 8.2 (other than the conditions set forth in Section 8.2(f)) have not been satisfied by Sellers on or before the Termination Date;

(d) by Sellers if the condition set forth in Section 8.1(f) is not waived or satisfied on or before the Termination Date or by Purchaser if the condition set forth in Section 8.2(f) has not been waived or satisfied on or before the Termination Date;

(e) by Sellers or Purchaser, if there shall be any Law that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Body shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and non-appealable;

provided, however, that neither Party shall have the right to terminate this Agreement under clause (b), (c) or (d) above if such Party or its Affiliates are at such time in material breach of any provision of this Agreement.

## Section 10.2. Remedies.

(a) If this Agreement is terminated pursuant to Section 10.1, then, except for the provisions of (a) Section 2.4, Section 4.4, Section 5.6, Section 6.5, Section 7.5, Section 11.9, this Article 10 and Article 12, and (b) such terms as set forth in this Agreement in order to give context to any of the surviving Sections, this Agreement shall forthwith become void and the Parties shall have no liability or obligation hereunder except and to the extent such termination results from the willful breach by a Party of any of its covenants or agreements hereunder, in which case, (i) if the breaching Party is Purchaser, Sellers shall be entitled to receive the Deposit as their exclusive remedy and as liquidated damages for Purchaser's breach, in accordance with Section 2.4, and (ii) if the breaching Party is Sellers (or any Seller), Purchaser shall be entitled to be delivered the Deposit in accordance with Section 2.4 and to pursue any other remedies available at Law or in equity, including specific performance.

(b) Upon termination of this Agreement, Purchaser shall return to Sellers or destroy all title, engineering, geological and geophysical data, environmental assessments or reports, maps and other information furnished by Sellers to Purchaser or prepared by or on behalf of Purchaser in connection with its due diligence investigation of the Assets, in each case, in accordance with the Confidentiality Agreement, and an officer of Purchaser shall certify same to Sellers in writing.

(c) If this Agreement is terminated pursuant to Section 10.1, Seller Representative and Purchaser agree to execute Joint Instructions to distribute the Deposit pursuant to Section 2.4.



## Section 11.1. Receipts.

Except as otherwise provided in this Agreement, any Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and any other income, proceeds, revenues, receipts and credits attributable to the Assets which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) (i) all Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and all other revenues, income, proceeds, receipts and credits earned with respect to the Oil and Gas Assets to

which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser; (ii) all fees, rentals proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets to which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser; and (iii) to the extent received by Sellers, Sellers shall fully disclose, account for and remit the same promptly to the relevant Purchaser; and (b) (i) all Hydrocarbons produced from or allocable to the Oil and Gas Properties (and all products and proceeds attributable thereto) and all other income, proceeds, revenues, receipts and credits earned with respect to the Oil and Gas Assets to which Sellers are entitled under Section 1.4 shall be the sole property and entitlement of Sellers; (ii) all fees, rentals proceeds, payments, revenues, receipts, income, and credits earned with respect to the Midstream Assets to which Sellers are entitled under Section 1.4 shall be the sole property and entitlement of Sellers; and (iii) to the extent received by Purchaser, Purchaser shall fully disclose, account for and remit the same promptly to the relevant Seller(s).

## Section 11.2. Expenses.

Any Property Costs which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Property Costs for which Sellers are responsible under Section 1.4 shall be the sole obligation of Sellers and Sellers shall promptly pay, or if paid by Purchaser, promptly reimburse Purchaser for and hold Purchaser harmless from and against same; and (b) all Property Costs for which Purchaser is responsible under Section 1.4 shall be the sole obligation of Purchaser, and Purchaser shall promptly pay, or if paid by Sellers, promptly reimburse Sellers for and hold Sellers harmless from and against same. Sellers are entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Sellers are wholly responsible and Purchaser is entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Purchaser is in whole or in part responsible; provided that Purchaser shall not agree to any adjustments to previously assessed costs for which Sellers are liable without the prior written consent of Seller, such consent not to be unreasonably withheld, conditioned or delayed. Purchaser shall provide Sellers with a copy of all applicable audit reports and written audit agreements received by Purchaser and relating to periods for which Sellers are partially or wholly responsible, and Sellers shall provide Purchaser with a copy of all applicable audit reports and written audit agreements received by a Seller and relating to periods for which Purchaser is partially or wholly responsible.

## Section 11.3. Assumed Seller Obligations.

Subject to the indemnification by Sellers under Section 11.5 and Purchaser’s rights under (a) any title indemnity agreement entered into by the Parties pursuant to this Agreement and (b) the special warranty of title contained in the Conveyances, from and after the Closing Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) (i) all of the following obligations and liabilities of each Seller, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time up to the Closing Date: (A) the obligation to furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (B) the obligation to pay the

holders of working interests, royalties, overriding royalties and other interests the Suspended Funds to which they are entitled (it being agreed that, notwithstanding anything in this Agreement to the contrary, subject to the provisions of Section 12.20 below, Purchaser shall be solely responsible for the distribution of all Suspended Funds transferred or credited to Purchaser pursuant hereto, and that Purchaser's obligations relating thereto shall be limited to the Suspended Funds actually delivered by Sellers to Purchaser), (C) the obligation to properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (D) the obligation to replug any well, wellbore, or previously plugged well on the Properties to the extent required by any Governmental Body, (E) the obligation to dismantle, salvage and remove any equipment, structures, materials, flowlines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (F) the obligation to clean up, restore, remediate or otherwise respond to Hazardous Materials on, at or migrating from the premises covered by or included in the Assets in accordance with applicable Contracts and Laws, to comply with Laws concerning Hazardous Materials and Environmental Liabilities related to the Assets, and to discharge all other Environmental Liabilities, and (G) the obligation to perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and related joint operating agreements, or as required by applicable Laws or applicable Contracts. All of such duties, obligations, responsibilities, and liabilities to be assumed by Purchaser with respect to the Oil and Gas Assets and Midstream Assets shall be referred to herein as the "Assumed Oil and Gas Obligations" and the "Assumed Midstream Obligations," respectively (collectively, the "Assumed Seller Obligations"). Notwithstanding the terms of Section 11.3 to the contrary, the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities to the extent that they are (such excluded obligations and liabilities, the "Excluded Seller Obligations"):

(A) attributable to, or arise out of, the ownership, use or operation of the Excluded Assets;

(B) the continuing responsibility of Sellers under Section 11.1 or Section 11.2;

(C) Property Costs for which any Seller is responsible pursuant to Section 1.4(b); and

(D) attributable to, or arise out of, the Retained Liabilities.



(a) The representations and warranties contained in Article 5 and Article 6 (other than the Fundamental Representations and the Tax Representations) shall terminate 12 months after Closing (the “Survival Date”). The representations and warranties contained in Section 5.2, Section 5.3, Section 5.4, Section 5.6, Section 6.1, Section 6.2, Section 6.3, and Section 6.5(collectively, the “Fundamental Representations”) shall survive the Closing without time limit, and the representations and warranties of Sellers contained in Section 5.8 and Section 5.19 shall survive the Closing until the expiration of the applicable Tax statute of limitations period plus 30 days (collectively, the “Tax Representations”). Upon the termination of a representation or warranty in accordance with the foregoing, such representation or warranty shall have no further force or effect for any purpose under this Agreement; provided

that, subject to Section 11.4(b), there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation or warranty prior to its expiration date. The covenants and other agreements of each Seller set forth in Section 7.6 shall survive the Closing Date and delivery and recordation of the Conveyances hereunder until the Survival Date. All other covenants and other agreements of each Seller and Purchaser set forth in this Agreement shall survive the Closing without time limit. The indemnities in Section 11.5(a) and Section 11.6(a) shall terminate as of the termination date of each respective representation or warranty that is subject to indemnification. Subject to Section 11.4(b), there shall be no termination of a bona fide claim asserted pursuant to the indemnities prior to the date of termination for such indemnity.

(b) No Party shall have any indemnification obligation pursuant to this Article 11 or otherwise in respect of any representation, warranty, covenant or agreement unless it shall have received from the Party seeking indemnification a written notice (a “Claim Notice”) of the existence of the claim for or in respect of which indemnification in respect of such representation, warranty, covenant or agreement is being sought. A Claim Notice in respect of a representation or warranty must be delivered on or before the expiration of the applicable survival period set forth in Section 11.4(a). If an Indemnified Party delivers a Claim Notice in respect of a representation or warranty to an Indemnifying Party before the expiration of the applicable survival period set forth in Section 11.4(a), then the applicable representation or warranty shall survive until, but only for purposes of, the resolution of the matter covered by such Claim Notice. A Claim Notice shall set forth with reasonable specificity (i) the basis for such claim under this Agreement, and the facts that otherwise form the basis of such claim and (ii) to the extent reasonably estimable, an estimate of the amount of such claim (which estimate shall not be conclusive of the final amount of such claim) and an explanation of the calculation of such estimate. Without limitation of the foregoing, Sellers agree and acknowledge that Purchaser shall, prior to Closing, be entitled to deliver a Claim Notice if one or more of the representations and warranties of Sellers contained in Article 5 is not true and correct as of the Closing Date (such a claim, a “Pre-Closing Indemnity Claim”).

(c) No Party shall have any liability for any indemnification under Section 11.5(a) and/or Section 11.6(a) of this Agreement, as applicable (except for breaches of Fundamental Representations and Tax Representations), until and unless (i) the amount of the Loss for any individual claim or series of claims arising out of the same or similar set of facts, for which a Claim Notice is delivered by Purchaser or Sellers, as applicable, and for which the Indemnifying Party is liable, exceeds $100,000 (“Individual Indemnity Threshold”), and (ii) the aggregate amount of the Losses for all claims for which Claim Notices are delivered by Purchaser or Seller, as applicable, and for which the Indemnifying Party is liable under this Agreement after application of the provisions of clause (i) above, exceeds 1.25% of the Purchase Price, and then only to the extent such damages exceed 1.25% of the Purchase Price (the “Aggregate Indemnity Deductible”); provided that:

(A) Sellers’ indemnities in Section 11.5(a) (with respect to the Fundamental Representations and Tax Representations) and any other provision of Section 11.5 shall not be limited by this Section 11.4(c);

(B) Purchaser’s indemnities in Section 11.6(a) (with respect to the Fundamental Representations only) and any other provision of Section 11.6 shall not be limited by this Section 11.4(c); and

(C) Sellers’ indemnities in Section 11.5(a) which relate to a Pre-Closing Indemnity Claim shall not be limited by this Section 11.4(c).

In addition, Sellers’ indemnities in Section 11.5(c) (with respect to Production Payments only) shall be subject to the Individual Indemnity Threshold, but shall not be subject to the Aggregate Indemnity Deductible. For the avoidance of doubt, claims for which Claim Notices are delivered by Purchaser or Sellers, as applicable, which do not meet the Individual Indemnity Threshold shall not be included in reaching the Aggregate Indemnity Deductible. For purposes of determining whether there has been a breach of any of Sellers’ representations and warranties for which Purchaser is entitled to indemnification under Section 11.5(a) and the Losses resulting from any such breach, any dollar or materiality qualifies in Sellers’ representations and warranties shall be disregarded.

(d) Except as expressly provided elsewhere in this Agreement, Sellers shall not be required to indemnify Purchaser pursuant to Section 11.5(a) (except with respect to breaches of Fundamental Representations and Tax Representations) for aggregate Losses in excess of 20% of the Purchase Price. Except as expressly provided elsewhere in this Agreement, Sellers shall not be required to indemnify Purchaser pursuant to Section 11.5(a) for aggregate Losses attributable to breaches of Fundamental Representations in excess of 100% of the Purchase Price.

(e) Absent fraud, the sole and exclusive remedy of the Parties with respect to the Assets and the transactions contemplated hereby shall be pursuant to the express provisions of this Agreement (including pursuant to this Section 11.4(e)) and any agreement delivered between the Parties at Closing (including any title indemnity agreement entered into by the Parties pursuant to this Agreement and the Conveyances). Without limitation of the foregoing, absent fraud and except with respect to (i) Purchaser’s rights with respect to the special warranty of title contained in the Conveyances and (ii) any claims or Losses attributable to any breach by Purchaser or Sellers (as applicable) of any of the provisions of Section 1.5, Section 3.7(b), Section 7.5, Section 7.7, Section 7.8, Section 7.9, Section 7.11, Section 9.4, Section 11.1 and Section 11.2 (each, a “Specified Covenant”), if the Closing occurs, the sole and exclusive remedy of the Parties for any and all (A) claims relating to any representations, warranties, covenants and agreements that are contained in this Agreement or in any certificate delivered at Closing, (B) other claims pursuant to or in connection with this Agreement and (C) other claims relating to the Assets and the purchase and sale thereof, shall be any right to indemnification from such claims that is expressly provided in



this Agreement and any other agreement delivered between the Parties at Closing and, and if no such right of indemnification is expressly provided, then such claims are hereby waived to the fullest extent permitted by Law. In the event of any breach by a Party of any of the provisions of any Specified Covenant, the non-breaching Party(ies), in addition to any rights of indemnification set forth herein or in any agreement delivered between the Parties at Closing, shall have all rights at Law or in equity with respect to or on account of such breach, including the right to seek specific

performance and injunctive relief (without the necessity of posting any bond in connection therewith).

## Section 11.5. Indemnification by Each Seller.

Subject to the terms, conditions, and limitations of this Article 11, from and after the Closing, Sellers are responsible for, shall pay on a current basis and hereby jointly and severally indemnify, defend and hold harmless Purchaser and its Affiliates, and its and their respective directors, officers, employees, members, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (collectively, the "Purchaser Indemnified Persons"), from and against any and all Losses asserted against, resulting from, imposed upon, or incurred or suffered by any Purchaser Indemnified Person, directly or indirectly, to the extent resulting from, arising out of or relating to:

(a) any breach of any representation or warranty of a Seller contained in this Agreement or in any certificate furnished by or on behalf of a Seller in connection with this Agreement;

(b) any breach or nonfulfillment of or failure to perform any covenant or agreement of a Seller contained in this Agreement or in any certificate furnished by or on behalf of a Seller in connection with this Agreement;

(c) the Retained Liabilities; and

(d) the Excluded Seller Obligations, REGARDLESS OF FAULT.

## Section 11.6. Indemnification by Purchaser.

From and after the Closing, subject to the terms and conditions of this Article 11 and Sellers' indemnity obligations under Section 11.5, Purchaser shall indemnify, defend and hold harmless each Seller, its Affiliates and its and their directors, officers, employees, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (collectively, the "Seller Indemnified Persons"), from and against any and all Losses, asserted against, resulting from, imposed upon, or incurred or suffered by any Seller Indemnified Person, directly or indirectly, to the extent resulting from, arising out of, or relating to:

(a) any breach of any representation or warranty of Purchaser contained in this Agreement or in any certificate furnished by or on behalf of Purchaser to Sellers in connection with this Agreement;

(b) any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement or any certificate furnished by or on behalf of Purchaser to Sellers in connection with this Agreement;

(c) the Assumed Seller Obligations, REGARDLESS OF FAULT; and

(d) the indemnity obligations set forth in Section 4.4;

but excepting, in each case, Losses with respect to which Sellers are required to indemnify Purchaser and the Purchaser Indemnified Persons pursuant to Section 11.5 or otherwise pursuant to this Agreement or any document or agreement executed in connection herewith.

## Section 11.7. Indemnification Proceedings.

(a) In the event that any claim or demand for which Sellers or Purchaser (in each case, as applicable, an “Indemnifying Party”) may be liable to a Purchaser Indemnified Person under Section 11.5 or to a Seller Indemnified Person under Section 11.6 (as applicable, an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by an un-Affiliated third party (a “Third Party Claim”), the Indemnified Party shall with reasonable promptness after the Indemnified Party has Actual Knowledge of the Third Party Claim notify the Indemnifying Party of such Third Party Claim by delivery of a Claim Notice and a copy of all papers (if any) served with respect to such Third Party Claim, provided that, the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11, except to the extent that the Indemnifying Party demonstrates (to the reasonable satisfaction of the Indemnified Party) that (i) it had insufficient time available to permit such Indemnifying Party to effectively defend against the Third Party Claim or (ii) its defense of such Third Party Claim is otherwise materially prejudiced by such failure or delay. In the case of a claim for indemnification based on a Third Party Claim, the Indemnifying Party shall have 30 days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.7, the “Notice Period”) to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Party.

(b) Subject to Section 11.7(d), the Indemnifying Party shall have the right to assume the defense of such Third Party Claim (at its sole cost and expense) only if and for so long as the Indemnifying Party (i) notifies the Indemnified Party during the Notice Period that the Indemnifying Party is assuming the defense of such Third Party Claim, (ii) uses counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conducts the



defense of such Third Party Claim in an active and diligent manner. If the Indemnifying Party is entitled to, and does, assume the defense of any such Third Party Claim, the Indemnified Party agrees to cooperate in contesting any such Third Party Claim to the extent such cooperation is so requested by the Indemnifying Party, and, further, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however, that notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys' fees of the Indemnified Party if the Indemnified Party's counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to have common counsel for the Indemnifying Party and the Indemnified Party it being understood and agreed, however, that the Indemnifying Party shall not be responsible for paying for more than one separate firm

of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Third Party Claim.

(c) If the Indemnifying Party elects (and is entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Party without the Indemnified Party's written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld, conditioned or delayed). If the Indemnifying Party elects not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period, otherwise is not entitled to assume such defense or fails to diligently prosecute or settle the Third Party Claim), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Party; provided, however, that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any Indemnifying Party without the prior written consent of such Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed.

(d) Notwithstanding the foregoing, (except with respect to the matters on Schedule 5.7(a) for which Sellers have indemnified Purchaser) the Indemnifying Party shall not be entitled to control the defense of (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party shall be entitled to have sole control over the defense, settlement, compromise, admission or acknowledgment of any Third Party Claim if (i) the Indemnified Person has been advised by counsel that an actual conflict of interest exists between the Indemnifying Party and the Indemnified Party in connection with the defense of such Third Party Claim, (ii) the Third Party Claim, individually or in the aggregate with any other claim, involves potential Losses that exceed the amount of the indemnification available under this Agreement, (iii) the Third Party Claim seeks injunctive relief or is part of a criminal proceeding or (iv) the Third Party Claim would reasonably be expected to have a material adverse effect on the Indemnified Person's business or relates to its customers, suppliers, vendors or other service providers; provided, however, in the event that the Indemnifying Party is not entitled to assume exclusive control of the defense, then the Indemnifying Party shall not be bound by any determination resulting from any compromise or settlement effected without its consent (which may not be unreasonably withheld, conditioned or delayed).

(e) Subject to Section 11.4(b), in any case in which an Indemnified Party seeks indemnification hereunder and no Third Party Claim is involved, the Indemnified Party shall deliver a Claim Notice to the Indemnifying Party within a reasonably prompt period of time after an officer of such Indemnified Party or its Affiliates has obtained actual knowledge of the Loss giving rise to indemnification hereunder. Except as otherwise expressly provided in Section 11.4(b), the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 except to the extent such failure

results in insufficient time being available to permit the Indemnifying Party to effectively mitigate the resulting Losses or otherwise prejudices the Indemnifying Party. In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to (i) cure the Losses complained of, (ii) admit its obligation to indemnify for and bear all expenses associated with such Losses or (iii) dispute the claim for such Losses. If the Indemnifying Party does not notify the Indemnified Party within such 30 day period that it has cured the subject Losses or that it disputes the claim for such Losses, the amount of such Losses shall conclusively be deemed a liability of the Indemnifying Party hereunder.

Section 11.8. Release.

EXCEPT WITH RESPECT TO (A) POST-CLOSING REMEDIATION AGREED TO PURSUANT TO SECTION 4.3 AND (B) PURCHASER'S REMEDIES UNDER SECTION 11.5, PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHETHER NOW EXISTING OR ARISING IN THE FUTURE, CONTINGENT OR OTHERWISE, WHICH PURCHASER MIGHT NOW OR SUBSEQUENTLY MAY HAVE AGAINST THE SELLER INDEMNIFIED PERSONS, RELATING TO OR ARISING OUT OF (I) THE VIOLATION OF ANY ENVIRONMENTAL LAWS WITH RESPECT TO THE ASSETS, (II) ANY ENVIRONMENTAL LIABILITIES WITH RESPECT TO THE ASSETS, (III) ANY ENVIRONMENTAL DEFECTS, (IV) THE RELEASE OF MATERIALS INTO THE ENVIRONMENT WITH RESPECT TO THE ASSETS OR THE PROTECTION OF NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT.

Section 11.9. Disclaimers.

(a) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCES, (I) SELLERS MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLERS EXPRESSLY DISCLAIM ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY



OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLERS OR ANY OF THEIR RESPECTIVE AFFILIATES).

(b) EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5 OF THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCES, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, EACH SELLER EXPRESSLY

DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLERS OR ANY THIRD PARTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, (IX) REDHIBITORY, PATENT OR LATENT DEFECTS, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, "AS IS" AND "WHERE IS" WITH ALL FAULTS AND THAT PURCHASER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE, OR (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c) OTHER THAN AS SET FORTH IN SECTION 5.9, SELLERS HAVE NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS "AS IS" AND "WHERE IS" FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

Section 11.10. Recording.

(a) As soon as practicable after Closing, Purchaser shall record the Conveyances in the appropriate counties where the Oil and Gas Properties and the Surface Rights are located and provide each Seller with copies of all recorded or approved instruments. The Conveyances

in the form attached as Exhibit B-1 and Exhibit B-2 are intended to convey all of the Oil and Gas Properties and Surface Rights being conveyed pursuant to this Agreement. Certain Oil and Gas Properties and Surface Rights or specific portions of the Oil and Gas Properties and Surface Rights that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyances and also are described and covered under separate assignments made by Sellers to Purchaser on officially approved forms, in sufficient multiple originals to satisfy applicable statutory and regulatory requirements. The interests conveyed by such separate assignments are the same, and not in addition to, the interests conveyed in the Conveyances attached as Exhibit B-1 and Exhibit B-2. Further, such assignments shall be deemed to contain all of the exceptions, reservations, rights, titles, power and privileges set forth herein and in the Conveyances as fully and only to the extent as though they were set forth in each such separate assignment.

## Section 11.11. Certain Indemnification Amounts for Matters on Schedule 5.7(a).

In the event of a settlement or determination by a court of competent jurisdiction, tribunal, arbitration or mediation of any of the matters set forth on Schedule 5.7(a) that causes Purchaser (as Sellers' successor in interest) to not have Defensible Title with respect to any Unit, Well or other Asset as set forth in Exhibit A-1, then Purchaser's Losses for diminution in value of such Unit, Well or other Asset shall be determined by application of the provisions of Section 3.4(g) and Section 3.4(h) as the sole method of calculating Purchaser's Losses for such diminution in value; provided, that (a) if in connection with not having Defensible Title with respect to such Unit, Well or other Asset, Purchaser is entitled to receive a cash payment from a third party in connection with such third party's acquisition of a working interest in a Well or Lease, then to the extent Purchaser actually receives such amount or recovers such amount by setting off against amounts due and payable from Purchaser to such third party, the amount of Purchaser's Losses shall be so reduced, and (b) such calculation of Losses shall not be limited by the Individual Title Threshold or the Aggregate Defect Deductible. For purposes of clarity and by way of example, if it is determined that a third party owns a working interest in a currently producing Well and such determination results in Purchaser (as Sellers' successor in interest) having a lesser Net Revenue Interest in such Well than set forth in Exhibit A-1, then the amount of Purchaser's Losses for diminution in value with respect to such Well would be determined in accordance with Section 3.4(g) and Section 3.4(h), but would be reduced by the amount, if any, of such third party's pro rata portion of drilling, completion and other operation costs attributable to such Well that (i) such third party pays to Purchaser in order to participate as a working interest owner in such Well or (ii) Purchaser actually recovers by setting off against amounts otherwise payable from Purchaser to such third party.



This Agreement may be executed and delivered (including by facsimile or email transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

## Section 12.2. Notice.

All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by overnight courier service, by electronic mail, or by registered or certified mail, postage prepaid, as follows:

If to Sellers or Seller Representative:

Halcón Resources Corporation
1000 Louisiana, Suite 6700
Houston, Texas 77002
Attention: Steve Herod
Phone: 832-538-0506
Email: sherod@halconresources.com

and

Halcón Resources Corporation
1000 Louisiana, Suite 6700
Houston, Texas 77002
Attention: David Elkouri
Phone: 832-538-0514
Email: delkouri@halconresources.com

If to Purchaser:

Hawkwood Energy, LLC
4582 S. Ulster St. Parkway, Suite 500
Denver, CO 80237
Attention: Patrick R. Oenbring
Phone: 303-823-4175 x400
Email: patrick.oenbring@hawkwoodenergy.com

With a copy to (which shall not constitute notice to Purchaser):

Jones Day
717 Texas St., Suite 3300
Houston, TX 77008
Attention: Omar Samji
Phone: 832-239-3639
Email: osamji@jonesday.com

Each Party may change its address for notice by notice to the other in the manner set forth above. All notices shall be deemed to have been duly given at the time of receipt by the Party to which such notice is addressed.

## Section 12.3. Sales or Use Tax Recording Fees and Similar Taxes and Fees.

Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees (collectively “Transfer Taxes”) incurred and imposed upon, or with respect to, the transactions contemplated by this Agreement. Purchaser will determine the amount of any Transfer Taxes, if any, that is due in connection with the transactions contemplated by this Agreement and Purchaser agrees to pay any such Transfer Tax to the appropriate Governmental Body. If any of the transactions contemplated by this Agreement are exempt from any such Transfer Taxes upon the filing of an appropriate certificate or other evidence of exemption, Purchaser will timely furnish to Sellers such certificate or evidence.

## Section 12.4. Expenses.

Except as otherwise expressly provided in Section 12.3 or elsewhere in this Agreement, (a) all expenses incurred by Sellers in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyances delivered hereunder and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, all fees and expenses of counsel, accountants and financial advisers employed by Sellers, shall be borne solely and entirely by Sellers, and (b) all such expenses incurred by Purchaser and all other fees and expenses relating to the registration of title to the Assets after Closing shall be borne solely and entirely by Purchaser.

## Section 12.5. Change of Name.

As promptly as practicable, but in any case within 60 days after the Closing Date, Purchaser shall eliminate the names “Halcón”, “HK”, “HRC”, “HFS” and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Sellers or any of their Affiliates.



## Section 12.6. Replacement of Bonds, Letters of Credit and Guarantees.

The Parties understand that none of the Bonds, if any, posted by Sellers or any of their Affiliates with Governmental Bodies and relating to the Assets may be transferable to Purchaser. Except as provided in Section 7.4(c), prior to Closing, Purchaser shall have obtained, or caused to be obtained in the name of Purchaser, replacements for such Bonds, to the extent such replacements are necessary to permit the cancellation of such Bonds posted by Sellers or any of their Affiliates or to consummate the transactions contemplated by this Agreement.

## Section 12.7. Governing Law and Venue.

(a) THIS AGREEMENT AND THE LEGAL RELATIONS AMONG THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS. JURISDICTION AND VENUE WITH RESPECT TO ANY DISPUTES ARISING HEREUNDER (EXCEPT FOR DISPUTES REQUIRED TO BE DETERMINED UNDER SECTION 3.4(k), SECTIONS 4.3(b) AND (c) AND SECTION 9.4) SHALL BE PROPER ONLY IN HARRIS COUNTY, TEXAS. EACH PARTY WAIVES, TO THE FULLEST

## EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY DISPUTE.

(b) Notwithstanding anything contrary in this Agreement, each of the Parties agrees that it will not bring or support, nor will it permit any of its Affiliates, equityholders, members, partners, officers, directors, employees, agents, advisors and representatives to bring or support, any action, cause of action, claim, cross-claim or third party claim of any kind or description, whether in law or in equity, whether in contract or in tort or otherwise, against the Lenders in any way relating to this Agreement or any of the transactions contemplated by this Agreement, including any dispute arising out of or relating in any way to the Commitment Letter, the Definitive Debt Agreements or the performance thereof, in any forum other than the Supreme Court of the State of New York, County of New York, or, if under applicable Law exclusive jurisdiction is vested in the federal courts, the United States District Court for the Southern District of New York located in the Borough of Manhattan (and appellate courts thereof). The Parties hereto further agree that all of the provisions of Section 12.7(a) relating to waiver of jury trial shall apply to any action, cause of action, claim, cross-claim or third party-claim referenced in this Section 12.7(b). Notwithstanding anything to the contrary contained in this Agreement, the Lenders are intended third party beneficiaries of, and shall be entitled to the protections of, this Section 12.7(b), and this Section 12.7(b) may not be amended, supplemented, waived or otherwise modified in a manner adverse to the Lenders without the prior written consent of the Lenders.

## Section 12.8. Captions.

The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

## Section 12.9. Waivers.

Any failure by any Party or Parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the Party or Parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

## Section 12.10. Assignment.

Subject to the provisions of Section 7.8(d), no Party shall assign all or any part of this Agreement, nor shall any Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other Party, which shall not be unreasonably withheld, conditioned or delayed, except that Purchaser may assign any of its rights and obligations hereunder to one or more of its Affiliates without the consent of any other Party. No assignment hereunder by any Party shall relieve such Party of any obligations and responsibilities hereunder. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns.

## Section 12.11. Entire Agreement.

The Confidentiality Agreement, this Agreement and the Exhibits and Schedules attached hereto, and the documents to be executed hereunder constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof.

## Section 12.12. Amendment.

(a) This Agreement may be amended or modified only by an agreement in writing executed by the Parties.

(b) No waiver of any right under this Agreement shall be binding unless executed in writing by the Party to be bound thereby.

## Section 12.13. No Third-Party Beneficiaries.

Nothing in this Agreement shall entitle any Person other than Purchaser or Sellers to any claims, remedy or right of any kind, except as to those rights expressly provided to the Seller Indemnified Persons and Purchaser Indemnified Persons (provided, however, any claim for indemnity hereunder on behalf of



an Seller Indemnified Person or an Purchaser Indemnified Person may only be made and administered by a Party).

## Section 12.14. References.

In this Agreement:

(a) References to any gender includes a reference to all other genders;

(b) References to the singular includes the plural, and vice versa;

(c) Reference to any Article or Section means an Article or Section of this Agreement;

(d) Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e) Unless expressly provided to the contrary, “hereunder”, “hereof”, “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement;

(f) “for example,” “include” and “including” mean include or including, as applicable, without limitation; and

(g) Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the Definitions section hereof.

## Section 12.15. Construction.

Purchaser is a Party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent Party would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability. Each Seller and Purchaser has had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions. In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against either Party.

## Section 12.16. Conspicuousness.

The Parties agree that provisions in this Agreement in “bold” and/or “ALL CAPS” type satisfy any requirements of the “express negligence rule” and any other requirements at law or in equity that provisions be conspicuously marked or highlighted.

## Section 12.17. Severability.

If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any materially adverse manner with respect to either Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

## Section 12.18. Time of Essence.

Time is of the essence in this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

## Section 12.19. Limitation on Damages.

Notwithstanding any other provision contained elsewhere in this Agreement to the contrary, the Parties acknowledge that this Agreement does not authorize one Party to sue for or collect from the other Party its own punitive damages, or its own special, punitive, exemplary, consequential or indirect damages or loss of profits in connection with this Agreement and the transactions contemplated hereby and each Party expressly waives for itself and on behalf of its Affiliates, any and all claims it may have against the other Party for its own such damages in connection with this Agreement and the transactions contemplated hereby. This Section 12.19 shall not restrict any Party’s right to obtain specific performance or other equitable remedies (other than rescission) to the extent permitted under Section 10.2 and Section 11.4(e).

## Section 12.20. Suspended Funds.

Sellers covenant to deliver to Purchaser, within 30 days after Closing, in Microsoft Excel format, the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of Suspended Funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries. Upon receipt of such information, Purchaser shall administer all such accounts and distribute such Suspended Funds in accordance with all applicable Laws to the proper parties.



The representations, warranties and covenants made by (and the obligations of) Sellers in and under this Agreement are joint and several.

## Section 12.22. Seller Representative.

For purposes of this Agreement, each Seller, without any further action, shall be deemed to have consented to the appointment of Halcon Energy Properties, Inc. as its representative (in such capacity, the "Seller Representative"), as the attorney-in-fact for and on behalf of such Seller, with respect to the exercise of any decision, right, consent, election or other action that such Seller is required or permitted to make or take under the terms of this Agreement (the "Delegated Matters") and Purchaser may rely on the decisions of Seller Representative with respect to all Delegated Matters. For the avoidance of doubt, notwithstanding anything to the contrary herein, Sellers will be treated as a single Party for purposes of any notice, election, exercise of a right, consent or similar action to be made by Sellers under this Agreement. The Parties further acknowledge that Purchaser shall have no responsibility to determine the portion of the Purchase Price or Adjusted Purchase Price to be paid to any Seller and shall be entitled to rely on the Preliminary Settlement Statement and Final Settlement Statement, as well as instructions by the Seller Representative as to the portion of the Purchase Price or Adjusted Purchase Price payable to any Seller hereunder.

## Section 12.23. No Recourse.

Notwithstanding anything in this Agreement to the contrary, the Parties acknowledge and agree that no past, present, or future director, manager, officer, employee, incorporator, member, partner, stockholder, agent, attorney, representative, Affiliate (excluding the Purchaser and any Person to which Purchaser subsequently assigns this Agreement or the Assets), or financing source (including, without limitation, Warburg Pincus LLC, Ontario Teachers' Pension Plan Board, and their respective past, present, or future directors, managers, officers, employees, incorporators, members, partners, stockholders, agents, attorneys, representatives, Affiliates (excluding the Purchaser and any Person to which Purchaser subsequently assigns this Agreement or the Assets), or financing sources) of the Purchaser (each, a "Non-Recourse Person"), in such capacity, shall have any liability or responsibility (in contract, tort, or otherwise) for any damages, losses, obligations, liabilities, penalties, interest obligations, expenses, costs, claims, demands, charges, suits, legal or administrative proceedings, or other causes of action whatsoever, in law or in equity, known or unknown, which are based on, related to, or arise out of the negotiation, performance, or consummation of this Agreement or the other

agreements, instruments or documents contemplated hereby or the transactions contemplated hereunder or thereunder. This Agreement may only be enforced against, and any dispute, controversy, matter, or claim based on, related to, or arising out of this Agreement, or the negotiation, performance, or consummation of this Agreement, may only be brought against the Persons that are expressly named as Parties (or to Persons to which a named Party subsequently assigns this Agreement or the Assets to), and then only with respect to the specific obligations set forth herein with respect to such Party. Each Non-Recourse Person is expressly intended as a third party beneficiary of this provision.

## Section 12.24. Lender Liability.

Notwithstanding anything to the contrary contained in this Agreement, each of the Parties: (i) agrees that all claims, whether in law or in equity, whether in contract or in tort or otherwise, against any lender party with respect to the Debt Financing (the "Lenders") (which defined term shall include the Lenders and their respective Affiliates, equityholders, members, partners, officers, directors, employees, agents, advisors and representatives involved in the Debt Financing) in any way relating to this Agreement or transactions contemplated thereby, including any dispute arising out of or relating in any way to the Commitment Letter, the Debt Financing, the Definitive Debt Agreements or the performance thereof, shall be brought only in the forum set forth in Section 12.7(b); (ii) agrees that all claims or causes of action (whether at law, in equity, in contract, in tort or otherwise) against any of the Lenders in any way relating to the Debt Financing or the performance thereof, shall be governed by, and construed in accordance with, the Laws of the State of New York, without regard to Laws that may be applicable under conflicts of Laws principles (whether of the State of New York or any other jurisdiction) that would cause the application of the Law of any jurisdiction other than the State of New York; and (iii) HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THE DEBT FINANCING OR THE PERFORMANCE THEREOF. Notwithstanding anything to the contrary contained in this Agreement, (A) no Seller, in its capacity as a party to this Agreement, or its Affiliates, directors, officers, employees, agents, partners, managers, members or shareholders shall have any rights or claims against any Lender, relating to this Agreement, the Commitment Letter, the Definitive Debt Agreements, or any of the transactions contemplated hereby or thereby or the performance hereof or thereof, whether at law or equity, in contract, in tort or otherwise and (B) no Lender shall have any liability to any of the Sellers or their respective Affiliates, directors, officers, employees, agents, partners, managers, members or shareholders relating to this Agreement, the Commitment Letter, the Definitive Debt Agreements, or any of the transactions contemplated hereby or thereby or the performance hereof or thereof, whether at law or equity, in contract, in tort or otherwise; provided, however, that the Parties agree and acknowledge that in no event shall any Seller have the right to specifically enforce the Commitment Letter in connection with the Debt Financing or to cause Purchaser to enforce the Commitment Letter to cause the Lender to consummate the Debt Financing. Notwithstanding anything to the contrary contained in this Agreement, the Lenders are intended third party beneficiaries of, and shall be entitled to the protections of, this Section 12.24, and this Section 12.24 may not be amended, supplemented, waived or otherwise modified in a manner adverse to the Lenders without the prior written consent of the Lenders.

## DEFINITIONS

“Actual Knowledge” has the meaning set forth in Section 5.1.

“Adjusted Purchase Price” shall mean the Purchase Price after calculating and applying the adjustments set forth in Section 2.2.



“Adjustment Period” has the meaning set forth in Section 2.2(a).

“AEA” has the meaning set forth in the definition of Environmental Laws.

“AFE” means authority for expenditure.

“Affiliates” with respect to any Person, means any Person that directly or indirectly controls, is controlled by or is under common control with such Person. The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.

“Aggregate Benefit Deductible” has the meaning set forth in Section 3.4(m).

“Aggregate Defect Deductible” has the meaning set forth in Section 3.4(l).

“Aggregate Indemnity Deductible” has the meaning set forth in Section 11.4(c).

“Agreed Accounting Firm” has the meaning set forth in Section 9.4(c).

“Agreement” means this Agreement of Sale and Purchase.

“Allocated Value” has the meaning set forth in Section 2.3.

“Applicable Date” means, with respect to any Title Defect, Environmental Defect, Title Defect Amount, Environmental Defect Amount or the cure of any such defect, if (a) Section 3.4(k)(ii) or Section 4.3(b)(ii) applies in connection with the applicable Title Defect or Environmental Defect, the Scheduled Closing Date and (b) if Section 3.4(k)(iii) or Section 4.3(b)(iii) applies in connection with the applicable Title Defect or Environmental Defect, the Closing Date, or (c) if Section 3.4(k)(iv) applies in connection with the applicable Title Defect, the date of the receipt by Purchaser of curative documents relating to such Title Defect from Sellers.

“Acquisition Area” has the meaning set forth in Section 1.2(c).

“Assets” has the meaning set forth in Section 1.2.

“Assumed Midstream Obligations” has the meaning set forth in Section 11.3.

“Assumed Oil and Gas Obligations” has the meaning set forth in Section 11.3.

“Assumed Seller Obligations” has the meaning set forth in Section 11.3.

“Benefit Plan” means each (a) “employee benefit plan,” as such term is defined in Section 3(3) of ERISA (whether or not the plan is subject to ERISA), including each “defined benefit plan” as defined in Section 3(35) of ERISA, pension plan subject to the funding standards of Section 302 of ERISA or Section 412 of the Code, “multiemployer plan” as defined in Section 3(37) of ERISA or Section 414(f) of the Code and “multiple employer plan” within the meaning of Section 210(a) of ERISA or Section 413(c) of the Code, (b) incentive compensation, bonus, profit sharing, equity-based compensation, retirement, pension, deferred compensation, medical benefit, dental benefit, vision benefit, disability benefit, life insurance, severance, retention, change in control plan, paid time off, fringe benefit or other compensatory plan, arrangement, policy or commitment and (c) each employment agreement, offer letter or consulting agreement that provides for the employment of an individual other than on an at-will basis or for service as an independent contractor other than on a basis that is terminable with less than two weeks notice.

“Business Day” means each calendar day except Saturdays, Sundays, and federal holidays.

“CERCLA” has the meaning set forth in the definition of Environmental Laws.

“Claim Notice” has the meaning set forth in Section 11.4(b).

“Closing” has the meaning set forth in Section 9.1(a).

“Closing Date” has the meaning set forth in Section 9.1(b).

“Closing Payment” has the meaning set forth in Section 9.4(a).

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Commitment Letter” means that certain commitment letter, dated as of the date hereof, among Wells Fargo Bank, National Association, Wells Fargo Securities, LLC, JPMorgan Chase Bank, N.A., BMO Harris Bank N.A., BMO Capital Markets Corp., and Natixis, New York Branch, including all exhibits, schedules, annexes and amendments to such agreement in effect as of the date of this Agreement.

“Confidentiality Agreement” has the meaning set forth in Section 7.1(a).

“Contracts” means, collectively, the Oil and Gas Contracts and the Midstream Contracts.



“Conveyances” has the meaning set forth in Section 3.1(b).

“COPAS” has the meaning set forth in Section 1.4(c).

“Cure Period” has the meaning set forth in Section 3.4(c).

“Debt Financing” means the debt financing to be provided by the Lenders pursuant to the Commitment Letter.

“Defensible Title” has the meaning set forth in Section 3.2.

“Definitive Debt Agreements” means the definitive documentation with respect to the Debt Financing contemplated by the Commitment Letter.

“Delegated Matters” has the meaning set forth in Section 12.22.

“Deposit” has the meaning set forth in Section 2.4.

“DOJ” means the Department of Justice.

“earned” has the meaning set forth in Section 1.4(c).

“Effective Time” has the meaning set forth in Section 1.4(a).

“Environmental Claim Date” has the meaning set forth in Section 4.3(a).

“Environmental Defect” has the meaning set forth in Section 4.3(a).

“Environmental Defect Amount” has the meaning set forth in Section 4.3(a)(iii).

“Environmental Defect Notice” has the meaning set forth in Section 4.3(a).

“Environmental Laws” means, as the same may have been amended, any federal, state or local Law relating to (a) the control of any potential pollutant or protection of the environment, including air, water or land, (b) the generation, handling, treatment, storage, disposal or transportation of Hazardous Materials or waste materials, (c) the regulation of or exposure to Hazardous Materials, (d) the cleanup, restoration, remediation of, or other environmental response to Hazardous Materials on, at, or migrating from, any property, or (e) responsibility for, response to, or restoration of damages (including natural resource damages) caused by Hazardous Materials, including the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq. (“CERCLA”); the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. (“RRCA”); the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq. the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq. (“AEA”); the Texas Solid Waste Disposal Act; and all applicable related Law, whether local, state, territorial, or national, of any Governmental Body having jurisdiction over the property in question addressing pollution or the environment and all regulations implementing the foregoing. The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Body pursuant to the foregoing.

“Environmental Liabilities” shall mean any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court

costs, attorneys' fees, and other liabilities incurred or imposed (a) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body, (in each case) to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets prior to the Closing or (b) pursuant to any claim or cause of action by a Governmental Body or other Person for damage to natural resources, remediation or response costs, (in each case) to the extent arising out of any alleged violation of, or any alleged remediation obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets prior to the Closing.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Escrow Agent” means JPMorgan Chase Bank, N.A.

“Escrow Agreement” means that certain Escrow Agreement of even date herewith, by and among Sellers, Purchaser and the Escrow Agent.

“Event” has the meaning set forth in the definition of Material Adverse Effect.

“Excluded Assets” has the meaning set forth in Section 1.3.

“Excluded Seller Obligations” has the meaning set forth in Section 11.3.



“Exchange” has the meaning set forth in Section 7.8(d).

“Field Employee” means an individual who is employed or otherwise engaged or retained by Sellers or an Affiliate of Sellers and whose job primarily involves performing field and/or operational services with respect to the Assets.

“Field Employee List” has the meaning set forth in Section 5.23.

“Final Purchase Price” has the meaning set forth in Section 9.4(b).

“Final Settlement Date” has the meaning set forth in Section 9.4(c).

“Final Settlement Statement” has the meaning set forth in Section 9.4(b).

“FTC” means the Federal Trade Commission.

“Fundamental Representations” has the meaning set forth in Section 11.4(a).

“GAAP” means generally accepted accounting principles in effect in the United States as amended from time to time, consistently applied throughout the periods involved.

“Gathering System” has the meaning set forth in Section 1.2(b)(i).

“Governmental Authorizations” has the meaning set forth in Section 5.12.

“Governmental Body” or “Governmental Bodies” means any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body, arbitrator or arbitration panel or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Material” means (a) any “hazardous substance,” as defined by CERCLA, (b) any “hazardous waste” or “solid waste,” in either case as defined by RCRA, and any analogous state statutes, and any regulations promulgated thereunder, (c) any solid, hazardous, dangerous or toxic chemical, material, waste or substance, within the meaning of and regulated by any applicable Environmental Laws, (d) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in the AEA and any amendments or authorizations thereof, (e) any regulated asbestos-containing materials in any form or condition, (f) any regulated polychlorinated biphenyls in any form or condition, and (g) petroleum, petroleum hydrocarbons or any fraction or byproducts thereof.

“Hydrocarbons” means oil, gas, casinghead gas, condensate, natural gas liquids, and other gaseous and liquid hydrocarbons or any combination thereof and sulphur and other minerals extracted from or produced with the foregoing.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether such over-production, under-production, over-delivery, under-delivery or similar imbalance arises at the wellhead or at any point of receipt into or any point of delivery from any pipeline, gathering system, transportation system, processing plant or other location.

“incurred” has the meaning set forth in Section 1.4(c).

“Indemnified Party” has the meaning set forth in Section 11.7(a).

“Indemnifying Party” has the meaning set forth in Section 11.7(a).

“Indemnity Agreement” has the meaning set forth in Section 3.4(d)(ii).

“Independent Expert” has the meaning set forth in Section 4.3(b)(i).

“Individual Indemnity Threshold” has the meaning set forth in Section 11.4(c).

“Individual Environmental Threshold” has the meaning set forth in Section 4.3(d).

“Individual Title Benefit Threshold” has the meaning set forth in Section 3.4(m).

“Individual Title Threshold” has the meaning set forth in Section 3.4(l).

“Lands” has the meaning set forth in Section 1.2(a)(i).



“Leases” has the meaning set forth in Section 1.2(a)(i).

“Leave” means any absence from active employment (other than due to vacation or jury duty) under any type of leave for which the Field Employee is entitled to reinstatement upon completion of the leave under the applicable leave policies of Sellers and their Affiliates or pursuant to applicable Laws.

“Lenders” has the meaning set forth in Section 12.24(a).

“Loss” or “Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding); however, excluding special, punitive, exemplary, consequential or indirect damages or loss of profits, except to the extent a Party is required to pay such damages to an un-Affiliated third party in connection with a matter for which such Party is entitled to indemnification under Article 11.

“Lowest Cost Response” means the response required or allowed under Environmental Laws that applicable Governmental Bodies, if any, are reasonably likely to approve and that timely addresses the condition present at the reasonable lowest cost (considered as a whole after taking into consideration any material negative impact such response may have on the operations of the relevant assets and any potential material additional costs or liabilities that may likely arise as a result of or in connection with such response) as compared to any other response that is required or allowed under Environmental Laws.

“Material Adverse Effect” means any change, inaccuracy, circumstance, effect, event, result, occurrence, condition or fact (each an “Event”) (whether or not (a) foreseeable or known as of the date of this Agreement or (b) covered by insurance) that has had, or could reasonably be expected to have, a material adverse effect on (i) the ownership, operation or value of the Assets, taken as a whole, or (ii) the ability of Sellers to consummate the transactions contemplated hereby. Excluded from such Events for the purposes of determining whether a “Material Adverse Effect” has occurred or could reasonably be expected to occur are (A) Events resulting from entering into this Agreement or the announcement of the transactions contemplated by this Agreement, (B) Events resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war or terrorist events, (C) Events that affect the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally (including changes in commodity prices or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally that do not have a disproportionate effect on the Assets), (D) any effect resulting from a change in Laws or regulatory policies, (E) matters that are cured by the Closing at no cost or liability to Purchaser and no material diminution in value of any affected Asset, and

(F) the depletion or watering out of any Well(s), collapsed casing or sand infiltration of any Well(s), drilling results of any Well(s), and/or the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

“Material Contracts” has the meaning set forth in Section 5.10.

“Maximum Upward Adjustment” has the meaning set forth in Section 3.4(n).

“Midstream Assets” has the meaning set forth in Section 1.2(b).

“Midstream Contracts” has the meaning set forth in Section 1.2(b)(v).

“Midstream Conveyance” has the meaning set forth in Section 3.1(b).

“Midstream Equipment” has the meaning set forth in Section 1.2(b)(viii).

“Midstream Records” has the meaning set forth in Section 1.2(b)(vii).

“Midstream Surface Rights” has the meaning set forth in Section 1.2(b)(ii).

“Negative Imbalance” shall mean, respectively as to each Oil and Gas Property and the Gathering System, and without duplication, the sum (expressed in mcf) of (a) the aggregate make-up, prepaid or other volumes of natural gas that a Seller was obligated, as of the Effective Time on account of prepayment, advance payment, take-or-pay, gas balancing or similar obligations, to deliver from an Oil and Gas Property after such Effective Time without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent such Seller will be entitled to receive partial payment therefor), and (b) the aggregate pipeline or processing plant overdelivery Imbalances for which a Seller is obligated to pay or deliver natural gas or cash to any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any Asset.

“Net Mineral Acres” means, for each Lease, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the interest in oil and gas covered by such Lease in such lands, multiplied by (c) Sellers’ aggregate undivided interest in such Lease insofar as it covers such lands (provided that if items (b) and/or (c) vary as to any tract or tracts of land covered by the Lease, a separate calculation shall be done for each such tract or tracts, as applicable).

“Net Revenue Interest” has the meaning set forth in Section 3.2 (a).

“Non-Recourse Person” has the meaning set forth in Section 12.23.

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.7(a).

“Offered Lease” has the meaning set forth in Section 1.2(c).



“Oil and Gas Contracts” has the meaning set forth in Section 1.2(a)(iv).

“Oil and Gas Conveyance” has the meaning set forth in Section 3.1(b).

“Oil and Gas Equipment” has the meaning set forth in Section 1.2(a)(vi).

“Oil and Gas Properties” has the meaning set forth in Section 1.2(a)(iii).

“Oil and Gas Records” has the meaning set forth in Section 1.2(a)(x).

“Oil and Gas Surface Rights” has the meaning set forth in Section 1.2(a)(v).

“Parties” means Sellers and Purchasers and a “Party” means either Sellers (collectively) or Purchaser.

“Permitted Encumbrances” has the meaning set forth in Section 3.3.

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Body or any other entity.

“Personal Property” means, collectively, the Oil and Gas Equipment, the Midstream Equipment and the Gathering System.

“Phase I” or “Phase I Assessment” has the meaning set forth in Section 4.1.

“Pre-Closing Indemnity Claim” has the meaning set forth in Section 11.4(b).

“Preference Property” has the meaning set forth in Section 7.7(b).

“Preference Right” means any right or agreement that enables any Person (other than Purchaser) to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (a) the sale, assignment or other transfer of any Asset or any interest therein or portion thereof or (b) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Preliminary Settlement Statement” has the meaning set forth in Section 9.4(a).

“Proceeding” or “Proceedings” has the meaning set forth in Section 5.7.

“Production Payments” has the meaning set forth in Section 5.1.

“Property Costs” has the meaning set forth in Section 1.4(d).

“Prorated Taxes” has the meaning set forth in Section 7.8(a).

“Purchase Price” has the meaning set forth in Section 2.1.

“Purchaser” has the meaning set forth in the preamble hereto.

“Purchaser Indemnified Persons” has the meaning set forth in Section 11.5.

“Purchaser’s knowledge” (and any similar knowledge qualification with respect to Purchaser) means matters within the Actual Knowledge of the officers and employees of Purchaser or its Affiliates identified on Schedule 5.1.

“Purchaser’s Representatives” has the meaning set forth in Section 7.1(a).

“Qualified Intermediary” has the meaning set forth in Section 7.8(d).

“RCRA” has the meaning set forth in the definition of Environmental Laws.

“Records” means, collectively, the Oil and Gas Records and the Midstream Records.

“REGARDLESS OF FAULT” MEANS WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY LOSS, EVEN THOUGH A LOSS IS CAUSED IN WHOLE OR IN PART BY:



THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), STRICT LIABILITY, OR OTHER FAULT OF ANY INDEMNIFIED PERSON; BUT SPECIFICALLY EXCLUDING THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PERSON; AND/OR

THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), GROSS NEGLIGENCE, STRICT LIABILITY, OR OTHER FAULT OF UN-AFFILIATED THIRD PARTIES, INCLUDING WILLFUL MISCONDUCT.

“Retained Asset” has the meaning set forth in Section 7.7(c).

“Retained Employee Liabilities” means any obligations, liabilities and Losses (a) as a result of actions taken by Sellers or their Affiliates arising under the Worker Adjustment Retraining Notification Act of 1988 or otherwise for severance, notice of termination pay or similar entitlements, (b) based upon, arising out of or otherwise with respect to the employment, potential employment, alleged employment or termination of any of the current or former employees, consultants or independent contractors of Sellers or their Affiliates, (c) with respect to employees of any Seller or an Affiliate of any Seller arising under any Seller Benefit Plan, or (d) arising under ERISA for which Purchaser may have any liability under ERISA with respect to the Assets or employees of any Seller or an Affiliate of any Seller as a result of the consummation of the transactions contemplated by this Agreement.

“Retained Liabilities” means (a) all obligations, liabilities and Losses to the extent that they are attributable to, or arise out of (i) the Retained Employee Liabilities, (ii) the actions, suits or proceedings, if any, set forth on (or required to be set forth on) Schedule 5.7(a), (iii) the disposal or transportation of any Hazardous Materials from the Assets attributable to the time prior to the Closing Date to any location not on the Assets, (iv) actual or claimed personal injury or death or property damage relating to the Assets or operations thereon and attributable to the

period of time prior to the Closing Date, (v) Production Payments relating to the Oil & Gas Assets and attributable to production prior to the Effective Time, and (vi) any indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bond, letter of credit or similar financial contract of any Seller or of any its Affiliates, (b) any liabilities or obligations of Sellers, or otherwise imposed on the Assets, in respect of any Tax, but excluding any ad valorem, property, production, severance or similar Taxes to the extent specifically allocated to Purchaser pursuant to Section 1.4 or Section 7.8, and any Transfer Taxes specifically allocated to Purchaser pursuant to Section 12.3, and (c) all obligations, liabilities, Losses, and/or Taxes related to any Excluded Asset.

“Scheduled Closing Date” has the meaning set forth in Section 9.1(a).

“SEC” means the U.S. Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Seller” and “Sellers” has the meaning set forth in the preamble hereto.

“Seller Benefit Plan” means each Benefit Plan for which Sellers or any of their Affiliates may have any liability, contingent or otherwise.

“Seller Indemnified Persons” has the meaning set forth in Section 11.6.

“Seller Operated Assets” means Assets operated by a Seller or an Affiliate of a Seller.

“Seller Representative” has the meaning set forth in Section 12.22.

“Sellers’ knowledge” (and any similar knowledge qualification with respect to Sellers) means matters within the Actual Knowledge of the officers and employees of any Seller or its Affiliates identified on Schedule 5.1, after due investigation, in their individual capacities and as officers and employees of any Seller or its Affiliates.

“Specified Covenant” has the meaning set forth in Section 11.4(e).

“Subject Representatives” has the meaning set forth in Section 1.5(a).

“Supplemental Acquisition Period” has the meaning set forth in Section 1.2(c).

“Supplemental Closing” has the meaning set forth in Section 1.2(c).

“Supplemental Closing Date” has the meaning set forth in Section 1.2(c).

“Supplemental Properties” has the meaning set forth in Section 1.2(c).

“Surface Rights” means, collectively, the Oil and Gas Surface Rights and the Midstream Surface Rights.



being held in suspense pursuant to Texas Natural Resources Code § 91.402 or (b) are payable with respect to such production within the last twelve months but have not yet been paid, but such term shall not include (i) any cash, proceeds, or accounts related to or holding any abandoned or unclaimed property reportable under or subject to any state or local unclaimed property, escheat or similar Law where the dormancy period elapsed prior to the Effective Time or (ii) solely for the purposes of Section 2.2(j), any amounts set forth on Schedule 5.20 that are owed to any Seller by third party owners of royalty, overriding royalty, working or other interests arising out of overpayment to such third party in respect of past production of oil, gas or other hydrocarbons attributable to the properties and Assets.

“Target Acreage” means 2,000 Net Mineral Acres.

“Tax” or “Taxes” means (a) all federal, state, local, and foreign income, profits, franchise, sales, use, ad valorem, property, severance, production, excise, stamp, documentary, real property transfer or gain, gross receipts, goods and services, registration, capital, transfer, payroll, employment, social security, workers’ compensation, unemployment compensation, unclaimed property or escheat obligations, or withholding taxes or other governmental fees or charges imposed by any Governmental Body or other tax of any kind whatsoever, including any interest, penalties or additional amounts which may be imposed with respect thereto, whether disputed or not and including any obligation to indemnify or otherwise assume or succeed to the Tax liability of any other Person, (b) any obligation or liability for the payment of any amounts of the type described in clause (a) as a result of (i) being a member of a consolidated, combined, unitary or similar group of entities, (ii) any successor or transferee liability, or (iii) any obligation to indemnify any Person for such amounts by reason of contract, assumption, operation of law, or otherwise.

“Tax Allocation” has the meaning set forth in Section 2.5.

“Tax Representations” has the meaning set forth in Section 11.4(a).

“Tax Returns” has the meaning set forth in Section 5.8(a).

“Termination Date” has the meaning set forth in Section 10.1(b).

“Third Party Claim” has the meaning set forth in Section 11.7(a).

“Title Benefit” has the meaning set forth in Section 3.2.

“Title Benefit Amount” has the meaning set forth in Section 3.4(e).

“Title Benefit Notice” has the meaning set forth in Section 3.4(b).

“Title Claim Date” has the meaning set forth in Section 3.4(a).

“Title Defect” has the meaning set forth in Section 3.2.

“Title Defect Amount” has the meaning set forth in Section 3.4(d)(i).

“Title Defect Notice” has the meaning set forth in Section 3.4(a).

“Title Defect Property” has the meaning set forth in Section 3.4(a)(ii).

“Title Expert” has the meaning set forth in Section 3.4(k)(i).

“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein; provided, however, that “Transfer Requirement” shall not include any consent of, notice to, filing with, or other action by, any Governmental Body in connection with the sale or conveyance of oil and/or gas leases or interests therein or Surface Rights or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Rights or interests or they are customarily obtained subsequent to such sale or conveyance (including consents from state agencies).

“Transferred Employee” has the meaning set forth in Section 12.13.

“Transfer Taxes” has the meaning set forth in Section 12.3.

“Transition Services Agreement” has the meaning set forth in Section 9.2(c).

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed, or final Treasury Regulations.

“Units” has the meaning set forth in Section 1.2(a)(iii).

“Unscheduled (Negative) Imbalance” shall mean, respectively as to each Oil and Gas Property and without duplication, the sum (expressed in mcf) of (a) the aggregate make-up, prepaid or other volumes of natural gas, not described on Schedule 5.16, that Sellers were obligated as of the Effective Time, on account of prepayment, advance payment, take-or-pay, gas balancing or similar obligations, to deliver from such Oil and Gas Property after the Effective Time without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Sellers are entitled to receive partial payment therefor) and (b) the aggregate pipeline or processing plant Imbalances or underdeliveries, not described in Schedule 5.16, for which Sellers are obligated as of



the Effective Time to pay or deliver natural gas or cash to any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any other natural gas attributable to each Oil and Gas Property without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Sellers are entitled to receive partial payment therefor).

“Unscheduled (Positive) Imbalance” shall mean, respectively as to each Oil and Gas Property and without duplication, the sum (expressed in mcf) of (a) the aggregate make-up or other volumes of natural gas, not described on Schedule 5.16, that Sellers were entitled as of the

Effective Time, on account of gas balancing or similar obligations, to receive from such Oil and Gas Property after the Effective Time and (b) the aggregate pipeline or processing plant Imbalances or overdeliveries, not described in Schedule 5.16, for which Sellers are entitled as of the Effective Time to receive natural gas or cash from any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any other natural gas attributable to each Oil and Gas Property.

“Wells” has the meaning set forth in Section 1.2(a)(ii).

## [SIGNATURES BEGIN ON THE FOLLOWING PAGE]

IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties as of the date first above written.

## SELLERS:

## HALCÓN ENERGY PROPERTIES, INC.

By: /s/ Steve. W. Herod

Name: Steve W. Herod
Title: Executive Vice President, Corporate Development

## HALCON HOLDINGS, INC.

By: /s/ Steve. W. Herod

Name: Steve W. Herod

Title: Executive Vice President, Corporate Development

## HK ENERGY, LLC

By: /s/ Steve. W. Herod

Name: Steve W. Herod

Title: Executive Vice President, Corporate Development

## HK OIL & GAS, LLC

By: /s/ Steve. W. Herod

Name: Steve W. Herod

Title: Executive Vice President, Corporate Development

## HRC ENERGY, LLC

By: /s/ Steve. W. Herod

Name: Steve W. Herod

Title: Executive Vice President, Corporate Development

SIGNATURE PAGE TO AGREEMENT OF SALE AND PURCHASE

## THE 7711 CORPORATION

By: /s/ Steve. W. Herod



Steve W. Herod
Title: Executive Vice President, Corporate Development

## HALCÓN FIELD SERVICES, LLC

By: /s/ Steve. W. Herod

Name: Steve W. Herod
Title: Executive Vice President, Corporate Development

SIGNATURE PAGE TO AGREEMENT OF SALE AND PURCHASE

## PURCHASER:

## HAWKWOOD ENERGY EAST TEXAS, LLC

By: /s/ Patrick R. Oenbring

Name: Patrick R. Oenbring

Title: Chief Executive Officer

SIGNATURE PAGE TO AGREEMENT OF SALE AND PURCHASE



# SECOND SUPPLEMENTAL INDENTURE

THIS SECOND SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 23, 2017, among Lampe, LLC, a Delaware limited liability company (the “New Guarantor”), a subsidiary of Halcoen Resources Corporation, a Delaware corporation (the “Company”), the existing Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to herein (the “Trustee”). The New Guarantor and the existing Guarantors are sometimes referred to herein as the “Guarantors,” or individually as a “Guarantor.”

## WITNESSETH

WHEREAS, the Company and the existing Guarantors have heretofore executed and delivered to the Trustee the Indenture, dated as of May 1, 2015, among the Company, the Guarantors and the Trustee (the “Indenture”), relating to the 8.625% Senior Secured Notes due 2020 (the “Securities”) of the Company;

WHEREAS, Section 4.9 of the Indenture, in certain circumstances, requires the Company to cause a newly acquired or created Restricted Subsidiary to (i) become a Guarantor by executing a supplemental indenture and (ii) deliver an Opinion of Counsel to the Trustee as provided therein; and

WHEREAS, pursuant to Section 9.1 of the Indenture, the Company, the Guarantors and the Trustee are authorized to execute and deliver this Supplemental Indenture to amend or supplement the Indenture without the consent of any Holder.

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the New Guarantor, the other Guarantors, the Company and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Securities as follows:

1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. AGREEMENT TO GUARANTEE. The New Guarantor hereby agrees, jointly and severally, with all other Guarantors, to unconditionally Guarantee to each Holder and to the Trustee the Obligations, to the extent set forth in the Indenture and subject to the provisions in the Indenture. The obligations of the Guarantors to the Holders of Securities and to the Trustee pursuant to the Subsidiary Guarantees and the Indenture are expressly set forth in Article X of the Indenture and reference is hereby made to the Indenture for the precise terms of the Subsidiary Guarantees.

3. EXECUTION AND DELIVERY. The New Guarantor agrees that its Subsidiary Guarantee shall remain in full force and effect, notwithstanding any failure to endorse on each Security a notation of such Subsidiary Guarantee.

4. NEW YORK LAW TO GOVERN. THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SUPPLEMENTAL INDENTURE.

5. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement. This Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument.

6. EFFECT OF HEADINGS. The section headings herein are for convenience only and shall not affect the construction hereof.

7. THE TRUSTEE. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

[Signature Pages Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

NEW GUARANTOR:

LAMPE, LLC

By: /s/ Mark J. Mize

Name: Mark J. Mize

Title: Executive Vice President, Chief Financial

Officer and Treasurer



## EXISTING GUARANTORS:

HALCÓN ENERGY PROPERTIES, INC.
HALCÓN FIELD SERVICES, LLC
HALCÓN HOLDINGS, INC.
HALCÓN OPERATING CO., INC.
HALCÓN RESOURCES OPERATING, INC.
HALCÓN LOUISIANA OPERATING, L.P.
BY: HALCÓN GULF STATES, LLC,
its General Partner
HALCÓN GULF STATES, LLC
HALCÓN WILLISTON I, LLC
HALCÓN WILLISTON II, LLC
HRC ENERGY LOUISIANA, LLC
HRC ENERGY RESOURCES (WV), INC.
HALCÓN ENERGY HOLDINGS, LLC
HRC PRODUCTION COMPANY
HK OIL & GAS LLC
HRC ENERGY, LLC
HRC OPERATING, LLC
HK ENERGY, LLC
HK ENERGY OPERATING, LLC
HK LOUISIANA OPERATING, LLC
HK RESOURCES, LLC
THE 7711 CORPORATION

By: /s/ Mark J. Mize
Name: Mark J. Mize
Title: Executive Vice President, Chief Financial Officer and Treasurer

[Signature Page to 8.625% Second Supplemental Indenture]

## HALCÓN RESOURCES CORPORATION

By: /s/ Mark J. Mize
Name: Mark J. Mize
Title: Executive Vice President, Chief Financial Officer and Treasurer

[Signature Page to 8.625% Second Supplemental Indenture]

## TRUSTEE:

U.S. BANK NATIONAL ASSOCIATION

By: /s/ Steven A. Finklea
Name: Steven A. Finklea
Title: Vice President

[Signature Page to 8.625% Second Supplemental Indenture]



# SECOND SUPPLEMENTAL INDENTURE

THIS SECOND SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 23, 2017, among Lampe, LLC, a Delaware limited liability company (the “New Guarantor”), a subsidiary of Haloën Resources Corporation, a Delaware corporation (the “Company”), the existing Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to herein (the “Trustee”). The New Guarantor and the existing Guarantors are sometimes referred to herein as the “Guarantors,” or individually as a “Guarantor.”

## WITNESSETH

WHEREAS, the Company and the existing Guarantors have heretofore executed and delivered to the Trustee the Indenture, dated as of December 21, 2015, among the Company, the Guarantors and the Trustee (the “Indenture”), relating to the 12.0% Second Lien Senior Secured Notes due 2022 (the “Securities”) of the Company;

WHEREAS, Section 4.9 of the Indenture, in certain circumstances, requires the Company to cause a newly acquired or created Restricted Subsidiary to (i) become a Guarantor by executing a supplemental indenture and (ii) deliver an Opinion of Counsel to the Trustee as provided therein; and

WHEREAS, pursuant to Section 9.1 of the Indenture, the Company, the Guarantors and the Trustee are authorized to execute and deliver this Supplemental Indenture to amend or supplement the Indenture without the consent of any Holder.

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the New Guarantor, the other Guarantors, the Company and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Securities as follows:

1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. AGREEMENT TO GUARANTEE. The New Guarantor hereby agrees, jointly and severally, with all other Guarantors, to unconditionally Guarantee to each Holder and to the Trustee the Obligations, to the extent set forth in the Indenture and subject to the provisions in the Indenture. The obligations of the Guarantors to the Holders of Securities and to the Trustee pursuant to the Subsidiary Guarantees and the Indenture are expressly set forth in Article X of the Indenture and reference is hereby made to the Indenture for the precise terms of the Subsidiary Guarantees.

3. EXECUTION AND DELIVERY. The New Guarantor agrees that its Subsidiary Guarantee shall remain in full force and effect, notwithstanding any failure to endorse on each Security a notation of such Subsidiary Guarantee.

4. NEW YORK LAW TO GOVERN. THE LAWS OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SUPPLEMENTAL INDENTURE.

5. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement. This Supplemental Indenture may be executed in multiple counterparts which, when taken together, shall constitute one instrument.

6. EFFECT OF HEADINGS. The section headings herein are for convenience only and shall not affect the construction hereof.

7. THE TRUSTEE. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

[Signature Pages Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

NEW GUARANTOR:

LAMPE, LLC

By: /s/ Mark J. Mize

Name: Mark J. Mize

Title: Executive Vice President, Chief Financial

Officer and Treasurer

EXISTING GUARANTORS:



HALCÓN ENERGY PROPERTIES, INC.
HALCÓN FIELD SERVICES, LLC
HALCÓN HOLDINGS, INC.
HALCÓN OPERATING CO., INC.
HALCÓN RESOURCES OPERATING, INC.
HALCÓN LOUISIANA OPERATING, L.P.
BY: HALCÓN GULF STATES, LLC,
its General Partner
HALCÓN GULF STATES, LLC
HALCÓN WILLISTON I, LLC
HALCÓN WILLISTON II, LLC
HRC ENERGY LOUISIANA, LLC
HRC ENERGY RESOURCES (WV), INC.
HALCÓN ENERGY HOLDINGS, LLC
HRC PRODUCTION COMPANY
HK OIL & GAS LLC
HRC ENERGY, LLC
HRC OPERATING, LLC
HK ENERGY, LLC
HK ENERGY OPERATING, LLC
HK LOUISIANA OPERATING, LLC
HK RESOURCES, LLC
THE 7711 CORPORATION

By: /s/ Mark J. Mize
Name: Mark J. Mize
Title: Executive Vice President, Chief Financial Officer and Treasurer

[Signature Page to 12.0% Second Supplemental Indenture]

## HALCÓN RESOURCES CORPORATION

By: /s/ Mark J. Mize
Name: Mark J. Mize
Title: Executive Vice President, Chief Financial Officer and Treasurer

[Signature Page to 12.0% Second Supplemental Indenture]

## TRUSTEE:

U.S. BANK NATIONAL ASSOCIATION

By: /s/ Steven A. Finklea
Name: Steven A. Finklea
Title: Vice President

[Signature Page to 12.0% Second Supplemental Indenture]



# HALCÓN RESOURCES CORPORATION

## THIRD AMENDED AND RESTATED
SUMMARY OF NON-EMPLOYEE DIRECTOR COMPENSATION
Adopted Effective as of September 9, 2016

Each non-employee member serving on the Board of Directors (each, a “Director,” and collectively, the “Directors”) of Halcón Resources Corporation (the “Company”) shall be paid compensation in the form of cash and stock, represented in an annual amount, as set forth in the summary below:

<table><tr><td></td><td>Amount</td></tr><tr><td>Annual Retainer:</td><td></td></tr><tr><td>Cash(1) (2)</td><td>$ 70,000</td></tr><tr><td>Stock(3)</td><td>$ 165,000</td></tr><tr><td>Additional Annual Retainer:</td><td></td></tr><tr><td>Lead Director</td><td>$ 25,000</td></tr><tr><td>Additional Annual Retainers — Chair:</td><td></td></tr><tr><td>Audit Committee Chair</td><td>$ 25,000</td></tr><tr><td>Compensation Committee Chair</td><td>$ 15,000</td></tr><tr><td>Nominating and Corporate Governance Committee Chair</td><td>$ 12,500</td></tr><tr><td>Reserves Committee Chair</td><td>$ 12,500</td></tr><tr><td>Additional Annual Retainers — Committee Member:</td><td></td></tr><tr><td>Audit Committee Member</td><td>$ 7,500</td></tr><tr><td>Compensation Committee Member</td><td>$ 5,000</td></tr><tr><td>Nominating and Corporate Governance Committee Member</td><td>$ 5,000</td></tr><tr><td>Reserves Committee Member</td><td>$ 5,000</td></tr></table>

(1) Payable in quarterly installments and pro-rated for partial year terms.

(2) Any cash compensation to be received by a Director may, at such Director’s written election, be paid in the Company’s common stock based on the closing market price of the stock on the last trading day of the calendar quarter during which such Director is entitled to receive the cash compensation. A Director’s written election to be paid any or all fees in Company stock, rather than in cash, must be delivered to the Company prior to the beginning of the quarter in which he desires to be paid in Company stock and such election shall be irrevocable during that quarter.

(3) Granted under the Halcón Resources Corporation 2016 Long-Term Incentive Plan; valued at the date of grant, which date shall occur contemporaneously with the annual meeting of shareholders.



# HALCÓN RESOURCES CORPORATION
2016 LONG-TERM INCENTIVE PLAN

# EMPLOYEE STOCK OPTION AWARD AGREEMENT

THIS EMPLOYEE STOCK OPTION AWARD AGREEMENT (this “Agreement”) is made and entered into as of the Date of Grant (as set forth on the Summary of Stock Option Grant and provided through the online platform of the Company’s third-party Plan administrator) by and between HALCÓN RESOURCES CORPORATION, a Delaware corporation (the “Company”), and the Participant set forth on the Summary of Stock Option Grant (“Participant”) pursuant to the Halcón Resources Corporation 2016 Long-Term Incentive Plan (as amended, modified or supplemented, the “Plan”).

WHEREAS, the Participant is an employee or a consultant to the Company or a Subsidiary of the Company or is a non-employee director of the Company, and it is important to the Company that the Participant be encouraged to remain in the service of the Company or such Subsidiary;

WHEREAS, the Board of Directors of the Company and the Committee (as defined in the Plan) have the authority to grant Options under the Plan to eligible employees, non-employee directors and other individuals providing consulting or advisory services to the Company, its Subsidiaries or its Affiliated Entities; and

WHEREAS, the Board has determined to award to the Participant the Option described in this Agreement;

NOW, THEREFORE, the Company and the Participant agree as follows:

1. Effect of Plan and Authority of Committee. This Agreement and the Option granted hereunder are subject to the Plan, which is incorporated herein by reference. The Committee is authorized to make all determinations and interpretations with respect to matters arising under or relating to the Plan, this Agreement and the Option granted hereunder. Capitalized terms used and not otherwise defined herein have the respective meanings given them in the Plan or in the Summary of Stock Option Grant, which are attached hereto and incorporated herein by this reference for all purposes.

2. Grant of Option. On the terms and conditions set forth in this Agreement, the Summary of Stock Option Grant and the Plan, as of the Grant Date, the Company hereby grants to the Participant the option to purchase the number of shares of Common Stock set forth on the Summary of Stock Option Grant at the Exercise Price per share set forth on the Summary of Stock Option Grant (the "Option"). The Option is intended to be an Incentive Stock Option or a Nonqualified Stock Option, as provided in the Summary of Stock Option Grant. If the Option is intended to be an Incentive Stock Option, it is agreed that the exercise price is at least 100% of the Fair Market Value of a share of Common Stock on the Date of Grant (110% of Fair Market Value if the Participant owns stock possessing more than 10% of the combined voting power of the Company or its Subsidiaries or a "parent corporation"). To the extent that the aggregate Fair Market Value (determined at the time the Incentive Stock Option is granted) of shares of Common Stock with respect to which Incentive Stock Options are exercisable for the first time by an individual during any calendar year under all incentive stock option plans of the Company and its Subsidiaries and any "parent corporation" (as defined in Section 424(e) of the Code) exceeds $100,000, such excess Incentive Stock Options shall be treated as Nonqualified Stock Options. The Committee shall determine, in accordance with applicable provisions of the Code, Treasury Regulations and other administrative pronouncements, which of the Participant's Options will not constitute Incentive Stock Options because of such limitation and shall notify the Participant of such determination as soon as practicable after such determination.

3. Vesting. This Option may be exercised only to the extent it is vested on the vesting dates in accordance with the Vesting Schedule set forth in the Summary of Stock Option Grant. The vested percentage indicated in such Vesting Schedule shall be exercisable, as to all or part of the vested shares, at any time or times after the respective vesting date and until the expiration or termination of the Option. The unvested portion of this Option shall terminate and be forfeited immediately on the date of the Participant's termination of employment or service with the Company, the Subsidiaries and the Affiliated Entities, subject to accelerated vesting on termination in certain circumstances as set forth herein or in the Plan.

## 4. Term.

(a) Term of Option. This Option may not be exercised after the close of the Company’s business on the Expiration Date as set forth in the Summary of Stock Option Grant. If the Expiration Date of this Option or any termination date provided for in this Agreement shall fall on a Saturday, Sunday or a day on which the executive offices of the Company are not open for business, then such expiration or termination date shall be deemed to be the last normal business day of the Company at its executive offices preceding such Saturday, Sunday or day on which such offices are closed.

(b) Early Termination. Except as provided below, this Option may not be exercised unless the Participant shall have been in the continuous employ or service of the Company, any Subsidiary of the Company or any Affiliated Entity from the Date of Grant to the date of exercise of the Option.

(i) If the Participant is an Eligible Employee and the Participant’s employment with the Company, a Subsidiary or an Affiliated Entity terminates by reason of the Participant’s Disability, this Option may be exercised in full by the Participant (or the Participant’s estate or the person who acquires this Option by will or the laws of descent and distribution or otherwise by reason of death of the Participant), but only within such period of time ending on the earlier of (A) the date that is one year following such termination or (B) the Expiration Date.

(ii) If the Participant is an Eligible Employee and the Participant’s employment with the Company, a Subsidiary or an Affiliated Entity terminates by reason of the Participant’s death, the Participant’s estate, or the person who acquires this Option by will or the laws of descent and distribution or otherwise by reason of death of the Participant, may exercise this Option in full, but only within such period of time ending on the earlier of (A) the date that is one year following the Participant’s death or (B) the Expiration Date.



(iii) If the Participant is an Eligible Employee and the Participant’s employment with the Company, a Subsidiary or an Affiliated Entity is terminated without Cause, all unvested Options shall be forfeited and the Participant may exercise any vested Options but only within such period of time ending on the earlier of (A) the date that is three months following such termination or (B) the Expiration Date. For purposes of this Agreement, “Cause” means a Participant’s gross negligence or willful misconduct in the performance of the duties of his or her employment, or the Participant’s final conviction of a felony or of a misdemeanor involving moral turpitude.

(iv) If the Participant is an Eligible Employee and the Participant’s employment with the Company, a Subsidiary or an Affiliated Entity is terminated for Cause, all unvested and vested Options shall be immediately forfeited upon such termination.

(v) If the Participant is an Eligible Employee and the Participant voluntarily terminates employment with the Company, a Subsidiary or an Affiliated Entity, all unvested Options shall be forfeited and the Participant may exercise any vested Options but only within such period of time ending on the earlier of (A) the date that is three months following such termination of employment or (B) the Expiration Date.

(vi) If the Participant is a Consultant and the Participant ceases providing services to the Company, all unvested Options shall be forfeited and the Participant may exercise any vested Options but only within such period of time ending on the earlier of (A) the date that is three months following such cessation of services or (B) the Expiration Date.

(vii) If the Participant is an Eligible Director and the Participant terminates service as a director of the Company, all unvested Options shall be forfeited and the Participant may exercise any vested Options but only within such period of time ending on the earlier of (A) the date that is three months following such cessation of services or (B) the Expiration Date.

5. Manner of Exercise and Payment. Exercise of this Option shall be by written notice to the Senior Vice President, Human Resources and Administration of the Company at least two business days in advance of such exercise stating the election to exercise in the form and manner determined by the Committee. The exercise price of this Option may be paid (i) in cash or by check, bank draft or money order payable to the order of the Company; (ii) by delivering shares of Common Stock having a Fair Market Value on the date of payment equal to the amount of the exercise price, but only to the extent such exercise of an Option would not result in an adverse accounting charge to the Company for financial accounting purposes with respect to the shares used to pay the exercise price unless otherwise determined by the Committee; or (iii) a combination of the foregoing. In addition to the foregoing, the Committee may permit this Option to be exercised by a broker-dealer acting on behalf of a Participant through procedures approved by the Committee.

6. Withholding Tax. Unless otherwise paid by the Participant, the Company, its Subsidiaries or any of its Affiliated Entities shall be entitled to deduct from any payment under this Agreement, regardless of the form of such payment, the amount of all applicable income and employment taxes required by law to be withheld with respect to such payment or may require the Participant to pay to it such tax prior to and as a condition of the making of such payment. In accordance with any applicable administrative guidelines it establishes, the Committee may allow the Participant to pay the amount of taxes required by law to be withheld with respect to this Option by (i) directing the Company to withhold from any payment with respect to the Option a number of shares of Common Stock having a Fair Market Value on the date of payment equal to the amount of the required withholding taxes or (ii) delivering to the Company previously owned shares of Common Stock having a Fair Market Value on the date of payment equal to the amount of the required withholding taxes. However, any payment made by the Participant pursuant to either of the foregoing clauses (i) or (ii) shall not be permitted if it would result in an adverse accounting charge with respect to such shares used to pay such taxes unless otherwise approved by the Committee.

7. Delivery of Shares. Delivery of the certificates representing the shares of Common Stock purchased, upon exercise of this Option shall be made as soon as reasonably practicable after receipt of notice of exercise and full payment of the Exercise Price and any required withholding taxes. If the Company so elects, its obligation to deliver shares of Common Stock upon the exercise of this Option shall be conditioned upon its receipt from the person exercising this Option of an executed investment letter, in form and content satisfactory to the Company and its legal counsel, evidencing the investment intent of such person and such other matters as the Company may reasonably require. If the Company so elects, the certificate or certificates representing the shares of Common Stock issued upon exercise of this Option shall bear a legend to reflect any restrictions on transferability.

8. Optional Issuance in Book-Entry Form. Notwithstanding the provisions of Section 7, at the option of the Company, any shares of Common Stock that under the terms of this Agreement are issuable in the form of a stock certificate may instead be issued in book-entry form.

## 9. Transferability.

(a) This Option is personal to the Participant and during the Participant’s lifetime may be exercised only by the Participant or his or her guardian or legal representative upon the events and in accordance with the terms and conditions set forth in the Plan, and shall not be transferred except by will or by the laws of descent and distribution, nor may it be otherwise sold, transferred, pledged, exchanged, hypothecated or otherwise disposed of in any way (by operation of law or otherwise) and it shall not be subject to execution, attachment or similar process. Any attempted sale, transfer, pledge, exchange, hypothecation or other disposition of this Option not specifically permitted by the Plan or this Agreement shall be null and void and without effect.

(b) No shares of Common Stock or other form of payment shall be issued with respect to any Option unless the Company shall be satisfied based on the advice of its counsel that such issuance will be in compliance with applicable federal and state securities laws. Certificates evidencing shares of Common Stock delivered pursuant to exercise of this Option may be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any securities exchange or transaction reporting system upon which the Common Stock is then listed or to which it is admitted for quotation and any federal or state securities law. The Committee may cause a legend or legends to be placed upon such certificates (if any) to make appropriate reference to such



10. Notices. All notices between the parties hereto shall be in writing. Notices to the Participant shall be given to the Participant’s address as contained in the Company’s records. Notices to the Company shall be addressed to its Senior Vice President, Human Resources and Administration at the principal executive offices of the Company at 1000 Louisiana, Suite 6700, Houston, Texas 77002.

## 11. Relationship with Contract of Employment or Services.

(a) The grant of an Option does not form part of the Participant’s entitlement to remuneration or benefits pursuant to his or her contract of employment or services, if any, and, except as otherwise provided in a written contract of employment or for services, the existence of such a contract between any person and the Company, any Subsidiary or any Affiliated Entity does not give such person any right or entitlement to have an Option granted to him or any expectation that an Option might be granted to him whether subject to any conditions or at all.

(b) The rights and obligations of the Participant under the terms of his or her contract of employment or other contract or agreement for services with the Company, any Subsidiary of the Company or any Affiliated Entity, if any, shall not be affected by the grant of an Option.

(c) The rights granted to the Participant upon the grant of an Option shall not afford the Participant any rights or additional rights to compensation or damages in consequence of the loss or termination of his or her office, employment or service with the Company, any Subsidiary of Affiliated Entity for any reason whatsoever.

(d) The Participant shall not be entitled to any compensation or damages for any loss or potential loss which he or she may suffer by reason of being or becoming unable to exercise an Option in consequence of the loss or termination of his or her office, employment or service with the Company, any Subsidiary of the Company or any Affiliated Entity for any reason (including, without limitation, any breach of contract by the Company, any Subsidiary of the Company or any Affiliated Entity) or in any other circumstances whatsoever.

12. Market Standoff Agreement. The Participant agrees in connection with any public offering of the Company’s securities that, upon request of the Company or the managing underwriter(s) of such offering, the Participant will not sell or otherwise dispose of any Common Stock acquired pursuant to this Agreement without the prior written consent of the Company or such managing underwriter(s), as the case may be, for a period of time (not to exceed 180 days) after the effective date of the registration requested by such managing underwriter(s) and subject to all restrictions as the Company or the managing underwriter(s) may specify for employee or other service provider stockholders generally.

13. Governing Law; Exclusive Forum; Consent to Jurisdiction. This Agreement shall be governed by and construed in accordance with the internal laws (and not the principles relating to conflicts of laws) of the State of Texas, except as superseded by applicable federal law. The exclusive forum for any action concerning this Agreement or the transactions contemplated hereby shall be in a court of competent jurisdiction in Harris County, Texas, with respect to a state court, or the United States District Court for the Southern District of Texas, with respect to a federal court. THE PARTICIPANT HEREBY CONSENTS TO THE EXERCISE OF JURISDICTION OF A COURT IN THE EXCLUSIVE FORUM AND WAIVES ANY RIGHT HE OR SHE MAY HAVE TO CHALLENGE OR CONTEST THE REMOVAL AT ANY TIME BY THE COMPANY, ANY OF ITS SUBSIDIARIES OR ANY OF ITS AFFILIATED ENTITIES TO FEDERAL COURT OF ANY SUCH ACTION HE OR SHE MAY BRING AGAINST IT IN STATE COURT.

## HALCÓN RESOURCES CORPORATION

Bv: /s/ Leah R. Kasparek
Leah R. Kasparek
Senior Vice President, Human Resources and Administration



# HALCÓN RESOURCES CORPORATION
2016 LONG-TERM INCENTIVE PLAN

# EMPLOYEE RESTRICTED STOCK AWARD AGREEMENT

THIS EMPLOYEE RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”) is made between HALCÓN RESOURCES CORPORATION, a Delaware corporation (the “Company”), and the Employee (the “Employee”).

WHEREAS, to carry out the purposes of the HALCÓN RESOURCES CORPORATION 2016 LONG-TERM INCENTIVE PLAN (as amended, modified or supplemented, the “Plan”), the Company desires to grant to the Employee a Restricted Stock Award pursuant to the terms of this Agreement and the Plan (“Restricted Stock”).

NOW THEREFORE, in consideration of the mutual agreements and other matters set forth herein and in the Plan, the Company and the Employee hereby agree as follows:

1. Grant. On the Date of Grant, the Company hereby grants to the Employee shares of Common Stock (the “Shares”) on the terms and conditions set forth herein, in the Grant Information Summary as provided by the Company’s third-party Plan administrator’s online platform and in the Plan, which Plan is incorporated herein by reference.

## 2. Vesting.

(a) The Shares shall vest one-third one year after the Date of Grant; an additional one-third two years after the Date of Date; and the remaining one-third of the Shares will vest three years after the Date of Grant; provided, however, that the Employee has served as an employee of the Company through and until each such vesting date.

(b) Upon termination of the Employee’s employment with the Company, any Shares which are not vested shall be forfeited and returned to the Company, except that:

(i) If the Employee’s service with the Company terminates by reason of Disability, legal ownership of the Shares shall fully vest as of the date of such termination. For purposes hereof, the term Disability shall mean a physical or mental infirmity which impairs the Employee’s ability to substantially perform his or her duties for a period of one hundred eighty (180) consecutive days.

(ii) If the Employee dies while employed with the Company, the Shares shall fully vest on the date of death.

3. Beneficial Ownership. Unless and until the Shares are forfeited to the Company or transferred by the Employee (in accordance with this Agreement and applicable law), the Employee shall have beneficial ownership of the Shares, including the right to receive dividends and the right to vote the Shares.

4. Issuance of the Shares. The Shares shall be registered in the name of the Employee on the records of the Company and shall be issued in book-entry form (with no physical certificate issued to the Employee). Until the vesting of any Shares (the period from the Date of Grant to the date of vesting, the “Restriction Period”), any certificate representing the Shares shall be held in escrow by the Company for the account of the Employee and the Company shall issue “stop-transfer” instructions to its transfer agent to prevent the transfer of the Shares by the Employee.

5. Transfer Restrictions. Except as approved by the Company, during the Restriction Period, the Shares shall not be transferable or assignable by the Employee other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by Section 414(p) of the Internal Revenue Code of 1986, as amended (the “Code”). No transfer by will, trust, or by the laws of descent and distribution shall be effective to bind the Company unless the Board of Directors of the Company (the “Board”), the Compensation Committee of the Board or other such committee as the Board shall appoint to administer the Plan as permitted by the Plan (collectively herein the “Committee”) has been furnished with a copy of the deceased Employee’s enforceable will, trust or such other evidence as the Committee deems necessary to establish the validity of the transfer. Any attempted transfer in violation of this provision shall be void and ineffective.

6. Vesting Restrictions. Except as provided under the terms of the Plan and in Section 2 hereof, the Shares will vest only during Employee’s lifetime while Employee remains employed by the Company.

7. Withholding of Tax. To the extent that the granting of the Shares or the lapse of restrictions applicable to such Shares results in compensation income to the Employee for federal or state income tax purposes, the Employee shall pay to the Company (in cash or to the extent permitted by the Committee, shares of Common Stock held by the Employee whose value is equal to the amount of the Employee’s tax withholding liability as determined by the Committee) any federal, state or local taxes of any kind required by law to be withheld, if any, with respect to the Shares. The Company, to the extent permitted by law, has the right to deduct from any payment of any kind otherwise due to the Employee from the Company any federal, state or local taxes of any kind required by law to be withheld with respect to the Shares. The Company is further authorized in its discretion to satisfy any such withholding requirement out of shares of Restricted Stock of the Employee held by the Company.

8. Securities Law. The Employee agrees that the Shares will not be sold or otherwise disposed of in any manner which would constitute a violation of any applicable securities laws, whether federal or state. The Employee also agrees that (i) any certificates representing the Shares may bear such legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws; (ii) the Company may refuse to register the transfer of such Shares on the stock transfer records of the Company if such proposed transfer would, in the opinion of counsel satisfactory to the



Company, constitute a violation of any applicable securities laws; and (iii) the Company may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Shares.

9. No Rights to Continued Employment. Nothing contained in this Agreement shall confer upon the Employee the right to continue as an employee of the Company.

10. Representations and Warranties of Employee. The Employee represents and warrants to the Company as follows:

(a) The Employee has received a copy of the Plan and has read and understands the terms of the Plan and this Agreement, and agrees to be bound by their terms and conditions. The Employee acknowledges that there may be adverse tax consequences upon the granting of the Shares, vesting of the Shares or disposition of the Shares once vested, and that the Employee should consult a tax adviser prior to such time.

(b) The Employee agrees to sign such additional documentation as may reasonably be required from time to time by the Company in connection with this Agreement.

11. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all persons lawfully claiming under the Employee.

12. Governing Laws. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas.

13. Modification. This Agreement may not be modified except in writing signed by the parties hereto or their respective successors and permitted assigns.

14. Headings. The headings of paragraphs in this Agreement are for convenience of reference only, do not constitute a part of this Agreement, and shall not be deemed to limit or alter any of the provisions of this Agreement.

15. Defined Terms. Except as otherwise provided in this Agreement, or unless the context clearly indicates otherwise, capitalized terms used but not defined in this Agreement have the definitions as provided in the Plan. In the event of a conflict or inconsistency between the discretionary terms and provisions of the Plan and the provisions of this Agreement, this Agreement shall govern and control.

## HALCÓN RESOURCES CORPORATION

By: /s/ Leah R. Kasparek

Leah R. Kasparek

Senior Vice President, Human Resources

and Administration



# HALCÓN RESOURCES CORPORATION
2016 LONG-TERM INCENTIVE PLAN

## NON-EMPLOYEE DIRECTOR RESTRICTED STOCK AWARD AGREEMENT

THIS NON-EMPLOYEE DIRECTOR RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”) is made and entered by and between HALCÓN RESOURCES CORPORATION, a Delaware corporation (the “Company”), and the Non-Employee Director (the “Director”).

WHEREAS, to carry out the purposes of the HALCÓN RESOURCES CORPORATION 2016 LONG—TERM INCENTIVE PLAN (as amended, modified or supplemented, the “Plan”), the Company desires to grant to the Director a Restricted Stock Award pursuant to the terms of this Agreement and the Plan (“Restricted Stock”).

NOW THEREFORE, in consideration of the mutual agreements and other matters set forth herein and in the Plan, the Company and the Director hereby agree as follows:

1. Grant. On the Date of Grant, the Company hereby grants to the Director shares of Common Stock (the “Shares”) on the terms and conditions set forth in the Grant Information Summary as provided by the Company’s third-party Plan administrator’s online platform and in the Plan, which Plan is incorporated herein by reference.

## 2. Vesting.

(a) The Shares shall vest six months from the Date of Grant as set forth in the Grant Information Summary; provided, however, that the Director remains in continued service with the Company through such date and has served as a director of the Company for the entire six-month period preceding such date.

(b) Upon the termination of the Director’s service with the Company, any Shares which are not vested shall be forfeited and returned to the Company, except that:

(i) If the Director’s service with the Company terminates by reason of Disability, legal ownership of the Shares shall fully vest as of the date of such termination. For purposes hereof, the term Disability shall mean a physical or mental infirmity which impairs the Director’s ability to substantially perform his duties for a period of one hundred eighty (180) consecutive days.

(ii) If the Director dies while serving on the Board, the Shares shall fully vest on the date of death.

3. Beneficial Ownership. Unless and until the Shares are forfeited to the Company or transferred by the Director (in accordance with this Agreement and applicable law), the Director shall have beneficial ownership of the Shares, including the right to receive dividends and the right to vote the Shares.

4. Issuance of the Shares. The Shares shall be registered in the name of the Director on the records of the Company and shall be issued in book-entry form (with no physical certificate issued to the Director). Until the vesting of any Shares (the period from the Date of Grant to the date of vesting, the “Restriction Period”), any certificate representing the Shares shall be held in escrow by the Company for the account of the Director and the Company shall issue “stop-transfer” instructions to its transfer agent to prevent the transfer of the Shares by the Director.

5. Transfer Restrictions. Except as approved by the Company, during the Restriction Period, the Shares shall not be transferable or assignable by the Director other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by Section 414(p) of the Internal Revenue Code of 1986, as amended. No transfer by will, trust, or by the laws of descent and distribution shall be effective to bind the Company unless the Board, the Compensation Committee of the Board or other such committee as the Board shall appoint to administer the Plan as permitted by the Plan (collectively herein the “Committee”) has been furnished with a copy of the deceased Director’s enforceable will, trust or such other evidence as the Committee deems necessary to establish the validity of the transfer. Any attempted transfer in violation of this provision shall be void and ineffective.

6. Vesting Restrictions. Except as provided under the terms of the Plan and in Section 2 hereof, the Shares will vest only during the Director’s lifetime while the Director remains in the service of the Company.

7. Withholding of Tax. To the extent that the granting of the Shares or the lapse of restrictions applicable to such Shares results in compensation income to the Director for federal or state income tax purposes for which the Company has a withholding obligation, the Director shall pay to the Company (in cash or to the extent permitted by the Committee, shares of Common Stock held by the Director whose value is equal to the amount of the Director’s tax withholding liability as determined by the Committee) any federal, state or local taxes of any kind required by law to be withheld, if any, with respect to the Shares. The Company, to the extent permitted by law, has the right to deduct from any payment of any kind otherwise due to the Director from the Company any federal, state or local taxes of any kind required by law to be withheld with respect to the Shares. The Company is further authorized in its discretion to satisfy any such withholding requirement out of shares of Restricted Stock of the Director held by the Company.

8. Securities Law. The Director agrees that the Shares will not be sold or otherwise disposed of in any manner which would constitute a violation of any applicable securities laws, whether federal or state. The Director also agrees that: (i) any certificates representing the Shares may bear such legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws; (ii) the Company may refuse to register the transfer of such Shares on the stock transfer records of the Company if such proposed transfer would, in the opinion of counsel satisfactory to the Company, constitute a violation of any applicable securities laws; and (iii) the Company may give related instructions to its transfer agent, if any, to stop



registration of the transfer of the Shares.

9. No Rights to Directorship. Nothing contained in this Agreement shall confer upon the Director the right to continue in the service of the Company.

10. Representations and Warranties of Director. The Director represents and warrants to the Company as follows:

(a) The Director has received a copy of the Plan and has read and understands the terms of the Plan and this Agreement, and agrees to be bound by their terms and conditions. The Director acknowledges that there may be adverse tax consequences upon the granting of the Shares, vesting of the Shares or disposition of the Shares once vested, and that the Director should consult a tax adviser prior to such time.

(b) The Director agrees to sign such additional documentation as may reasonably be required from time to time by the Company in connection with this Agreement.

11. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all persons lawfully claiming under the Director.

12. Governing Laws. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas.

13. Modification. This Agreement may not be modified except in writing signed by the parties hereto or their respective successors and permitted assigns.

14. Headings. The headings of paragraphs in this Agreement are for convenience of reference only, do not constitute a part of this Agreement, and shall not be deemed to limit or alter any of the provisions of this Agreement.

15. Defined Terms. Except as otherwise provided in this Agreement, or unless the context clearly indicates otherwise, capitalized terms used but not defined in this Agreement have the definitions as provided in the Plan. In the event of a conflict or inconsistency between the discretionary terms and provisions of the Plan and the provisions of this Agreement, this Agreement shall govern and control.

HALCÓN RESOURCES CORPORATION

By: /s/ Leah R. Kasparek

Leah R. Kasparek

Senior Vice President, Human Resources

and Administration



Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends (In thousands, except ratios)

<table><tr><td rowspan="2"></td><td rowspan="2">Successor Period from September 10, 2016 through December 31, 2016</td><td colspan="5">Predecessor</td></tr><tr><td rowspan="2">Period from January 1, 2016 through September 9, 2016</td><td colspan="4">Years Ended December 31,</td></tr><tr><td>Earnings:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income (loss) before income taxes</td><td>$ (474,449)</td><td>$ 3,292</td><td>$ (1,913,535)</td><td>$ 314,880</td><td>$ (1,380,378)</td><td>$ (67,066)</td></tr><tr><td>Adjustments:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity investment loss (income)</td><td>(9)</td><td>152</td><td>171</td><td>(617)</td><td>(97)</td><td>(373)</td></tr><tr><td>Interest capitalized</td><td>—</td><td>(68,192)</td><td>(113,009)</td><td>(168,897)</td><td>(203,993)</td><td>(53,492)</td></tr><tr><td>Income (loss) before income taxes, as adjusted</td><td>$ (474,458)</td><td>$ (64,748)</td><td>$ (2,026,373)</td><td>$ 145,366</td><td>$ (1,584,468)</td><td>$ (120,931)</td></tr><tr><td>Fixed charges</td><td>29,013</td><td>197,640</td><td>340,399</td><td>320,403</td><td>262,046</td><td>86,589</td></tr><tr><td>Total earnings</td><td>$ (445,445)</td><td>$ 132,892</td><td>$ (1,685,974)</td><td>$ 465,769</td><td>$ (1,322,422)</td><td>$ (34,342)</td></tr><tr><td>Fixed charges:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense and amortization of finance costs</td><td>$ 28,553</td><td>$ 195,698</td><td>$ 337,554</td><td>$ 317,732</td><td>$ 259,159</td><td>$ 85,372</td></tr><tr><td>Rental expense representative of interest factor</td><td>460</td><td>1,942</td><td>2,845</td><td>2,671</td><td>2,887</td><td>1,217</td></tr><tr><td>Total fixed charges</td><td>$ 29,013</td><td>$ 197,640</td><td>$ 340,399</td><td>$ 320,403</td><td>$ 262,046</td><td>$ 86,589</td></tr><tr><td>Ratio of earnings to fixed charges</td><td>—(1)</td><td>—(3)</td><td>—(5)</td><td>1.5</td><td>—(7)</td><td>—(8)</td></tr><tr><td>Total fixed charges</td><td>$ 29,013</td><td>$ 197,640</td><td>$ 340,399</td><td>$ 320,403</td><td>$ 262,046</td><td>$ 86,589</td></tr><tr><td>Pre-tax preferred dividend requirements</td><td>783</td><td>12,320</td><td>83,942</td><td>32,902</td><td>12,132</td><td>110,075</td></tr><tr><td>Total fixed charges plus preference dividends</td><td>$ 29,796</td><td>$ 209,960</td><td>$ 424,341</td><td>$ 353,305</td><td>$ 274,178</td><td>$ 196,664</td></tr><tr><td>Ratio of earnings to combined fixed charges and preference dividends</td><td>—(2)</td><td>—(4)</td><td>—(6)</td><td>1.3</td><td>—(7)</td><td>—(9)</td></tr></table>

(1) Due to the Company's loss for the period from September 10, 2016 through December 31, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $474.5 million to achieve a coverage ratio of 1:1.

(2) Due to the Company's loss for the period from September 10, 2016 through December 31, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $475.2 million to achieve a coverage ratio of 1:1.

(3) Due to the Company's loss for the period from January 1, 2016 through September 9, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $64.7 million to achieve a coverage ratio of 1:1.



(4) Due to the Company's loss for the period from January 1, 2016 through September 9, 2016 the ratio coverage was less than 1:1. The Company must generate additional earnings of $77.1 million to achieve a coverage ratio of 1:1.

(5) Due to the Company's "Loss before income taxes, as adjusted" in 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.0 billion to achieve coverage ratio of 1:1.

(6) Due to the Company's "Loss before income taxes, as adjusted" in 2015, the ratio coverage was less than 1:1. The Company must generate additional earnings of $2.1 billion to achieve coverage ratio of 1:1.

(7) Due to the Company's "Loss before income taxes, as adjusted" in 2013, the ratio coverage was less than 1:1. The Company must generate additional earnings of $1.6 billion to achieve a coverage ratio of 1:1.

(8) Due to the Company's "Loss before income taxes, as adjusted" in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $120.9 million to achieve a coverage ratio of 1:1.

(9) Due to the Company's "Loss before income taxes, as adjusted" in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $231.0 million to achieve a coverage ratio of 1:1.



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Exhibit 12.1

Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends (In thousands, except ratios)



## Subsidiaries of the Registrant

<table><tr><td>Subsidiary</td><td>State of Incorporation or Organization</td></tr><tr><td>Halcón Resources Operating, Inc</td><td>Delaware</td></tr><tr><td>Halcón Holdings, Inc.</td><td>Delaware</td></tr><tr><td>HRC Energy Resources (WV), Inc.</td><td>Delaware</td></tr><tr><td>HRC Energy Louisiana, LLC</td><td>Delaware</td></tr><tr><td>HRC Production Company.</td><td>Texas</td></tr><tr><td>Halcón Energy Properties, Inc.</td><td>Delaware</td></tr><tr><td>Halcón Operating Co., Inc.</td><td>Texas</td></tr><tr><td>Halcón Gulf States, LLC</td><td>Oklahoma</td></tr><tr><td>Halcón Energy Holdings, LLC</td><td>Delaware</td></tr><tr><td>Halcón Field Services, LLC</td><td>Delaware</td></tr><tr><td>Halcón Louisiana Operating, L.P.</td><td>Delaware</td></tr><tr><td>HRC Energy, LLC</td><td>Colorado</td></tr><tr><td>HRC Operating, LLC</td><td>Colorado</td></tr><tr><td>HK Oil &amp; Gas, LLC</td><td>Texas</td></tr><tr><td>Halcón Williston I, LLC</td><td>Texas</td></tr><tr><td>Halcón Williston II, LLC</td><td>Texas</td></tr><tr><td>HK Energy, LLC</td><td>Texas</td></tr><tr><td>HK Louisiana Operating, LLC</td><td>Texas</td></tr><tr><td>HK Energy Operating, LLC.</td><td>Texas</td></tr><tr><td>HK Resources, LLC</td><td>Delaware</td></tr><tr><td>The 7711 Corporation</td><td>Texas</td></tr><tr><td>Lampe, LLC</td><td>Delaware</td></tr></table>



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Exhibit 21.1

Subsidiaries of the Registrant



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Exhibit 23.1

## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-213565, on Form S-8, of our reports dated February 28, 2017, relating to the financial statements of Halcón Resources Corporation, and the effectiveness of Halcón Resources Corporation's internal control over financial reporting, appearing in this Annual Report on Form 10-K of Halcón Resources Corporation for the year ended December 31, 2016.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2017



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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



## CONSENT OF INDEPENDENT PEIROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our reserves report dated February 1, 2017, included in the Annual Report on Form 10-K of Halcón Resources Corporation (the "Company") for the fiscal year ended December 31, 2016, as well as in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the references to our firm, in the context in which they appear, and to our reserves report dated February 1, 2017, into the Registration Statement on and Form S-8 (File No. 333-213565), filed with the U.S. Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ DANNY D. SIMMONS

Danny D. Simmons, P.E.
President and Chief Operating Officer

Houston, Texas
February 28, 2017



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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS



## CERTIFICATION

I, Floyd C. Wilson, certify that:

1. I have reviewed this Annual Report on Form 10-K of Halcón Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2017

By: /s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board, Chief Executive Officer and President



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Exhibit 31.1

CERTIFICATION



## CERTIFICATION

I, Mark J. Mize, certify that:

1. I have reviewed this Annual Report on Form 10-K of Halcón Resources Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2017

By: /s/ MARK J. MIZE

Mark J. Mize
Executive Vice President, Chief Financial Officer and Treasurer



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Exhibit 31.2

CERTIFICATION



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Exhibit 32

# Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), Floyd C. Wilson, Chairman of the Board, Chief Executive Officer and President, and Mark J. Mize, Executive Vice President, Chief Financial Officer and Treasurer, of Halcón Resources Corporation, (the "Company"), each hereby certifies that, to the best of his knowledge:

(1) The Company's Annual Report on Form 10-K for the year ended December 31, 2016 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2017

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board, Chief Executive Officer and President

February 28, 2017

/s/ MARK J. MIZE

Mark J. Mize
Executive Vice President, Chief Financial Officer and Treasurer

This certification accompanies this Form 10-K and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that Section.

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.



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Exhibit 32

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)



Mr. Steve Herod
Halcón Resources Corporation
1000 Louisiana Street, Suite 6700
Houston, Texas 77002

Dear Mr. Herod:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2016, to the Halcón Resources Corporation (Halcón) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Halcón and its subsidiaries. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Halcón's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Halcón interest in these properties, as of December 31, 2016, to be:

<table><tr><td rowspan="2">Category</td><td colspan="2">Net Reserves</td><td colspan="2">Future Net Revenue (M$)</td></tr><tr><td>Oil (MBBL)</td><td>NGL (MBBL)</td><td>Gas (MMCF)</td><td>Total</td></tr><tr><td>Proved Developed Producing</td><td>66,164.9</td><td>9,080.8</td><td>50,340.0</td><td>1,062,281.4</td></tr><tr><td>Proved Developed Non-Producing</td><td>1,818.0</td><td>256.3</td><td>1,185.7</td><td>32,968.6</td></tr><tr><td>Proved Undeveloped</td><td>51,616.8</td><td>6,303.9</td><td>28,712.7</td><td>570,090.5</td></tr><tr><td>Total Proved</td><td>119,599.6</td><td>15,641.0</td><td>80,238.4</td><td>1,665,340.5</td></tr></table>

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Halcón's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Halcón's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the

effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2016. For oil and NGL volumes, the average West Texas Intermediate spot price of $42.75 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.481 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $37.31 per barrel of oil, $7.00 per barrel of NGL, and $1.926 per MCF of gas.

Operating costs used in this report are based on operating expense records of Halcón. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels and Halcón's estimate of the portion of its headquarters general and administrative overhead expenses necessary to manage the properties. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Halcón's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs and are not escalated for inflation.

Capital costs used in this report were provided by Halcón and are based on authorizations for expenditure and actual costs from recent activity. Capital costs



are included as required for workovers, fracture stimulations, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Halcón's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Halcón interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Halcón receiving its net revenue interest share of estimated future gross production. Additionally, we have made no investigation of any firm transportation contracts that may be in place for these properties; no adjustments have been made to our estimates of future revenue to account for such contracts.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Halcón, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Halcón, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. J. Carter Henson, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1989 and has over 8 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III
By:
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

/s/ J. Carter Henson, Jr.
By:
J. Carter Henson, Jr., P.E. 73964
Senior Vice President

/s/ Mike K. Norton
By:
Mike K. Norton, P.G. 441
Senior Vice President

Date Signed: February 1, 2017

Date Signed: February 1, 2017

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## DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves — Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves — Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7



gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

## DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(I) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.



Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Definitions - Page 3 of 7

## DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.



(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 4 of 7

## DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence



exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservation. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7

## DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.



(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

- The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

- The company’s historical record at completing development of comparable long-term projects;

- The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

- The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

- The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.