Battalion Oil Corp (BATL, NYSE)
Annual report, fiscal year 2012


# 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, 2012

Commission File Number: 001-35467

# Halcón Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)
20-0700684
(I.R.S. Employer 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 ( \( §232.405 \)  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 ☐

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 25, 2013, there were 366,928,463 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, 2012, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $573.0 million.

## DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13, and 14, is incorporated by reference to portions of the registrant's definitive proxy statement for its






## TABLE OF CONTENTS

PART I

ITEM 1. Business 7
ITEM 1A. Risk factors 28
ITEM 1B. Unresolved staff comments 41
ITEM 2. Properties 41
ITEM 3. Legal proceedings 41
ITEM 4. Mine safety disclosures 41

PART II

ITEM 5. Market for registrant's common equity, related stockholder matters and issuer purchases of equity securities 42
ITEM 6. Selected financial data 44
ITEM 7. Management's discussion and analysis of financial condition and results of operations 45
ITEM 7A. Quantitative and qualitative disclosures about market risk 67
ITEM 8. Consolidated financial statements and supplementary data 69
ITEM 9. Changes in and disagreements with accountants on accounting and financial disclosure 140
ITEM 9A. Controls and procedures 140
ITEM 9B. Other information 140

PART III

ITEM 10. Directors, executive officers and corporate governance 141
ITEM 11. Executive compensation 141
ITEM 12. Security ownership of certain beneficial owners and management and related stockholder matters 141
ITEM 13. Certain relationships and related transactions, and director independence 142
ITEM 14. Principal accountant fees and services 142

PART IV

ITEM 15. Exhibits and financial statements schedules 143






## 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 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," "believe," "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. One should consider carefully the statements 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 the forward-looking statements, including, but not limited to, the following factors:

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

- the possibility that acquisitions may involve unexpected costs or delays, will not achieve intended benefits and will divert management's time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;

• risks in connection with potential acquisitions and the integration of significant acquisitions;

• we have substantial indebtedness and may incur more debt; higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

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

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

• our ability to secure firm transportation and other marketing outlets for the natural gas, natural gas liquids and crude oil and condensate we produce and to sell these products at market prices;

• access to adequate gathering systems and transportation take-away capacity, necessary to fully execute our capital program;

• constraints in the Williston Basin and Utica areas with respect to gathering, transportation and processing facilities and marketing;

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

• volatility in commodity prices for oil and natural gas;

• our ability to replace oil and natural gas reserves;

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

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

• our ability to retain key members of senior management and key technical employees;

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

• environmental risks;



## Table of Contents

• drilling and operating risks;

• exploration and development risks;

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

• 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 financial markets;

• 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 pricing;

• the insurance coverage maintained by us will adequately cover all losses that may be sustained in connection with all oil and natural gas activities;

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

• 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

• 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.

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.

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.

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 Btus.

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.

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

We have included definitions of technical terms important to an understanding of our business under "Glossary of Oil and Natural Gas Terms."

Unless the context otherwise requires, all references in this report to "Halcon," "our," "us," and "we" refer to Halcon Resources Corporation (formerly known as RAM Energy Resources, Inc.) and its subsidiaries, as a common entity. On February 10, 2012, we completed a one-for-three reverse stock split of our common stock. All share and per share information in this report has been adjusted to reflect the reverse stock split.

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 and were recapitalized on February 8, 2012, as described more fully herein. Historically, our producing properties have been located in basins with long histories of oil and natural gas operations. During 2012 we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas and now have an extensive drilling inventory in multiple basins that we believe allows for multiple years of profitable production growth and provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns.

At December 31, 2012, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), were approximately 108.8 million barrels of oil equivalent (MMBoe), consisting of 87.4 million barrels (MMBbls) of oil, 5.4 MMBbls of natural gas liquids, and 96.1 billion cubic feet (Bcf) of natural gas. Approximately 47% of our proved reserves were classified as proved developed. We maintain operational control of approximately 93% of our proved reserves.

Our oil and natural gas assets consist of a combination of undeveloped acreage positions in unconventional liquids-rich basins/fields and mature liquids-weighted reserves and production in more conventional basins/fields. We have mature oil and natural gas reserves located primarily in Texas, North Dakota, Louisiana, Oklahoma and Montana. We have acquired acreage and may acquire additional acreage in the Utica / Point Pleasant formations in Ohio and Pennsylvania, the Woodbine / Eagle Ford formations in East Texas, the Bakken / Three Forks formations in North Dakota and Montana, the Tuscaloosa Marine Shale formation in Louisiana, the Midway / Navarro formations in Southeast Texas and the Wilcox formation in Texas and Louisiana as well as several other areas.

Our total operating revenues for 2012 were approximately $247.9 million. Production for the fourth quarter of 2012 averaged 18,348 barrels of oil equivalent per day (Boe/d). Full year 2012 production averaged 9,404 Boe/d compared to 4,121 Boe/d in 2011, resulting in a 128% year over year increase in our average daily production. The increase in production compared to the prior year was driven by our acquisitions of GeoResources, Inc. (GeoResources), the East Texas Assets (defined below) and the Williston Basin Assets (defined below), partially offset by a slight production decline from existing properties. The acquisition of GeoResources, the East Texas Assets and the Williston Basin Assets combined to contribute approximately 5,320 Boe/d of the increase. In 2012, we participated in the drilling of 192 gross (88.2 net) wells of which 189 gross (85.3 net) wells were completed and capable of production, and 3 gross (2.9 net) wells were dry holes. We also drilled and completed 6 gross (5.0 net) salt water disposal wells.



## Recent Developments

## Acquisition of Williston Basin Assets

On December 6, 2012, we completed the acquisition of entities owning approximately 81,000 net acres prospective for the Bakken / Three Forks formations primarily located in Williams, Mountrail, McKenzie and Dunn Counties, North Dakota (the Williston Basin Assets), from two affiliated privately held companies, Petro-Hunt, L.L.C. and Pillar Energy, LLC (the Petro-Hunt parties) for a total adjusted purchase price of approximately $1.5 billion, consisting of approximately $756.1 million in cash and approximately $695.2 million in newly issued shares of our preferred stock. We issued a total of approximately 10,880 shares of our 8% Automatically Convertible Preferred Stock, par value $0.0001 per share. Following the approval by our stockholders, on January 18, 2013 each outstanding share of our preferred stock converted into 10,000 shares of our common stock at an effective conversion price of approximately $7.45 per share based on the liquidation preference. Accordingly, on that date an aggregate of 108.8 million shares of our common stock was issued to the Petro-Hunt parties. No cash dividends were paid on the convertible preferred stock as it converted into common stock before April 6, 2013. No proceeds were received by us upon conversion of the preferred stock.

The borrowing base for our Senior Credit Agreement was increased to $850.0 million after the closing of the Williston Basin Assets acquisition. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding our acquisition of the Williston Basin Assets.

## Merger with GeoResources, Inc.

On August 1, 2012, we acquired GeoResources by merger (the Merger) for a total purchase price of $854.4 million. As consideration, we paid a combination of $20.00 in cash, and issued 1.932 shares of our common stock, for each share of GeoResources' common stock that was issued and outstanding on the closing date and also assumed GeoResources' outstanding warrants. We issued a total of approximately 51.3 million shares of common stock and paid approximately $531.5 million in cash to former GeoResources stockholders in exchange for their shares of GeoResources common stock. GeoResources' oil and natural gas properties include acreage in the Bakken / Three Forks formations in North Dakota and Montana, the Austin Chalk trend and Eagle Ford Shale in Texas. The acquisition expanded our presence in these areas as well as added properties in Oklahoma and Louisiana, which added oil and natural gas reserves and production to our existing asset base. GeoResources' production for the year ended December 31, 2011 was 1.9 MMBoE. Prior to the Merger, we and GeoResources operated as separate companies. GeoResources' results of operations are reflected in our results from and after August 1, 2012. Accordingly, the comparison to prior period results of operations and financial condition set forth below relate solely to us. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding the Merger.

## East Texas Assets Acquisition

In early August 2012, we acquired an operated interest in 20,628 net acres of oil and natural gas leaseholds in East Texas (the East Texas Assets) from several private oil and natural gas entities for consideration of $426.8 million comprised of approximately $296.1 million in cash and 20.8 million shares of our common stock, subject to normal closing adjustments. The properties consist of producing and nonproducing acreage believed to be prospective for the Woodbine, Eagle Ford and other formations. The East Texas Assets results of operations are reflected in our results from and after August 1, 2012. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding the East Texas Assets acquisition.



## Table of Contents

## Acquisition of Unevaluated Acreage

On June 28, 2012, we acquired a working interest in acreage in Eastern Ohio that we believe is prospective for the Utica / Point Pleasant formations. The purchase price in the transaction was approximately $164.0 million. We funded the acquisition with cash on hand.

## Other Recent Developments

## Offering of Additional 8.875% Senior Notes

On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of our 8.875% senior unsecured notes due 2021 (the Additional 2021 Notes). The Additional 2021 Notes were issued at 105% of par and provided net proceeds of approximately $619.5 million (after deducting offering fees). The net proceeds from this offering were used to repay all of the outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program. There was no borrowing base reduction to our Senior Credit Agreement as a result of the issuance of the Additional 2021 Notes.

## Common Stock Purchase Agreement

On December 6, 2012, we received net proceeds of approximately $294.0 million from the private placement of 41.9 million shares of our common stock with Canada Pension Plan Investment Board (CPPIB), which acquired the shares for a purchase price of approximately $7.16 per share.

## Offering of 8.875% Senior Notes

On November 6, 2012, we completed a private offering of $750.0 million aggregate principal amount of our 8.875% senior notes due 2021 (the 2021 Notes). The 2021 Notes were issued at 99.247% of par and provided net proceeds of approximately $725.6 million (after deducting offering fees and expenses). The net proceeds from this offering were used to fund a portion of the cash consideration paid in our acquisition of the Williston Basin Assets.

## Offering of 9.75% Senior Notes

On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 (the 2020 Notes). The 2020 Notes were issued at 98.646% of par and provided net proceeds of approximately $723.1 million (after deducting offering fees and expenses). The net proceeds from this offering were used to fund a portion of the cash consideration paid in the Merger and East Texas Assets acquisition.

## Preferred Stock Offering

On March 5, 2012, we sold in a private placement 4,444.4511 shares of 8% automatically convertible preferred stock (Preferred Stock), par value $0.0001 per share, each share of which automatically converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the Preferred Stock as it converted into common stock before May 31, 2012. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 12, "Preferred Stock and Stockholders' Equity," for additional information regarding the offering and subsequent conversion.



## Recapitalization

On February 8, 2012, HALRES LLC, formerly, Halcón Resources, LLC (HALRES), a newly-formed limited liability company led by Floyd C. Wilson, recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8.0% convertible note and warrants for the purchase of an additional 36.7 million shares of our common stock at an exercise price of $4.50 per share (Recapitalization). Information regarding our Recapitalization is set forth under Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Recapitalization."

## Senior Revolving Credit Agreement

In connection with the closing of the Recapitalization, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders on February 8, 2012. Initially, the Senior Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, 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 our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that we may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. Advances under the Senior Credit Agreement are secured by liens on substantially all of our properties and assets. The Senior Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on our capital stock and financial covenants relating to current ratio and minimum interest coverage ratio.

On August 1, 2012, in connection with the closing of the Merger and East Texas Assets acquisition, we entered into the First Amendment to the Senior Credit Agreement (the First Amendment). The First Amendment increased the commitments under the Senior Credit Agreement to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. On December 6, 2012, the borrowing base was increased from $525.0 million to $850.0 million. At December 31, 2012, we had $298.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $550.7 million of borrowing capacity available under the Senior Credit Agreement.

On January 25, 2013, we entered into the Second Amendment which amends the Senior Credit Agreement with respect to our ability to enter into certain commodity hedging agreements (the Second Amendment). The Second Amendment provides, among other things, that we and our subsidiaries may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of our internally forecasted production (i) from our crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, from such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, we may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% (i) of the reasonably anticipated projected production from our proved reserves for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, of the reasonably anticipated projected production from proved reserves from such oil and gas properties that are the subject of such proposed



acquisition for the period of 25 to 48 months following the date such agreement is entered into. The 85% limitations discussed above do not apply to our volumes hedged by using puts, floors and/or basis differential swap agreements.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from our proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas liquids and natural gas, for the 66 months following the date such agreement was entered into.

## 2013 Capital Budget

We expect to spend approximately $1.2 billion on drilling and completion capital expenditures during 2013. While this amount represents the vast majority of our expected capital expenditures in 2013, we will also incur additional capital expenditures associated with ongoing leasing efforts, transportation, infrastructure, and seismic and other expenditures. Of the $1.2 billion budget for drilling and completions, approximately $475 million is planned for the Bakken / Three Forks formations in North Dakota, approximately $490 million is budgeted for Woodbine / Eagle Ford formations in East Texas, approximately $200 million is planned for the Utica / Point Pleasant formations in Ohio and Pennsylvania with the remaining amount planned for various other project areas. Our 2013 drilling and completion budget contemplates six to eight operated rigs running in the Bakken / Three Forks, five to seven operated rigs running in the Woodbine / Eagle Ford and two to three operated rigs running in the Utica / Point Pleasant. Our drilling and completion budget for 2013 is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our budgeted 2013 capital expenditures with cash flows from operations, proceeds from potential non-core asset divestitures and 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 or proceeds from potential asset dispositions are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may 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 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 leverage our management team's expertise and the latest available technologies to economically develop our existing property portfolio with a focus on our core liquids-rich resource style plays. We expect to be the operator for the majority of our acreage,



which gives us more control over timing, execution and costs. It also allows us to adjust our capital expenditure plans 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 operator, we will also be able to evaluate industry drilling results to implement improved operating practices which may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital. We currently have 17 operated rigs running in our core resource plays, and another three operated rigs running in our non-core areas.

• Manage Our Property Portfolio Actively. We continually evaluate our property base to identify and divest non-core areas, higher cost or lower volume producing properties with limited development potential. This strategy allows us to focus on a portfolio of core resource plays with significant potential to increase our proved reserves and production. We expect that divestitures of non-core area assets will provide us with cash to reinvest in our business and repay our current debt and/or future debt we may incur, reducing our reliance on the capital markets for financing.

• Maintain Strong Balance Sheet. We believe our cash, internally generated cash flows, borrowing capacity, asset sales and access to the 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 has a successful track record of issuing equity and debt, and selling non-core assets to maintain a strong balance sheet. Since February 2012, Halcón has issued an aggregate approximately $3.4 billion of equity and debt securities. 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 with Significant Ownership Stake. Our management team and technical professionals, including geologists and engineers, have decades of combined experience in the industry. Our management team has successfully founded, grown, operated and sold companies in this industry sector. Floyd C. Wilson was Chairman and Chief Executive Officer of Petrohawk Energy Corporation, which was acquired by BHP Billiton in August 2011, Chairman and Chief Executive Officer of 3TEC Energy Corporation, which was acquired by Plains Exploration & Production Company in 2003, and Chairman and Chief Executive Officer of Hugoton Energy Corporation, which was acquired by Chesapeake Energy Corporation in 1998.

Geographically and Geologically Diverse Asset Base. Our proved reserves, production and acreage are located in concentrated positions within multiple onshore U.S. basins. These various 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 project 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. In addition to their 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. The technical staff (including field personnel) currently represents a majority of Halcón's employee base. This 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 capabilities, 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

Estimates of proved reserves at December 31, 2012 were prepared by Netherland, Sewell, our independent consulting petroleum engineers. Our estimated proved reserves for the years ended December 31, 2011 and 2010 were prepared by Forrest A. Garb & Associates, an independent oil and natural gas reservoir engineering consulting firm. Netherland, Sewell is 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 J. Carter Henson, Jr. and Mike K. Norton. Mr. Henson has been practicing consulting petroleum engineering at Netherland, Sewell since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 27 years of experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton has been practicing consulting petroleum geology at Netherland, Sewell since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 30 years of practical experience in petroleum geosciences, with over 23 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. 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 Securities and Exchange Commission (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 Manager, Corporate Reserves for 2012. 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 accept the report prepared by our independent consulting petroleum engineers. In 2012, the Manager, Corporate Reserves was the technical person primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. He holds a Bachelor of Science degree in Mechanical Engineering from The University of Missouri-Rolla and has over 35 years of experience in reservoir engineering, economic modeling and reserve evaluation.

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, 2012. Average prices for the 12-month period were as follows: West Texas Intermediate (WTI) spot price of $94.71 per barrel (Bbl) for oil and natural gas liquids, adjusted by lease or field for quality, transportation fees, and regional price differentials and a Henry Hub spot price of $2.76 per million British thermal unit (Mmbtu) for natural gas, as adjusted by lease or field for energy content, transportation fees, and regional price differentials. All prices and costs associated with operating wells were held constant in accordance with the amended SEC guidelines. The following table presents certain information as of December 31, 2012.

<table><tr><td></td><td>Total</td></tr><tr><td>Proved Reserves at Year End (MBoe)(1)</td><td></td></tr><tr><td>Developed</td><td>51,399</td></tr><tr><td>Undeveloped</td><td>57,386</td></tr><tr><td>Total</td><td>108,785</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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, 2012 and 2011. Shut-in wells currently not capable of production are excluded from producing well information.

<table><tr><td rowspan="3"></td><td colspan="5">Years Ended December 31,</td></tr><tr><td colspan="2">2012</td><td colspan="2">2011</td><td></td></tr><tr><td>Gross</td><td>Net(1)</td><td>Gross</td><td>Net(1)</td><td></td></tr><tr><td>Oil</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2,428</td><td>1,396.0</td><td>1,424</td><td>1,116.5</td><td></td></tr><tr><td>Natural Gas</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>893</td><td>425.6</td><td>396</td><td>186.1</td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>3,321</td><td>1,821.6</td><td>1,820</td><td>1,302.6</td><td></td></tr></table>

(1) Net wells represent our working interest share of each well. The term "net" as used in "net acres" or "net production" throughout this document refers to amounts that include only acreage or production that we own and produce to our interest, less royalties and production due to others.



## Oil and Natural Gas Production

## Core Resource Plays

At December 31, 2012, we have estimated proved reserves in our core resource plays of approximately 75.6 MMBoe, of which 92% are oil and natural gas liquids and 38% are proved developed. 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 128,000 net acres as of December 31, 2012 prospective for the Bakken / Three Forks formations in North Dakota and Montana. Multiple initiatives are underway to lower costs and improve recoveries in our operated project areas. We expect to spud 65 to 75 gross horizontal wells on our operated acreage in 2013 with an average working interest of 63%. We expect to operate an average of six to eight rigs throughout 2013 in the Williston Basin. As of December 31, 2012, we had approximately 105 operated wells producing in this area in addition to minor working interest in hundreds of non-operated wells. Our average daily net production from this area for the three months ended December 31, 2012 was 5,753 Boe/d. As of December 31, 2012, proved reserves for the Bakken / Three Forks formations were approximately 48.6 MMBoe, of which approximately 45% were classified as proved developed and approximately 55% as proved undeveloped.

## Woodbine / Eagle Ford Formations

Our Woodbine / Eagle Ford acreage is prospective for the Woodbine, Eagle Ford and other formations, with targeted depths ranging anywhere from 7,000 feet to 10,400 feet. Our hydrocarbon stream is largely comprised of oil and natural gas liquids, which receive premium pricing given their proximity to key United States markets for these products. As of December 31, 2012, we had approximately 198,000 net acres leased or under contract primarily in Leon, Madison, Grimes, Brazos, and Polk Counties, Texas. Leasing efforts will continue in key areas as we develop the field. We finished 2012 with a six rig drilling program and approximately 25 producing wells. In 2013, we plan to run an average of five to seven rigs and spud 75 to 85 gross horizontal wells with an average working interest of approximately 90%. Our average daily net production from this area for the three months ended December 31, 2012 was 2,807 Boe/d. As of December 31, 2012, proved reserves for the Woodbine / Eagle Ford formations were approximately 27 MMBoe, of which approximately 24% were classified as proved developed and approximately 76% as proved undeveloped.

## Utica / Point Pleasant Formations

We believe the Utica / Point Pleasant formations in Ohio and Pennsylvania are in some areas geologically analogous to the Eagle Ford Shale based on reservoir thickness, porosity, water saturation and permeability. We are focused on what we believe to be the volatile oil and liquids-rich gas window in the play, and as of December 31, 2012, we had approximately 125,000 net acres leased or under contract in Trumbull and Mahoning Counties, Ohio, and Mercer, Venango and Crawford Counties, Pennsylvania. Substantially all of our acreage in these areas is either held by shallow production or provides for five years to drill a well plus a renewal option for an additional five years. We expect to spud 20 to 25 gross horizontal wells in 2013 with an average working interest of approximately 91%. We are currently operating two rigs in the Utica / Point Pleasant formations and expect to operate an average of two to three rigs throughout 2013. We expect to gain drilling efficiencies while lowering well costs through the use of pad drilling once a sufficient backlog of approved drilling permits has been established. Due to infrastructure requirements, combined with the practice of shutting in wells for up to 60 days after completion in an effort to maximize recoveries, we estimate a spud-to-production time



of 120 days per well. As of the date of this report, two wells are resting after being completed, two wells are being completed or waiting on completion and two wells are being drilled. First production is anticipated early in the second quarter of 2013. As of December 31, 2012, we did not have any proved reserves for the Utica / Point Pleasant formations. We can provide no assurance that this exploratory area, or any wells we subsequently drill in these formations we have targeted for exploration and development, will be successful.

## Non-Core Areas

## Electra-Burkburnett Field

We are the operator and have a 100% working interest in more than 12,000 net acres in Wichita and Wilbarger Counties, Texas that we are actively water flooding in shallow Cisco aged Pennsylvania sandstone and limestone reservoirs. In 2012, we produced 484 MBoE, or 1,322 Boe/d, from approximately 700 active producing wells and approximately 230 active water injection wells. We are currently running one company owned drilling rig and nine company owned work over rigs to improve injection and production well patterns, maximize injection profiles, and increase production performance. Management believes that significant reserve upside can be achieved through the modification and expansion of the existing water flood. During 2012, we drilled a total of 38 gross (38.0 net) wells, 31 gross (31.0 net) producers and 7 gross (7.0 net) injectors in our Electra-Burkburnett Field. The positive production response from our 640 acre water flood modification pilot on the west side of the field focused our efforts to set up a field wide water flood modification program. It is believed that the modified water flood will improve areal and vertical sweep efficiency and thereby accelerate production withdrawal rates, reduce production decline rates, and increase reserve recovery. We are also improving upon the reservoir geological correlation and are targeting injection into areas that were not previously produced.

During the second quarter of 2012, we began working on the first lease of the modified water flood expansion project by investing $9 million on operations across the 1,100 acre lease. We drilled a total of 20 gross (20.0 net) wells in 2012, 13 gross (13.0 net) producers and 7 gross (7.0 net) injectors in addition to multiple well conversions and workovers to re-activate both injectors and producers. The project is currently ahead of schedule (approximately 70% complete) and is producing oil at rates above the projected response rates. Additional leases will be added as scheduled and as the project is expanded to optimize production and recoverable reserve potential across our leasehold. As of December 31, 2012, the estimated proved reserves for our Electra-Burkburnett Field were approximately 7.1 MMBoe, or 7% of our total proved reserves, of which approximately 54% were classified as proved developed and 46% as proved undeveloped. The natural gas liquids are processed from the casing head gas through a company owned gas plant. We believe that additional reserves will be added to adjacent leases above the reserves currently booked as we expand our project boundaries and the modified leases respond to the more favorable water flood configuration. In addition to the water flood modification, management also believes that additional upside potential exists with the recompletion of previously bypassed zones and from inefficiently connected reservoirs not previously swept.

## La Copita Field

Our position in the La Copita Field covers 3,720 gross acres and 2,829 net acres in Starr County, Texas. For the year ended December 31, 2012, our average net daily production was 623 Boe/d. We operate 100% of this production and our working interest ranges from 75% to 100%. The production is primarily natural gas with a high concentration of natural gas liquids producing from Vicksburg Sands at depths ranging from approximately 7,200 feet to 10,500 feet. We did not drill any new wells during 2012. Estimated proved reserves for the Field totaled 3.0 MMBoe as of December 31, 2012.



## Other Areas

We have various other oil and natural gas properties with varying working interests located across the United States, including the Austin Chalk Trend and Eagle Ford Shale in Texas, the Fitts-Allen Fields in Central Oklahoma, and various other areas across South Louisiana, Montana, North Dakota, New Mexico, and West Virginia. Production from these areas totaled 1,607 MBoe, or 4,391 Boe/d, in 2012. As of December 31, 2012, proved reserves for these other properties were approximately 23.1 MMBoe in aggregate, of which approximately 78% were classified as proved developed and approximately 22% as proved undeveloped. We are currently pursuing certain activities to enhance these assets, including redesigning existing waterflood programs. We will consider divesting certain of these assets that we determine are non-core and reinvesting the proceeds in our core resource plays.

## Liquids-Rich Exploratory Plays

In addition to the disclosed areas, we anticipate we will continue to acquire acreage in undisclosed unconventional exploratory plays as opportunities arise. We would expect to utilize multi-stage hydraulic fracturing to complete wells drilled in these areas. Our strategy for our exploratory projects is to use our in-house geologic expertise to identify underdeveloped 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. Due to competitive concerns, we intend to keep the details of such plays confidential until such time we deem it appropriate to disclose specifics.

## 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 and interest rate increases. Derivative contracts are utilized to economically 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. We hedge a substantial, but varying, portion of anticipated oil and natural gas production for the next 18 to 24 months. Historically, we entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those on our Senior Credit Agreement) to fixed interest rates.

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. While there are many different types of derivatives available, we typically use costless collar agreements, swap agreements and 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 market price of oil and natural gas for the period is greater or less than the fixed price established for that period when the swap agreement is put in place. Under put option agreements, we pay a fixed premium to lock in a specified floor price. If the index price falls below the 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, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender or an affiliate of a lender in our Senior Credit Agreement. 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 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="7">Years Ended December 31,</td></tr><tr><td colspan="2">2012</td><td colspan="2">2011</td><td colspan="2">2010</td><td></td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td></td></tr><tr><td>Exploratory Wells:</td><td></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><td></td></tr><tr><td>Dry</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2</td><td>2.0</td><td>4</td><td>4.0</td><td>1</td><td>0.2</td><td></td></tr><tr><td>Total Exploratory</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>3</td><td>2.9</td><td>10</td><td>10.0</td><td>4</td><td>3.2</td><td></td></tr><tr><td>Extension Wells(2):</td><td></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><td></td></tr><tr><td></td><td>101</td><td>30.1</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><td></td></tr><tr><td></td><td>1</td><td>0.9</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total Extension</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>102</td><td>31.0</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><td></td></tr><tr><td>Productive(1)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>87</td><td>54.3</td><td>43</td><td>38.8</td><td>59</td><td>51.0</td><td></td></tr><tr><td>Dry</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>1</td><td>0.2</td><td>—</td><td>—</td><td></td></tr><tr><td>Total Development</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>87</td><td>54.3</td><td>44</td><td>39.0</td><td>59</td><td>51.0</td><td></td></tr><tr><td>Total Wells:</td><td></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><td></td></tr><tr><td></td><td>189</td><td>85.3</td><td>49</td><td>44.8</td><td>62</td><td>54.0</td><td></td></tr><tr><td>Dry</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>3</td><td>2.9</td><td>5</td><td>4.2</td><td>1</td><td>0.2</td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>192</td><td>88.2</td><td>54</td><td>49.0</td><td>63</td><td>54.2</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.

(2) An extension well is a well drilled to extend the proven limits of a known reservoir.

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 terms. The following table presents a summary of our acreage interests as of December 31, 2012:

<table><tr><td rowspan="2">State</td><td colspan="2">Developed Acreage</td><td colspan="2">Undeveloped Acreage</td><td colspan="2">Total Acreage</td></tr><tr><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td><td>Gross</td><td>Net</td></tr><tr><td>Alabama</td><td>42,480</td><td>21,240</td><td>—</td><td>—</td><td>42,480</td><td>21,240</td></tr><tr><td>Colorado</td><td>3,724</td><td>2,403</td><td>25,858</td><td>12,959</td><td>29,582</td><td>15,362</td></tr><tr><td>Louisiana</td><td>17,773</td><td>10,311</td><td>177,664</td><td>161,123</td><td>195,437</td><td>171,434</td></tr><tr><td>Montana</td><td>15,478</td><td>7,403</td><td>13,924</td><td>5,942</td><td>29,402</td><td>13,345</td></tr><tr><td>New Mexico</td><td>12,657</td><td>8,393</td><td>280</td><td>40</td><td>12,937</td><td>8,433</td></tr><tr><td>North Dakota</td><td>278,792</td><td>95,564</td><td>136,235</td><td>46,218</td><td>415,027</td><td>141,782</td></tr><tr><td>Ohio</td><td>—</td><td>—</td><td>47,871</td><td>45,367</td><td>47,871</td><td>45,367</td></tr><tr><td>Oklahoma</td><td>116,593</td><td>35,348</td><td>24,700</td><td>16,311</td><td>141,293</td><td>51,659</td></tr><tr><td>Pennsylvania</td><td>—</td><td>—</td><td>83,407</td><td>79,705</td><td>83,407</td><td>79,705</td></tr><tr><td>Texas</td><td>126,611</td><td>74,082</td><td>495,567</td><td>262,323</td><td>622,178</td><td>336,405</td></tr><tr><td>West Virginia</td><td>7,835</td><td>7,726</td><td>27,804</td><td>22,349</td><td>35,639</td><td>30,075</td></tr><tr><td>All others</td><td>6,580</td><td>2,969</td><td>101,238</td><td>63,177</td><td>107,818</td><td>66,146</td></tr><tr><td>Total Acreage</td><td>628,523</td><td>265,439</td><td>1,134,548</td><td>715,514</td><td>1,763,071</td><td>980,953</td></tr></table>

The table below reflects the percentage of our total net undeveloped and mineral acreage as of December 31, 2012 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.



At December 31, 2012, we had estimated proved reserves of approximately 108.8 MMBoe comprised of 87.4 MMBbls of oil, 5.4 MMBbls of natural gas liquids, and 96.1 Mmcf of natural gas. The following table sets forth, at December 31, 2012, 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></table>



<table><tr><td></td><td>38,429</td><td>48,949</td><td>87,378</td></tr><tr><td>Natural Gas Liquids (MBbls)</td><td></td><td></td><td></td></tr><tr><td></td><td>3,172</td><td>2,211</td><td>5,383</td></tr><tr><td>Natural Gas (Mmcf)</td><td></td><td></td><td></td></tr><tr><td></td><td>58,785</td><td>37,360</td><td>96,145</td></tr><tr><td>Equivalent (MBoe)(1)</td><td></td><td></td><td></td></tr><tr><td></td><td>51,399</td><td>57,386</td><td>108,785</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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, 2012, our estimated proved undeveloped (PUD) reserves were approximately 57.4 MMBoе, a 49.7 MMBoе net increase over the previous year's estimate of 7.7 MMBoе. The increase is largely due to acquisitions totaling 42.9 MMBoе of undeveloped reserves primarily in the Bakken / Three Forks and Woodbine / Eagle Ford areas. As of December 31, 2012, more than 97% of our PUD reserves are less than five years old. The following details the changes in proved undeveloped reserves for 2012 (MBoе):



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—"Supplementary 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 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. At December 31, 2012 the ceiling test value of our reserves was calculated based on the first day average of the 12-months ended December 31, 2012 of the WTI spot price of $94.71 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first day average of the 12-months ended December 31, 2012 of the Henry Hub price of $2.76 per Mmbtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, our net book value of oil and natural gas properties at December 31, 2012, did not exceed the ceiling amount. 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, 2012, 2011 and 2010 are summarized as follows:

<table><tr><td rowspan="3"></td><td colspan="3">December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td colspan="3">(In thousands)</td></tr><tr><td>Oil and natural gas properties (full cost method):</td><td></td><td></td><td></td></tr><tr><td>Evaluated</td><td></td><td></td><td></td></tr><tr><td>Unevaluated</td><td></td><td></td><td></td></tr><tr><td>Gross oil and natural gas properties</td><td></td><td></td><td></td></tr><tr><td>Less—accumulated depletion</td><td></td><td></td><td></td></tr><tr><td>Net oil and natural gas properties</td><td></td><td></td><td></td></tr><tr><td></td><td>$ 4,407,636</td><td>$ 213,673</td><td>$ 206,586</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 colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></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></td><td></td><td></td><td></td></tr><tr><td>Woodbine / Eagle Ford</td><td>650</td><td>—</td><td>—</td><td></td></tr><tr><td>Electra/Burkburnett</td><td>372</td><td>—</td><td>—</td><td></td></tr><tr><td>La Copita</td><td>437</td><td>441</td><td>471</td><td></td></tr><tr><td>Other</td><td>16</td><td>24</td><td>41</td><td></td></tr><tr><td>Total</td><td>940</td><td>419</td><td>483</td><td></td></tr><tr><td>Natural gas—Mmcf</td><td>2,415</td><td>884</td><td>995</td><td></td></tr><tr><td>Bakken / Three Forks</td><td></td><td></td><td></td><td></td></tr><tr><td>Woodbine / Eagle Ford</td><td>224</td><td>—</td><td>—</td><td></td></tr><tr><td>Electra/Burkburnett</td><td>129</td><td>—</td><td>—</td><td></td></tr><tr><td>La Copita</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Other</td><td>914</td><td>1,079</td><td>1,682</td><td></td></tr><tr><td>Total</td><td>3,287</td><td>1,583</td><td>3,134</td><td></td></tr><tr><td>Natural gas liquids—MBbl</td><td>4,554</td><td>2,662</td><td>4,816</td><td></td></tr><tr><td>Bakken / Three Forks</td><td></td><td></td><td></td><td></td></tr><tr><td>Woodbine / Eagle Ford</td><td>13</td><td>—</td><td>—</td><td></td></tr><tr><td>Electra/Burkburnett</td><td>26</td><td>—</td><td>—</td><td></td></tr><tr><td>La Copita</td><td>47</td><td>44</td><td>41</td><td></td></tr><tr><td>Other</td><td>60</td><td>83</td><td>126</td><td></td></tr><tr><td>Total</td><td>122</td><td>49</td><td>197</td><td></td></tr><tr><td>Production:</td><td>268</td><td>176</td><td>364</td><td></td></tr></table>



<table><tr><td>Total MBoe(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>3,442</td><td>1,504</td><td>2,161</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>9,404</td><td>4,121</td><td>5,921</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>$ 92.36</td><td>$ 93.86</td><td>$ 76.95</td></tr><tr><td>Natural gas price—Mcf</td><td></td><td>2.74</td><td>4.01</td><td>4.21</td></tr><tr><td>Natural gas liquids price—Bbl</td><td></td><td>41.37</td><td>56.14</td><td>38.89</td></tr><tr><td>Barrel of oil equivalent price—Boe(1)</td><td></td><td>71.64</td><td>68.83</td><td>51.36</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>$ 14.51</td><td>$ 19.98</td><td>$ 13.95</td></tr><tr><td>Workover and other</td><td></td><td>1.29</td><td>1.31</td><td>0.74</td></tr><tr><td>Taxes other than income</td><td></td><td>5.59</td><td>4.80</td><td>3.93</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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 2012, 2011 and 2010 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 2012, 2011 and 2010 average crude oil sales prices were $93.25, $91.84 and $74.88 per Bbl and average natural gas sales prices were $3.56, $4.95 and $4.58 per Mcf.

## 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 and the states in which our properties are located. 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. In 2012, two individual purchasers of our production, Shell Trading US Co. (STUSCO) and Sunoco Partners Marketing & Terminals L.P., (Sunoco), each accounted for approximately 20% and 19%, respectively, of our total sales.

In 2011, STUSCO accounted for $70.4 million, or 68%, of our oil and natural gas revenue for the year. In 2011, we were subject to a crude purchase contract with STUSCO covering all of our production in our Electra Field in Wichita and Wilbarger Counties, Texas. The contract term covered the period of January 1, 2011 through December 31, 2011. We were also subject to a crude purchase contract with STUSCO, in 2011, covering all of our oil production in our Fitts and Allen Fields in Oklahoma. Effective December 1, 2011, we cancelled the crude purchase contract with STUSCO and entered into a new crude oil purchase agreement with Sunoco for a term of December 1, 2011 through May 31, 2012.

In 2010, STUSCO, accounted for $68.1 million, or 61%, of our oil and natural gas revenue for the year. No other purchaser accounted for 10% or more of our oil and natural gas revenue during 2010. Our agreement with STUSCO covered all of our North Texas oil production. We were also subject to a crude purchase contract with STUSCO covering all of our oil production in our Fitts and Allen Fields in Oklahoma.

## 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



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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 leakage 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 materially adverse 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 include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas properties, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the establishment of maximum allowable rates of production from fields and individual wells. 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.

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 which 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 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 that must be addressed before those activities can proceed.



## Environmental Regulations

Our operations are subject to stringent federal, state 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. Failure to comply with these 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.

Environmental regulatory programs typically regulate the permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can issue a cease and desist order to terminate operations. New programs and changes in existing programs are anticipated, some of which include natural occurring radioactive materials, oil and natural gas exploration and production, 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.

## Comprehensive Environmental Response, Compensation and Liability Act and Hazardous Substances

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 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, companies that incur liability frequently confront additional claims because 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.

## The Solid Waste Disposal Act and Waste Management

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, generally does not regulate most wastes generated by the exploration and production of oil and natural gas because that act specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies as non-hazardous wastes as long as these wastes are not commingled with regulated hazardous wastes. Moreover, in the ordinary course of our operations, wastes generated in connection with our exploration and production activities may be regulated as hazardous waste under RCRA or 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 these materials or wastes. At this time, with respect to any properties where materials or wastes may have been released, but of which we



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have not been made aware, it is not possible to estimate the potential costs that may arise from unknown, latent liability risks.

## The Clean Water Act, wastewater and storm 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 will apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make 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.

## The Safe Drinking Water Act, groundwater protection, and the Underground Injection Control Program

The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. 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. 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. Certain states have adopted and are considering laws that require the disclosure of the chemical constituents in hydraulic fracturing fluids. In addition, in 2010, the EPA announced that it would be conducting a study on the environmental effects of hydraulic fracturing. In December 2012, the EPA issued a progress report describing its ongoing study, and announcing its expectation that a final draft report will be released for public comment and peer review in 2014.

Additional disclosure requirements could result in increased regulation, operational delays, and increased operating costs that could make it more difficult to perform hydraulic fracturing.

## The Clean Air Act

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions 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. 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.



## Climate change legislation and greenhouse gas regulation

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol 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 begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and required reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting which went into effect September 2012. Beyond measuring and reporting, the EPA 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 serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. On July 28, 2011, the EPA proposed four new regulations for the oil and natural gas industry, with the potential to affect our business. On August 16, 2012, the EPA issued its final rule, which includes: a new source performance standard for volatile organic compounds (VOCs); a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. The final rule includes the first federal air standards for natural gas wells that are hydraulically fractured, or refractured, as well as requirements for several sources, such as storage tanks and other equipment, and limits methane emissions from these sources. Compliance with these regulations will impose additional requirements and costs on our operations.

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.

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, and additional compliance costs.

## The National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are 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.



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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, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and 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 oil and gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and in some cases, criminal penalties.

## Hazard communications and community right to know

We are subject to federal and state hazard communications and community right to know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances, including, but not limited to, the federal Emergency Planning and Community Right-to-Know Act.

## Occupational Safety and Health Act

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

## Employees and Principal Office

As of December 31, 2012, we had 435 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, 2012, we lease corporate office space in Houston, Texas at 1000 Louisiana Street, where our principal offices are located. We also lease corporate offices in Plano, Texas; Tulsa, Oklahoma; Denver, Colorado; and Williston, North Dakota 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.halcomresources.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 New York Stock Exchange (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

We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

Our business plan contemplates 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, such as the Merger and our acquisitions of the East Texas Assets and the Williston Basin Assets. 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, 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 not entitled to contractual indemnification for environmental liabilities and 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 the 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.

## Assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due significantly to acquisitions of exploration and production companies, producing properties and undeveloped and unevaluated leaseholds. We expect acquisitions may also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an "as is" basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We have incurred substantial debt amounting to approximately $2.1 billion as of December 31, 2012 (including current portion). 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 under the indentures. At December 31, 2012, our Senior Credit Agreement was a $1.5 billion facility with a borrowing base of $850.0 million. As of December 31, 2012, we had $298.0 million of debt outstanding, $1.3 million of letters of credit outstanding and $550.7 million of additional borrowing capacity available under this facility.

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 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.

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

At December 31, 2012, our corporate credit rating was "B" with a stable outlook by Standard and Poor's (S&P) and "B2" and under review for downgrade 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. Future deterioration in 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.

Part of our strategy involves drilling in shale formations, some of which are new and emerging, 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 new or emerging formations, such as the Utica / Point Pleasant formations, Bakken / Three Forks formations and Woodbine / Eagle Ford 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 and consequently we are less able to predict future drilling results in these areas. 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. Our experience, as well as that of the industry as a whole, is significant but still growing. The ultimate success of these 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 we could incur material write downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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, 2012, we owned leasehold interests in approximately 128,000 net acres in areas we believe are prospective for the Bakken / Three Forks formations, approximately 198,000 net acres in areas we believe are prospective for the Woodbine / Eagle Ford formations and 125,000 net acres in areas we believe are prospective for the Utica / Point Pleasant formations. A large portion of our acreage is not currently held by production. Unless production in paying quantities is established



on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans for these areas 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 there is therefore additional risk of expirations occurring in sections where we are not the operator.

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 currently 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. Currently, we anticipate that additional pipeline capacity will be required in the Bakken / Three Forks formations to transport oil and condensate production, which increased substantially during 2012 and is expected to continue to increase. 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, 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.

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

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs, primarily as a result of our drilling program. We intend to 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 likely 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, proceeds from potential asset dispositions and proceeds from potential future capital markets transactions, if necessary, to fund capital expenditures that are in excess of our cash flow and cash on hand.

Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. Our borrowing base was $850.0 million as of December 31, 2012 with $298.0 million outstanding. Our borrowing base is determined semi-annually, and may also be redetermined periodically at the discretion of the banks. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, the indentures governing our senior unsecured 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 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 under the most restrictive indenture. The second test applies only to borrowings under our Senior Credit Agreement that do not meet the first test and it limits these borrowings to the greater of a fixed sum of $750 million and 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. 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 adjusted consolidated net tangible assets, 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.

## 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 redetermination 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;

• 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.

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 and results of operations.

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, 2012, approximately 53% of our estimated 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. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

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



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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 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.

## 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 or drilling fluids, 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 adversely 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 complex federal, state, local and other laws and regulations 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, 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 these laws may result in the suspension or termination of operations and subject us to liabilities under administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws 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 these laws and other environmental health and safety laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. Some laws and regulations 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 the regulation by oil and natural gas-producing states relating to conservation practices and protection of correlative rights. These 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.

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

Legislation was proposed in the last Congress to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations 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 many of the wells for which we are the operator. If similar legislation is ultimately adopted, it could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Certain states have adopted or are considering similar disclosure legislation.

In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. In December 2012, the EPA issued a progress report describing its ongoing study, and announcing its expectation that a final draft report will be released for public comment and peer review in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.



## 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 to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol 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 begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and required reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. On July 19, 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting beginning in September 2012. Beyond measuring and reporting, the EPA 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 serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. On July 28, 2011, the EPA proposed four new regulations for the oil and natural gas industry, with the potential to affect our business. On August 16, 2012, the EPA issued its final rule, which includes: a new source performance standard for volatile organic compounds (VOCs); a new source performance standard for sulfur dioxide; an air toxics standard for oil and natural gas production; and an air toxics standard for natural gas transmission and storage. The final rule includes the first federal air standards for natural gas wells that are hydraulically fractured, or refracted, as well as requirements for several sources, such as storage tanks and other equipment, and limits methane emissions from these sources. Compliance with these regulations will impose additional requirements and costs on our operations.

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.

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, and additional compliance costs.

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 43,000 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 are generally 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.

Recent federal legislation 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 and, periodically, interest expense. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act which requires the SEC, the Commodity Futures Trading Commission (or CFTC) to promulgate rules and regulations implementing the new legislation. The CFTC has issued 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 exempt from these limits. The CFTC also finalized other regulations implementing the new legislation; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. The Dodd-Frank Act and regulations may require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities. The legislation may also require the counterparties to our commodity derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new 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, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the new legislation and regulations, 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 new legislation and 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 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;



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• 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 materially adverse 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 every claim 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.

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 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 negatively 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 additional hedging transactions in the future. While intended to reduce the effects of volatile oil, natural gas and natural gas liquids prices, such transactions may limit our potential gains and increase our potential losses if oil, natural gas and natural gas liquids 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 may be required to take non-cash asset write downs if oil and natural gas prices decline.

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 decline 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.

As of December 31, 2012, our net book value of oil and natural gas properties did not exceed our ceiling amount using the WTI unweighted 12-month average price $94.71 per Bbl for oil and natural gas liquids and the Henry Hub unweighted 12-month average of $2.76 per Mmbtu for natural gas. As ceiling test computations depend upon the calculated unweighted arithmetic average prices, it is impossible to predict the likelihood, timing and magnitude of any future impairments. Depending on the magnitude, a ceiling test write down could negatively affect our results of operations.

Costs associated with unevaluated properties, which were approximately $2.3 billion at December 31, 2012, 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 amortization 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 amortization and the ceiling test limitation.



## Table of Contents

## Our results of operations could be adversely affected as a result of non-cash goodwill impairments.

In conjunction with the recording of the purchase price allocation for the Merger, we recorded goodwill which represents the excess of the purchase price paid by us plus liabilities assumed, including deferred taxes recorded in connection with the acquisition, over the estimated fair market value of the tangible net assets acquired.

The Financial Accounting Standard Board's (FASB) Accounting Standards Codification (ASC) 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. If the fair value of the reporting unit is less than the book value (including goodwill), then goodwill is reduced to its implied fair value and the amount of the write down is charged against earnings. The assumptions we used in calculating our reporting unit fair value at the time of the test include our market capitalization and discounted future cash flows based on estimated reserves and production, future costs and future oil and natural gas prices. Adverse changes to any of these factors could lead to an impairment of all or a portion of our goodwill in future periods.

## 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

## ITEM5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock began trading on the New York Stock Exchange (NYSE) under the symbol HK on March 26, 2012. Following the Recapitalization, from February 9, 2012 to March 25, 2012, our common stock traded on the Nasdaq Capital Market under the symbol HK. Effective February 9, 2012, we changed the trading symbol under which our common stock traded on the Nasdaq Capital Market from RAM to HK. Effective May 6, 2011, we changed the trading symbol under which our common stock traded on the Nasdaq Capital Market from RAMe to RAM. The following table sets forth the quarterly high and low sales prices per share of our common stock as reported on the NYSE and Nasdaq Capital Market from January 1, 2011 through December 31, 2012. All share prices reflect the one-for-three reverse stock split, which was effective February 10, 2012.

<table><tr><td></td><td>High</td><td>Low</td></tr><tr><td>2012</td><td></td><td></td></tr><tr><td>First Quarter</td><td></td><td></td></tr><tr><td>Second Quarter</td><td>$ 12.76</td><td>$ 8.46</td></tr><tr><td>Third Quarter</td><td>11.02</td><td>8.30</td></tr><tr><td>Fourth Quarter</td><td>9.46</td><td>6.26</td></tr><tr><td>2011</td><td></td><td></td></tr><tr><td>First Quarter</td><td></td><td></td></tr><tr><td>Second Quarter</td><td>$ 7.35</td><td>$ 4.68</td></tr><tr><td>Third Quarter</td><td>6.36</td><td>3.66</td></tr><tr><td>Fourth Quarter</td><td>3.75</td><td>2.04</td></tr></table>

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 of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors 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 694 registered stockholders of record as of February 25, 2013 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

During the three months ended December 31, 2012, there was no repurchase of shares of our common stock nor were there any shares surrendered by employees in exchange for the payment of tax withholding as no awards were vested during the period. All sales of our unregistered equity securities during the year ended December 31, 2012 were previously reported.

## Five-Year Stock Performance Graph

The following common stock performance graph shows the performance of our common stock through December 31, 2012. As required by applicable rules of the SEC, the performance graph shown below was prepared based on the following assumptions:

• A $100 investment was made in Halcón common stock and each index on December 31, 2007.

• All quarterly dividends were reinvested at the average of the closing stock prices at the beginning and end of the quarter.



The following graph and table compare the cumulative 5-year total return provided to our stockholders on our common stock beginning December 31, 2007 through December 31, 2012, relative to the cumulative total returns of the Nasdaq Composite Index and the Dow Jones Wilshire MicroCap Exploration & Production Index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on December 31, 2007, and in each of the indexes and its relative performance is tracked through December 31, 2012. The identity of the companies included in the Dow Jones Wilshire MicroCap Exploration & Production Index will be provided upon request.

Halcón changed its indexes from NASDAQ Composite to NYSE Composite and from the Dow Jones US TSM MicroCap Exploration and Production to the S&P Midcap Oil & Gas Exploration & Production due to the transfer of its stock listing from the NASDAQ to the NYSE in March of 2012 and a change in peer group due increased market capitalization.

## COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN \( ^{*} \) 

Among Halcón Resources Corporation, the NASDAQ Composite Index, the NYSE Composite Index, the S&P Midcap Oil & Gas Exploration & Production Index, and Dow Jones US TSM MicroCap Exploration & Production Index



Value of Initial $100 Investment (End of Year)

<table><tr><td></td><td>12/07</td><td>12/08</td><td>12/09</td><td>12/10</td><td>12/11</td><td>12/12</td></tr><tr><td>Halcón Resources Corporation</td><td>100.00</td><td>17.53</td><td>40.84</td><td>36.65</td><td>62.35</td><td>45.95</td></tr><tr><td>NASDAQ Composite</td><td>100.00</td><td>59.03</td><td>82.25</td><td>97.32</td><td>98.63</td><td>110.78</td></tr><tr><td>NYSE Composite</td><td>100.00</td><td>60.74</td><td>77.92</td><td>88.36</td><td>84.96</td><td>98.55</td></tr><tr><td>Dow Jones US TSM MicroCap Exploration &amp; Production</td><td>100.00</td><td>54.28</td><td>66.48</td><td>76.44</td><td>57.97</td><td>43.96</td></tr><tr><td>S&amp;P Midcap Oil &amp; Gas Exploration &amp; Production</td><td>100.00</td><td>41.25</td><td>70.14</td><td>99.41</td><td>85.92</td><td>76.02</td></tr></table>



## ITEM 6. SELECTED FINANCIAL DATA

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 Item 1. Business—Recent Developments, for details regarding the recent acquisitions and business combinations that could impact the comparability of the following data.

<table><tr><td rowspan="3"></td><td colspan="6">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td>2009(6)</td><td>2008(7)</td><td></td></tr><tr><td colspan="5">(In thousands, except per share data)</td><td></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>$ 247,945</td><td>$ 103,689</td><td>$ 111,141</td><td>$ 98,384</td><td>$ 183,072</td><td></td></tr><tr><td>Income (loss) from operations</td><td>(29,717)</td><td>19,799</td><td>24,526</td><td>(44,476)</td><td>(206,911)</td><td></td></tr><tr><td>Net income (loss)</td><td>(53,885)</td><td>(1,403)</td><td>2,417</td><td>(58,383)</td><td>(129,953)</td><td></td></tr><tr><td>Net income (loss) available to common stockholders</td><td>(142,330)</td><td>(1,403)</td><td>2,417</td><td>(58,383)</td><td>(129,953)</td><td></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>$ (0.91)</td><td>$ (0.05)</td><td>$ 0.09</td><td>$ (2.26)</td><td>$ (5.40)</td><td></td></tr><tr><td>Diluted</td><td>$ (0.91)</td><td>$ (0.05)</td><td>$ 0.09</td><td>$ (2.26)</td><td>$ (5.40)</td><td></td></tr><tr><td></td><td colspan="6">As of December 31,</td></tr><tr><td></td><td>2012</td><td>2011(8)</td><td>2010(8)</td><td>2009(8)</td><td>2008(8)</td><td></td></tr><tr><td></td><td colspan="5">(In thousands)</td><td></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>$ (390,111)</td><td>$ (7,620)</td><td>$ (13,878)</td><td>$ (15,899)</td><td>$ (4,558)</td><td></td></tr><tr><td>Total assets</td><td>5,041,025</td><td>267,174</td><td>260,733</td><td>306,894</td><td>399,696</td><td></td></tr><tr><td>Total long-term debt(2)(4)</td><td>2,034,498</td><td>202,000</td><td>196,965</td><td>246,041</td><td>250,536</td><td></td></tr><tr><td>Preferred stock(3)</td><td>695,238</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Stockholders&#x27; equity (deficit)(4)(5)</td><td>1,397,982</td><td>1,680</td><td>(101)</td><td>(4,794)</td><td>53,572</td><td></td></tr></table>

(1) No cash dividends were declared or paid for any periods presented.

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

(3) Preferred Stock outstanding at December 31, 2012 converted into 108.8 million shares of Halcón common stock on January 18, 2013, following stockholder approval.

(4) On December 21, 2011, we entered into a Securities Purchase Agreement with HALRES LLC, formerly Halcón Resources, LLC (HALRES) in which HALRES purchased and we sold 73.3 million shares of our common stock for a purchase price of $275 million and HALRES purchased and we issued a senior convertible promissory note in the principal amount of $275 million, together with five year warrants to purchase 36.7 million shares of our common stock at an exercise price of $4.50 per share, subject to adjustment under certain circumstances. For additional information regarding this recapitalization, see Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Recapitalization.")

(5) On March 5, 2012, we sold in a private placement 4,444.4511 shares of 8% automatically convertible preferred stock (Preferred Stock), par value $0.0001 per share, each share of which automatically converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the Preferred Stock as it converted into common stock before May 31, 2012. Refer to Item 8. Consolidated Financial






Supplementary Data—Note 12, "Preferred Stock and Stockholders' Equity," for additional information regarding the offering and subsequent conversion.

(6) We incurred a $47.6 million impairment on the carrying value of our oil and natural gas properties for the year ended December 31, 2009.

(7) We incurred a $269.9 million impairment on the carrying value of our oil and natural gas properties for the year ended December 31, 2008.

(8) Previously issued consolidated financial statements as of and for the years ended December 31, 2011, 2010, 2009 and 2008 have been restated, see Item 8. Consolidated Financial Statements and Supplementary Data—Note 2, "Corrections of Immaterial Errors."

## 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.

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 assets in the United States. We were incorporated in Delaware on February 5, 2004 and were recapitalized on February 8, 2012, as described more fully herein. Historically, our producing properties have been located in basins with long histories of oil and natural gas operations. During 2012, we focused our efforts on the acquisition of unevaluated leasehold and producing properties in selected prospect areas. We now have an extensive drilling inventory in multiple basins that we believe allow for multiple years of profitable production growth and provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns.

At December 31, 2012, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), were approximately 108.8 MMBoe, consisting of 87.4 MMBb's of oil, 5.4 MMBb's of natural gas liquids, and 96.1 Bcf of natural gas. Approximately 47% of our proved reserves were classified as proved developed. We maintain operational control of approximately 93% of our proved reserves. Production for the fourth quarter of 2012 averaged 18,348 Boe/d. Full year 2012 production averaged 9,404 Boe/d compared to 4,121 Boe/d in 2011. Our total operating revenues for 2012 were approximately $247.9 million compared to $103.7 million in 2011.

Our oil and natural gas assets consist of a combination of undeveloped acreage positions in unconventional liquids-rich basins/fields and mature liquids-weighted reserves and production in more conventional basins/fields. We have mature oil and natural gas reserves located primarily in Texas, North Dakota, Louisiana, Oklahoma and Montana. We have acquired acreage and may acquire additional acreage in the Utica / Point Pleasant formations in Ohio and Pennsylvania, the Woodbine / Eagle Ford formations in East Texas, the Bakken / Three Forks formations in North Dakota and Montana, the Tuscaloosa Marine Shale formation in Louisiana, the Midway / Navarro formations in Southeast Texas and the Wilcox formation in Texas and Louisiana as well as several other undisclosed locations.



Our average daily production increased 128% year over year. The increase in production compared to the prior year period was driven by our acquisitions of GeoResources, Inc. (GeoResources), the East Texas Assets (defined below) and the Williston Basin Assets (defined below), partially offset by a slight production decline from existing properties. The acquisition of GeoResources, the East Texas Assets and the Williston Basin Assets combined to contribute approximately 5,320 Boe/d of the increase. In 2012, we participated in the drilling of 192 gross (88.2 net) wells of which 189 gross (85.3 net) wells were completed and capable of production, and 3 gross (2.9 net) wells were dry holes. We also drilled and completed 6 gross (5.0 net) salt water disposal wells.

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.

For the twelve months ended December 31, 2012 we incurred capital expenditures for drilling, completions and leasehold costs of approximately $1.3 billion as compared to a budget of $1.1 billion. Capital spending was more than budgeted primarily because of increased drilling and completion activity in the Bakken / Three forks formations related to the acquisition of the Williston Basin Assets in addition to increased leasing activity in the Utica / Point Pleasant formations.

We expect to spend approximately $1.2 billion on drilling and completion capital expenditures during 2013. While this amount represents the vast majority of our expected capital expenditures in 2013, we will also incur additional capital expenditures associated with ongoing leasing efforts, transportation, infrastructure and seismic and other expenditures. Of the $1.2 billion budget for drilling and completions, approximately $475 million is planned for the Bakken / Three Forks formations in North Dakota, approximately $490 million is budgeted for Woodbine / Eagle Ford formations in East Texas, approximately $200 million is planned for the Utica / Point Pleasant formations in Ohio and Pennsylvania with the remaining amount planned for various other project areas. Our 2013 drilling and completion budget contemplates six to eight operated rigs running in the Bakken / Three Forks, five to seven operated rigs running in the Woodbine / Eagle Ford and two to three operated rigs running in the Utica / Point Pleasant. Our drilling and completion budget for 2013 is based on our current view of market conditions and current business plans, and is subject to change.

We expect to fund our budgeted 2013 capital expenditures with cash flows from operations, proceeds from potential non-core asset divestitures and 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 or proceeds from potential asset dispositions are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

## Recent Acquisitions

## Acquisition of Williston Basin Assets

On December 6, 2012, we completed the acquisition of entities owning a total of approximately 81,000 net acres prospective for the Bakken / Three Forks formations primarily located in Williams, Mountrail, McKenzie and Dunn Counties, North Dakota (the Williston Basin Assets), from two



affiliated privately held companies, Petro-Hunt, L.L.C. and Pillar Energy, LLC (the Petro-Hunt parties) for a total adjusted purchase price of approximately $1.5 billion, consisting of approximately $756.1 million in cash and approximately $695.2 million in newly issued shares of our preferred stock. We issued a total of 10,880 shares of our 8% Automatically Convertible Preferred Stock, par value $0.0001 per share. Following the approval by our stockholders, on January 18, 2013, each outstanding share of our preferred stock converted into 10,000 shares of our common stock at an effective conversion price of approximately $7.45 per share based on the liquidation preference. Accordingly, on that date an aggregate of 108.8 million shares of our common stock was issued to the Petro-Hunt parties. No cash dividends were paid on the convertible preferred stock as it converted into common stock before April 6, 2013. No proceeds were received by us upon conversion of the preferred stock.

The borrowing base for our Senior Credit Agreement was increased to $850.0 million after the closing of the Williston Basin Assets acquisition. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding our acquisition of the Williston Basin Assets.

## Merger with GeoResources, Inc.

On August 1, 2012, we acquired GeoResources by merger (the Merger) for a total purchase price of $854.4 million. As consideration, we paid a combination of $20.00 in cash, and issued 1.932 shares of our common stock, for each share of GeoResources' common stock that was issued and outstanding on the closing date and also assumed GeoResources' outstanding warrants. We issued a total of approximately 51.3 million shares of common stock and paid approximately $531.5 million in cash to former GeoResources stockholders in exchange for their shares of GeoResources common stock. GeoResources' oil and natural gas properties include acreage in the Bakken / Three Forks formations in North Dakota and Montana, and the Austin Chalk trend and Eagle Ford Shale in Texas. The acquisition expanded our presence in these areas as well as added properties in Oklahoma and Louisiana, which added oil and natural gas reserves and production to our existing asset base. GeoResources' production for the year ended December 31, 2011 was 1.9 MMboe. Prior to the Merger, we and GeoResources operated as separate companies. GeoResources' results of operations are reflected in our results from and after August 1, 2012. Accordingly, the comparison to prior period results of operations and financial condition set forth below relate solely to us. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding the Merger.

## East Texas Assets Acquisition

In early August 2012, we acquired an operated interest in 20,628 net acres of oil and natural gas leaseholds in East Texas (the East Texas Assets) from several private oil and natural gas companies for consideration of $426.8 million comprised of approximately $296.1 million in cash and 20.8 million shares of our common stock, subject to normal closing adjustments. The properties consist of producing and nonproducing acreage believed to be prospective for the Woodbine, Eagle Ford and other formations. The East Texas Assets results of operations are reflected in our results from and after August 1, 2012. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 5, "Acquisitions and Divestitures," for additional information regarding the East Texas Assets acquisition.

## Acquisition of Unevaluated Acreage and Other

On December 28, 2012, we completed the acquisition of certain oil and natural gas properties, located in Brazos County, Texas, from a group of private sellers for approximately $83.7 million, before customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. The promissory notes have a maturity date of August 30, 2013. The transaction had an effective date of December 1, 2012. Refer to Item 8. Consolidated Financial



## Table of Contents

Statements and Supplementary Data—Note 7, "Long-term debt," for more details regarding the promissory notes.

On September 12, 2012, we completed the acquisition of certain oil and natural gas properties, located in Leon County, Texas from a group of private sellers for approximately $14.0 million, before customary closing adjustments. The transaction had an effective date of September 1, 2012. The acquisition was funded with cash on hand.

On June 28, 2012, we acquired a working interest in approximately 27,000 net acres in Eastern Ohio that we believe is prospective for the Utica / Point Pleasant formations. The purchase price in the transaction was approximately $164.0 million. We funded the acquisition with cash on hand. No oil or natural gas production or proved reserves were attributable to the acquired assets.

In addition to the forgoing acquisitions, during 2012 we incurred approximately $915.6 million in capital expenditures on unevaluated oil and gas leaseholds through numerous leasing and acquisition transactions. No oil or natural gas production or proved reserves were attributable to the acquired unevaluated leasehold assets which were primarily located in Texas, Louisiana, Ohio and Pennsylvania.

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.

## Other Recent Developments

## Offering of Additional 8.875% Senior Notes

On January 14, 2013, we completed the issuance of an additional $600 million aggregate principal amount of our 8.875% senior unsecured notes due 2021 (the Additional 2021 Notes). The Additional 2021 Notes were issued at 105% of par and provided net proceeds of approximately $619.5 million (after deducting offering fees). The net proceeds from this offering were used to repay all of the outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program. There was no borrowing base reduction to our Senior Credit Agreement as a result of the issuance of the Additional 2021 Notes.

## Common Stock Purchase Agreement

On December 6, 2012, we received net proceeds of approximately $294.0 million from the private placement of 41.9 million shares of our common stock with Canada Pension Plan Investment Board (CPPIB), which acquired the shares for a purchase price of approximately $7.16 per share.

## Offering of 8.875% Senior Notes

On November 6, 2012, we completed a private offering of $750 million aggregate principal amount of our 8.875% senior notes due 2021 (the 2021 Notes). The 2021 Notes were issued at 99.247% of par and provided net proceeds of approximately $725.6 million (after deducting offering fees and expenses). The net proceeds from this offering were used to fund a portion of the cash consideration paid in our acquisition of the Williston Basin Assets.



## Offering of 9.75% Senior Notes

On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 (the 2020 Notes). The 2020 Notes were issued at 98.646% of par and provided net proceeds of approximately $723.1 million (after deducting offering fees and expenses). The net proceeds from this offering were used to fund a portion of the cash consideration paid in the Merger and East Texas Assets acquisition.

## Preferred Stock Offering

On March 5, 2012, we sold in a private placement 4,444.4511 shares of 8% automatically convertible preferred stock (Preferred Stock), par value $0.0001 per share, each share of which automatically converted into 10,000 shares of our common stock on April 17, 2012. We received gross proceeds of approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. No cash dividends were paid on the Preferred Stock as it converted into common stock before May 31, 2012. The Preferred Stock was considered to have a beneficial conversion feature because the proceeds per share, approximately $9.00 per share of common stock, were less than the fair value of our common stock of $10.99 per common share on the commitment date. The estimated fair value allocated to the beneficial conversion feature was $88.4 million and was recorded to additional paid-in capital, creating a discount on the Preferred Stock (the Discount). The Discount resulting from the allocation of value to the beneficial conversion feature was required to be amortized over the 71-month contractual period from issuance to required redemption, or fully amortized upon an accelerated date of redemption or conversion, by increasing Preferred Stock and recording the offsetting amount as a deemed non-cash Preferred Stock dividend. During the three months ended March 31, 2012, we amortized the Discount and recorded a non-cash preferred dividend of $1.1 million. Due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of the Discount amortization was accelerated to the conversion date and reflected as a non-cash preferred dividend in April 2012.

## Recapitalization

On February 8, 2012, HALRES LLC, formerly, Halcón Resources, LLC (HALRES), a newly-formed limited liability company led by Floyd C. Wilson, recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8.0% convertible note and warrants for the purchase of an additional 36.7 million shares of our common stock at an exercise price of $4.50 per share (Recapitalization). Information regarding our Recapitalization is set forth under Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Recapitalization."

## Senior Revolving Credit Agreement

In connection with the closing of the Recapitalization, we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders on February 8, 2012. Initially, the Senior Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, 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 our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that we may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year



term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. Advances under the Senior Credit Agreement are secured by liens on substantially all of our properties and assets. The Senior Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on our capital stock and financial covenants relating to current ratio and minimum interest coverage ratio.

On August 1, 2012, in connection with the closing of the Merger and East Texas Assets acquisition, we entered into the First Amendment to the Senior Credit Agreement (the First Amendment). The First Amendment increased the commitments under the Senior Credit Agreement to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. On December 6, 2012, the borrowing base was increased from $525.0 million to $850.0 million. At December 31, 2012, we had $298.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $550.7 million of borrowing capacity available under the Senior Credit Agreement.

On January 25, 2013, we entered into the Second Amendment which amends the Senior Credit Agreement with respect to our ability to enter into certain commodity hedging agreements (the Second Amendment). The Second Amendment provides, among other things, that we and our subsidiaries may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of our internally forecasted production (i) from our crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, from such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, we may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% (i) of the reasonably anticipated projected production from our proved reserves for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, of the reasonably anticipated projected production from proved reserves from such oil and gas properties that are the subject of such proposed acquisition for the period of 25 to 48 months following the date such agreement is entered into. The 85% limitations discussed above do not apply to our volumes hedged by using puts, floors and/or basis differential swap agreements.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from our proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas liquids and natural gas, for the 66 months following the date such agreement was entered into.



## Capital Resources and Liquidity

The proceeds provided by our recent financing activities have enabled us to increase our focus on expanding our leasehold position in liquids-rich resource areas. We have acquired and/or identified several core resource plays for additional leasing, including the Bakken / Three Forks formations in North Dakota, Utica / Point Pleasant formations in Ohio and Pennsylvania and the Woodbine / Eagle Ford formations in East Texas. In addition to our ongoing lease acquisition efforts in our core resource plays, we have identified several new exploratory areas we believe are prospective for oil and liquids-rich hydrocarbons. In 2012, excluding the Merger and acquisitions of the East Texas Assets and Williston Basin Assets, we invested $1.2 billion on oil and natural gas capital expenditures. The majority of these expenditures were for acreage in the Utica / Point Pleasant and Woodbine / Eagle Ford formations. Additionally, in 2012, we paid approximately $579.5 million, $756.1 million and $296.1 million respectively, in the Merger, the Williston Basin Assets Acquisition and the East Texas Assets Acquisition.

Our near-term capital spending requirements are expected to be partially funded with cash flows from operations, proceeds from potential non-core asset dispositions, proceeds from potential capital market transactions and borrowings under our Senior Credit Agreement, which has a current borrowing base of $850.0 million. Our borrowing base is redetermined on a semi-annual basis (with us and the lenders each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including redeterminations of our borrowing base, and covenants under our Senior Credit Agreement and our senior unsecured debt indentures. Our Senior Credit Agreement contains customary financial and other covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0. We are subject to additional covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. Additionally, the indentures governing our senior unsecured 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, the fixed charge coverage ratio test, applies to all indebtedness and requires that after giving effect to the incurrence of additional debt 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 the amount of such additional indebtedness is not more than the greater of a fixed sum of $750 million or 30% of our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined primarily using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. At December 31, 2012, we had $298.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $550.7 million of borrowing capacity available under the Senior Credit Agreement.

We strive to maintain financial flexibility while continuing our aggressive 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. 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.

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 proven 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 success.

## Cash Flow

Our primary source of cash in 2012 was from financing activities. Our primary source of cash in 2011 and 2010 was from operating activities. In 2012, proceeds from the sale of common stock and preferred stock, the issuance of new senior debt and cash received from operations were offset by repayments of borrowings under our Senior Credit Agreement and cash used in investing activities to fund our drilling program and acquisition activities, net of divestiture activities. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal fluctuations characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See Results of Operations below for a review of the impact of prices and volumes on sales.

<table><tr><td rowspan="3"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td colspan="4">(In thousands)</td></tr><tr><td>Cash flows provided by operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 118,174</td><td>$ 29,835</td><td>$ 37,875</td><td></td></tr><tr><td>Cash flows provided by (used) investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(2,866,280)</td><td>(25,376)</td><td>14,970</td><td></td></tr><tr><td>Cash flows provided by (used) financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2,750,563</td><td>(4,447)</td><td>(52,937)</td><td></td></tr><tr><td>Net increase (decrease) in cash</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 2,457</td><td>$ 12</td><td>$ (92)</td><td></td></tr></table>

Operating Activities. Net cash flows provided by operating activities were $118.2 million, $29.8 million and $37.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs.

Net loss for the year ended December 31, 2012 was $53.9 million. Non-cash items, including $90.3 million of depreciation, depletion and accretion, $9.4 million of non-cash interest and amortization and $6.2 million of amortization and write-off of deferred loan costs served to offset this net loss. The Recapitalization, including change in control and related activities which occurred during February 2012, the Merger and acquisition transaction costs and the impact of additional personnel and facilities in support of the rapidly expanding business base, drove a significant increase in general and administrative expenditures, which adversely affected operating cash flows. The remaining improvement in operating cash flows is largely attributable to a favorable mix in working capital changes.

Net cash flows provided by operating activities decreased in 2011 primarily due to our 30% decrease in our average daily production volumes, which was partially offset by a 34% increase in our average realized Boe price compared to the same period in 2010.



Investing Activities. The primary driver of cash used in investing activities is capital spending, specifically the acquisition of unevaluated leaseholds in our targeted areas, the Merger and the acquisitions of the East Texas Assets and the Williston Basin Assets. Net cash used in investing activities was $2.9 billion and $25.4 million for the years ended December 31, 2012 and 2011, respectively. Net cash provided by investing activities was $15.0 million for the year ended December 31, 2010.

In 2012, we incurred cash expenditures of $579.5 million, net of cash acquired, on the Merger, $756.1 million on the acquisition of the Williston Basin Assets, and $296.1 million on the acquisition of the East Texas Assets. Additionally, we spent $1.2 billion on oil and natural gas capital expenditures. We participated in the drilling of 192 gross (88.2 net) wells of which 189 gross (85.3 net) wells were completed and capable of production and 3 gross (2.9 net) wells were dry holes. We also drilled and completed 6 gross (5.0 net) salt water disposal wells. We spent an additional $38.8 million on other operating property and equipment capital expenditures primarily related to infrastructure for gathering and transportation systems. Proceeds from sales of oil and gas properties were $22.0 million.

In 2011, we spent $25.2 million on capital expenditures of evaluated oil and natural properties. We drilled or participated in the drilling of 54 gross (49.0 net) wells on our oil and natural gas properties, of which, 49 gross (44.8 net) wells were successfully completed as producing wells, 5 gross (4.2 net) wells were abandoned wells and 7 gross (5.9 net) wells were either drilling or waiting to be completed at the end of that period.

In 2010, proceeds from sales of oil and natural gas properties of $49.4 million offset capital expenditures of $34.4 million as a result of property divestitures in conjunction with the execution of our strategic alternative initiative to reduce debt.

Financing Activities. Net cash flows provided by financing activities were $2.8 billion for the year ended December 31, 2012. Net cash flows used in financing activities were $4.4 million and $52.9 million for the years ended December 31, 2011 and 2010, respectively. The primary driver of cash provided by financing activities is proceeds from the issuance of common stock and preferred stock and long-term debt offset by repayments of long-term debt.

On December 6, 2012, in conjunction with the closing of the Williston Basin Assets acquisition, we received net proceeds of approximately $294.0 million from the private placement of 41.9 million shares of our common stock with CPPIB, which acquired the shares for a purchase price of approximately $7.16 per share.

On November 6, 2012, we sold, in a private offering to eligible purchasers, $750.0 million aggregate principal amount of our 8.875% senior notes due 2021. Net proceeds of $725.6 million from the offering were placed into escrow pending the acquisition of the Williston Basin Assets and were subsequently released upon closing and used to fund a portion of the cash consideration paid in the acquisition.

On June 29, 2012, we priced $750.0 million aggregate principal amount of 9.75% senior unsecured notes due 2020 in a private offering. Net proceeds from these notes of approximately $723.1 million were funded into escrow on July 16, 2012 and subsequently released from escrow on August 1, 2012 and utilized to fund portions of the Merger and East Texas Assets Acquisition.

On March 5, 2012, we received $400.0 million, subject to certain adjustments, from the private placement sale of convertible Preferred Stock.

On February 8, 2012, HALRES recapitalized us with a $550.0 million investment structured as the purchase of $275.0 million in new common stock, a $275.0 million five-year 8.0% convertible note and warrants for the purchase of an additional 36.7 million shares of our common stock at an exercise price of $4.50 per share (February 2012 Warrants). The convertible note provided $231.4 million cash flow



from borrowings and $43.6 million cash flow from warrants issued. In connection with the closing of the Recapitalization, we entered into the Senior Credit Agreement and terminated our March 2011 Credit Facilities with the payoff of the $210.8 million balance.

Cash flows provided by financing activities include net borrowings from our Senior Credit Agreement of $298.0 million for the year ended December 31, 2012, primarily due to our acquisition activities and our ongoing drilling activities.

## Contractual Obligations

We believe 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 and other related economic factors. Currently no sources of liquidity or financing are provided by 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, 2012.

<table><tr><td rowspan="2">Contractual Obligations</td><td colspan="5">Payments Due by Period</td></tr><tr><td>Total</td><td>2013</td><td>2014 - 2015 (In thousands)</td><td>2016 - 2017</td><td>2018 and Beyond</td></tr><tr><td>Promissory notes/(1)</td><td>$ 75,285</td><td>$ 75,285</td><td>$ —</td><td>$ —</td><td>$ —</td></tr><tr><td>Senior revolving credit facility</td><td>298,000</td><td>—</td><td>—</td><td>298,000</td><td>—</td></tr><tr><td>8.875% $750 million senior notes/(2)</td><td>750,000</td><td>—</td><td>—</td><td>—</td><td>750,000</td></tr><tr><td>9.75% $750 million senior notes/(3)</td><td>750,000</td><td>—</td><td>—</td><td>—</td><td>750,000</td></tr><tr><td>8.0% $275 million senior note/(4)</td><td>289,669</td><td>—</td><td>—</td><td>289,669</td><td>—</td></tr><tr><td>Interest expense on long-term debt/(5)</td><td>1,247,178</td><td>173,334</td><td>346,668</td><td>316,667</td><td>410,509</td></tr><tr><td>Operating leases</td><td>53,825</td><td>8,074</td><td>13,079</td><td>12,970</td><td>19,702</td></tr><tr><td>Drilling rig commitments</td><td>79,391</td><td>55,257</td><td>24,134</td><td>—</td><td>—</td></tr><tr><td>Other commitments</td><td>17,809</td><td>17,809</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total contractual obligations</td><td>$ 3,561,157</td><td>$ 329,759</td><td>$ 383,881</td><td>$ 917,306</td><td>$ 1,930,211</td></tr></table>

(1) Excludes $0.6 million unamortized discount recorded in conjunction with the issuance of the notes.

(2) Excludes $5.6 million unamortized discount recorded in conjunction with the issuance of the notes. On January 14, 2013, we issued an additional $600 million of these notes which are not reflected in the table. See "8.875% Senior Notes" below and Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Long-Term Debt" for more details.

(3) Excludes $9.8 million unamortized discount recorded in conjunction with the issuance of the notes. See "9.75% Senior Notes" below and Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Long-Term Debt" for more details.

(4) Excludes $37.8 million unamortized discount recorded in conjunction with the issuance of the note. See "8.0% Convertible Note" below for more details.

(5) Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2012 less required annual repayments.

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 amount of asset retirement obligations at December 31, 2012 was $75.1 million.

## Senior Revolving Credit Facility

In connection with the closing of the Recapitalization, discussed in Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, "Recapitalization", we entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders on February 8, 2012. Initially, the Senior Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, 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 our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that we may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on our utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of our properties and assets. The Senior Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of dividends on our capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0.

On August 1, 2012, in connection with the closing of the Merger and the East Texas Assets acquisition, we entered into the First Amendment to the Senior Credit Agreement (the First Amendment). The First Amendment increased the commitments under the Senior Credit Agreement to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. On December 6, 2012, the borrowing base was increased from $525.0 million to $850.0 million. At December 31, 2012, we had $298.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $550.7 million of borrowing capacity available under the Senior Credit Agreement.

On January 25, 2013, we entered into the Second Amendment (the Second Amendment) which amends the Senior Credit Agreement with respect to our ability to enter into certain commodity hedging agreements. The Second Amendment provides, among other things, that we and our subsidiary guarantors may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of our internally forecasted production (i) from our crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, from such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, we may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% (i) of the reasonably anticipated projected production from our proved reserves for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, of the reasonably anticipated projected production from proved reserves from such oil and gas properties that are the subject of such proposed acquisition for the period of 25 to 48 months following the date such



agreement is entered into. The 85% limitations discussed above do not apply to volumes hedged by us using puts, floors and/or basis differential swap agreements.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from our proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas and natural gas liquids, for the 66 months following the date such agreement was entered into.

## March 2011 Credit Facilities

Our March 2011 credit facilities included a $250.0 million revolving credit facility and a $75.0 million second lien term loan facility (the March 2011 Credit Facilities), replacing the November 2007 facility. SunTrust Bank was the administrative agent for the revolving credit facility, and Guggenheim Corporate Funding, LLC was the administrative agent for the second lien term loan facility. The revolving credit facility allowed for funds advanced to be paid down and re-borrowed during the five-year term of the revolver, and bore interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The second lien term loan facility provided for payments of interest only during its 5.5 year term, and bore interest at LIBOR plus 9.0% with a 2.0% LIBOR floor, or if any period we elected to pay a portion of the interest "in kind", then the interest rate would have been LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid-in-kind by being added to principal. At December 31, 2011, $127.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the second lien term loan facility. On February 8, 2012, we paid in full the outstanding balances under the revolving credit facility and the second lien term loan facility and both facilities were terminated, resulting in a $1.5 million charge to interest expense related to an early termination penalty.

## 8.875% Senior Notes

On November 6, 2012, we completed a private offering of $750.0 million aggregate principal amount of 8.875% senior unsecured notes due 2021, issued at 99.247% of par (the 2021 Notes). The net proceeds from the offering were approximately $725.6 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Williston Basin Assets acquisition.

The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. In connection with the issuance of the 2021 Notes, we recorded a discount of approximately $5.65 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $5.58 million at December 31, 2012.

On January 14, 2013, we completed the issuance of an additional $600.0 million aggregate principal amount of our 8.875% senior notes due 2021, issued at 105.000% of par (the additional 2021 Notes). The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees). The net proceeds from this offering were used to repay all of the outstanding borrowings under our Senior Credit Agreement and for general corporate purposes, including funding a portion of our 2013 capital expenditures program. There was no borrowing base reduction to our Senior Credit Agreement as a result of the issuance of the additional 2021 Notes. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Long-Term Debt," for additional information regarding the 2021 Notes.



## 9.75% Senior Notes

On July 16, 2012, we completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured 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 the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Merger and the East Texas Assets acquisition.

The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, which began on January 15, 2013. The 2020 Notes will mature on July 15, 2020. In connection with the issuance of the 2020 Notes, we recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $9.8 million at December 31, 2012. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, "Long-Term Debt," for additional information regarding the 2020 Notes.

## 8.0% Convertible Note

On February 8, 2012, we issued the 8.0% senior note in the principal amount of $275.0 million (the 2017 Note) together with the February 2012 Warrants for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, we may elect to pay-in-kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. We elected to pay the interest in-kind on March 31, June 30 and September 30, 2012, and rolled $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. For the three months ended December 31, 2012, we did not elect to pay-in-kind interest. At any time after February 8, 2014, the noteholder may elect to convert all or any portion of the principal amount and accrued but unpaid interest into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of our common stock. The 2017 Note is a senior unsecured obligation of ours.

We allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, we recorded a discount of $43.6 million to be amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $37.8 million at December 31, 2012.

## Promissory Notes

On December 28, 2012, we completed a transaction consisting of certain oil and natural gas properties in East Texas to expand our existing operations in that area, for approximately $83.7 million, before customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. The promissory notes accrue interest beginning March 29, 2013, to the extent there is a remaining principal balance of the promissory notes at such date. Interest accrues based on the Wall Street Journal Prime Rate effective March 29, 2013. The promissory notes mature on August 30, 2013 and were classified as current as of December 31, 2012.

In conjunction with the issuance of the promissory notes, we recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The remaining unamortized discount was $0.6 million at December 31, 2012.

## Off-Balance Sheet Arrangements

At December 31, 2012, 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 Results of Operations above and 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.

## 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 use 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). 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 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 Securities Exchange Commission



(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, 2012 were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. Our estimated proved reserves for the years ended December 31, 2011 and 2010 were prepared by Forrest A. Garb & Associates, 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, 2012 our DD&A rate was $25.05 per Boe and a five percent positive revision to proved reserves would decrease the DD&A rate by approximately $1.53 per Boe and a five percent negative revision to proved reserves would increase the DD&A rate by approximately $1.69 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, 2012 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



## Table of Contents

would have been reduced by approximately $262 million. This reduction would not have resulted in a full costing 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. A five percent decrease or increase in future development and abandonment costs would decrease or increase the DD&A rate by approximately $0.64 per Boe.

## Asset Retirement Obligations

We have obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our gathering systems, and to restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

## 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, 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.

## Goodwill

We account for goodwill in accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350). Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. Our goodwill relates to the acquisition of GeoResources in 2012.



Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the company is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test.

## 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 bases. 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.

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.



## Comparison of Results of Operations

## Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

We reported a net loss available to common stockholders of $142.3 million, including a non-cash preferred dividend of $88.4 million, for the year ended December 31, 2012 compared to a net loss available to common stockholders of $1.4 million for the comparable period in 2011. The following table summarizes key items of comparison and their related change for the periods indicated.

<table><tr><td rowspan="2">In thousands (except per unit and per Boe amounts)</td><td colspan="3">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>Change</td></tr><tr><td>Net income (loss) available to common stockholders</td><td></td><td></td><td></td></tr><tr><td></td><td>$ (142,330)</td><td>$ (1,403)</td><td>$ (140,927)</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>223,048</td><td>82,968</td><td>140,080</td></tr><tr><td>Natural gas</td><td></td><td></td><td></td></tr><tr><td></td><td>12,458</td><td>10,673</td><td>1,785</td></tr><tr><td>Natural gas liquids</td><td></td><td></td><td></td></tr><tr><td></td><td>11,088</td><td>9,880</td><td>1,208</td></tr><tr><td>Other</td><td></td><td></td><td></td></tr><tr><td></td><td>1,351</td><td>168</td><td>1,183</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>49,941</td><td>30,043</td><td>19,898</td></tr><tr><td>Workover and other</td><td></td><td></td><td></td></tr><tr><td></td><td>4,429</td><td>1,967</td><td>2,462</td></tr><tr><td>Taxes other than income</td><td></td><td></td><td></td></tr><tr><td></td><td>19,253</td><td>7,214</td><td>12,039</td></tr><tr><td>Restructuring</td><td></td><td></td><td></td></tr><tr><td></td><td>2,406</td><td>1,071</td><td>1,335</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>104,608</td><td>17,025</td><td>87,583</td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></td></tr><tr><td></td><td>6,741</td><td>3,584</td><td>3,157</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>86,215</td><td>20,381</td><td>65,834</td></tr><tr><td>Depreciation—Other</td><td></td><td></td><td></td></tr><tr><td></td><td>1,763</td><td>964</td><td>799</td></tr><tr><td>Accretion expense</td><td></td><td></td><td></td></tr><tr><td></td><td>2,306</td><td>1,641</td><td>665</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>(6,126)</td><td>3,479</td><td>(9,605)</td></tr><tr><td>Interest expense and other</td><td></td><td></td><td></td></tr><tr><td></td><td>(31,223)</td><td>(17,879)</td><td>(13,344)</td></tr></table>



<table><tr><td>Income tax benefit (provision)</td><td>13,181</td><td>(6,802)</td><td>19,983</td></tr><tr><td>Production:</td><td></td><td></td><td></td></tr><tr><td>Crude oil—MBbls</td><td>2,415</td><td>884</td><td>1,531</td></tr><tr><td>Natural Gas—Mmcf</td><td>4,554</td><td>2,662</td><td>1,892</td></tr><tr><td>Natural gas liquids—MBbls</td><td>268</td><td>176</td><td>92</td></tr><tr><td>Total MBoe(1)</td><td>3,442</td><td>1,504</td><td>1,938</td></tr><tr><td>Average daily production—Boe(1)</td><td>9,404</td><td>4,121</td><td>5,283</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>$ 92.36</td><td>$ 93.86</td><td>$ (1.50)</td></tr><tr><td>Natural gas price—Mcf</td><td>2.74</td><td>4.01</td><td>(1.27)</td></tr><tr><td>Natural gas liquids price—Bbl</td><td>41.37</td><td>56.14</td><td>(14.77)</td></tr><tr><td>Total per Boe(1)</td><td>71.64</td><td>68.83</td><td>2.81</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>14.51</td><td>19.98</td><td>(5.47)</td></tr><tr><td>Workover and other</td><td>1.29</td><td>1.31</td><td>(0.02)</td></tr><tr><td>Taxes other than income</td><td>5.59</td><td>4.80</td><td>0.79</td></tr><tr><td>Restructuring</td><td>0.70</td><td>0.71</td><td>(0.01)</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td>30.39</td><td>11.32</td><td>19.07</td></tr><tr><td>Share-based compensation</td><td>1.96</td><td>2.38</td><td>(0.42)</td></tr><tr><td>Depletion</td><td>25.05</td><td>13.55</td><td>11.50</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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, 2012, oil, natural gas and natural gas liquids revenues increased $143.1 million from the same period in 2011. The increase was primarily due to an increase in production volumes resulting from the Merger, the East Texas Assets acquisition and the Williston Basin Assets acquisition which collectively accounted for an increase of 1,942 MBoe in production and $145.3 million of incremental revenues. Realized average prices per Boe increased $2.81 per Boe to $71.64 per Boe.

Lease operating expenses increased $19.9 million for the year ended December 31, 2012, primarily due to $16.3 million of costs incurred on our newly acquired assets. The remaining increases are due to surface repair and maintenance costs. Lease operating expenses were $14.51 per Boe in 2012 compared to $19.98 per Boe in 2011. The decrease per Boe is primarily due to a lower rate per Boe on the newly acquired properties.

Workover and other expenses increased $2.5 million for the year ended December 31, 2012 compared to the same period in 2011 primarily due to $2.7 million of expenses incurred on our newly acquired assets.

Taxes other than income increased $12.0 million for the year ended December 31, 2012 as compared to the same period in 2011 primarily due to $9.6 million of production taxes incurred on our newly acquired properties. 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 directly. On a per unit basis, taxes other than income were $5.59 per Boe and $4.80 per Boe, for the years ended 2012 and 2011, respectively.

In March 2012, we announced our intention to close the Plano, Texas office and began the process of relocating key administrative functions to our corporate headquarters in Houston, Texas (the Restructuring). As part of the Restructuring, we offered certain severance and retention benefits to affected employees. We have incurred $2.4 million in Restructuring costs for the year ended December 31, 2012. In October 2011, we announced a company-wide reorganization of our operating and administrative functions. As part of the reorganization, we recognized restructuring expense of $1.1 million, including $0.7 million of one-time severance benefits, $0.2 million of retention payments, and $0.2 million of share-based compensation related to the acceleration of employee restricted stock awards and payment of share appreciation rights. The reorganization was completed in full during the quarter ended December 31, 2011.

General and administrative expense for the year ended December 31, 2012 increased $87.6 million to $104.6 million as compared to the same period in 2011. The increase was primarily due to transaction costs of $41.0 million in the aggregate for the Merger, the East Texas Assets acquisition and the Williston Basin Assets acquisition. We incurred $8.9 million in connection with the Recapitalization, which included $5.4 million for change in control payments and $2.5 million for engagement termination fees. The remaining increase in general and administrative expenses is attributable to increases in payroll and related employee benefit costs of $18.3 million, office related expenses of $5.2 million and professional fees of $9.7 million, in support of the expanding business base and increased corporate activities subsequent to the Recapitalization.

Share-based compensation expense for the year ended December 31, 2012 was $6.7 million, an increase of $3.2 million compared to the same period in 2011. The increase is primarily due to the accelerated vesting of restricted stock awards and stock appreciation rights resulting from the change in control that occurred due to our Recapitalization, which totaled $4.3 million.

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 volume for the evaluated properties. Depletion expense increased $65.8 million to $86.2 million for the year ended December 31, 2012 compared to the same period in 2011 of $20.4 million, primarily due to a higher depletion rate per Boe and increased production. On a per unit basis, depletion expense was $25.05 per Boe for the year ended December 31, 2012 compared to $13.55 per Boe for the year ended December 31, 2011. The increase in depletion and the depletion rate per Boe and production is primarily due to the Merger and acquisitions of the East Texas Assets and the Williston Basin Assets.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $2.3 million for the year ended December 31, 2012, compared to $1.6 million for the year ended December 31, 2011.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. We have also, in the past, entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. 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, 2012, we had a $7.8 million derivative asset, $7.4 million of which was classified as current, and we had a $12.9 million derivative liability of which $10.4 million was classified as current. We recorded a net derivative loss of $6.1 million ($13.2 million net unrealized loss and $7.1 million net realized gain on settled contracts and premium costs) for the year ended December 31, 2012 compared to a net derivative gain of $3.5 million ($4.8 million net unrealized gain and $1.3 million net realized loss on settled contracts and premium costs) in the prior year.

Interest expense increased $13.3 million for the year ended December 31, 2012. This increase was primarily due to the issuance of new long-term debt partially offset by capitalized interest expense on unevaluated properties. We incurred interest expense of $85.4 million in 2012 compared to $17.4 million in the prior year. Due to significant costs incurred during 2012 on unevaluated properties we began capitalizing interest during 2012, resulting in $53.5 million capitalized for the year ended December 31, 2012. No amounts were capitalized in 2011.

We recorded an income tax benefit of $13.2 million on a loss before income taxes of $67.1 million for the year ended December 31, 2012. The benefit reflects nondeductible interest expense on the Convertible Notes issued as part of the Recapitalization of $3.2 million and nondeductible merger related costs of $3.6 million. For the year ended December 31, 2011, we recorded an income tax provision of $6.8 million on income before income taxes of $5.4 million. The income tax provision for 2011 included a $6.0 million decrease to deferred tax assets, including a Section 382 adjustment related to net operating loss limitations and a decrease in the valuation allowance of $1.9 million.



## Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

We reported a net loss available to common stockholders of $1.4 million for the year ended December 31, 2011 compared to net income available to common stockholders of $2.4 million for the comparable period in 2010. The following table summarizes key items of comparison and their related change for the periods indicated.

<table><tr><td rowspan="2">In thousands (except per unit and per Boe amounts)</td><td colspan="3">Years Ended December 31,</td></tr><tr><td>2011</td><td>2010</td><td>Change</td></tr><tr><td>Net income (loss) available to common stockholders</td><td>$ (1,403)</td><td>$ 2,417</td><td>$ (3,820)</td></tr><tr><td>Operating revenues:</td><td></td><td></td><td></td></tr><tr><td>Oil</td><td>82,968</td><td>76,563</td><td>6,405</td></tr><tr><td>Natural gas</td><td>10,673</td><td>20,265</td><td>(9,592)</td></tr><tr><td>Natural gas liquids</td><td>9,880</td><td>14,156</td><td>(4,276)</td></tr><tr><td>Other</td><td>168</td><td>157</td><td>11</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>30,043</td><td>30,148</td><td>(105)</td></tr><tr><td>Workover and other</td><td>1,967</td><td>1,596</td><td>371</td></tr><tr><td>Taxes other than income</td><td>7,214</td><td>8,486</td><td>(1,272)</td></tr><tr><td>Restructuring</td><td>1,071</td><td>—</td><td>1,071</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td>17,025</td><td>14,523</td><td>2,502</td></tr><tr><td>Share-based compensation</td><td>3,584</td><td>3,110</td><td>474</td></tr><tr><td>Depletion, depreciation and accretion:</td><td></td><td></td><td></td></tr><tr><td>Depletion—Full cost</td><td>20,381</td><td>26,166</td><td>(5,785)</td></tr><tr><td>Depreciation—Other</td><td>964</td><td>1,059</td><td>(95)</td></tr><tr><td>Accretion expense</td><td>1,641</td><td>1,527</td><td>114</td></tr><tr><td>Other income (expenses):</td><td></td><td></td><td></td></tr><tr><td>Net gain on derivative contracts</td><td>3,479</td><td>1,193</td><td>2,286</td></tr><tr><td>Interest expense and other</td><td>(17,879)</td><td>(22,307)</td><td>4,428</td></tr><tr><td>Income tax (provision) benefit</td><td></td><td></td><td></td></tr></table>



<table><tr><td>Production:</td><td>(6,802)</td><td>(995)</td><td>(5,807)</td></tr><tr><td>Crude oil—MBbls</td><td>884</td><td>995</td><td>(111)</td></tr><tr><td>Natural Gas—Mmcf</td><td>2,662</td><td>4,816</td><td>(2,154)</td></tr><tr><td>Natural gas liquids—MBbls</td><td>176</td><td>364</td><td>(188)</td></tr><tr><td>Total MBoe(1)</td><td>1,504</td><td>2,161</td><td>(657)</td></tr><tr><td>Average daily production—Boe(1)</td><td>4,121</td><td>5,921</td><td>(1,800)</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>$ 93.86</td><td>$ 76.95</td><td>$ 16.91</td></tr><tr><td>Natural gas price—Mcf</td><td>4.01</td><td>4.21</td><td>(0.20)</td></tr><tr><td>Natural gas liquids price—Bbl</td><td>56.14</td><td>38.89</td><td>17.25</td></tr><tr><td>Total per Boe(1)</td><td>68.83</td><td>51.36</td><td>17.47</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>$ 19.98</td><td>$ 13.95</td><td>$ 6.03</td></tr><tr><td>Workover and other</td><td>1.31</td><td>0.74</td><td>0.57</td></tr><tr><td>Taxes other than income</td><td>4.80</td><td>3.93</td><td>0.87</td></tr><tr><td>Restructuring</td><td>0.71</td><td>—</td><td>0.71</td></tr><tr><td>General and administrative:</td><td></td><td></td><td></td></tr><tr><td>General and administrative</td><td>11.32</td><td>6.72</td><td>4.60</td></tr><tr><td>Share-based compensation</td><td>2.38</td><td>1.44</td><td>0.94</td></tr><tr><td>Depletion</td><td>13.55</td><td>12.11</td><td>1.44</td></tr></table>

(1) Natural gas reserves are converted to oil reserves using a 1:6 equivalent ratio. 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, 2011, oil, natural gas and natural gas liquids revenues decreased $7.5 million, or 7%, to $103.5 million when compared to the prior year. The primary reason for the decrease is due to asset divestitures. Excluding asset sales, oil, natural gas and natural gas liquids sales increased $3.5 million for the year ended December 31, 2011, when compared to the year ended December 31, 2010. This increase was primarily driven by commodity price increases, offset by decreased production. Our average realized price increased $17.47 per Bfo from $51.36 per Bfo in the prior period. Excluding the activities related to the asset divestitures, our production volume decreased 16% as compared to the same period last year primarily due to a shut-in of one well as a result of a major workover in Louisiana and natural production declines.

Lease operating expenses decreased $0.1 million for the year ended December 31, 2011 as compared to the same period in 2010. For the year ended December 31, 2011, lease operating expense was $19.98 per Bfo compared to $139.95 per Bfo for the year ended December 31, 2010, an increase of 43%.

Taxes other than income decreased $1.3 million for the year ended December 31, 2011 as compared to the same period in 2010 primarily due to asset sales. Excluding asset sales, production taxes increased $0.2 million, primarily due to higher commodity prices during the 2011 period. Production taxes vary by state; most are based on realized prices at the wellhead, while Louisiana production tax is based on volume for natural gas and value for oil. As oil revenues or natural gas volumes increase or decrease, production taxes increase or decrease directly. On a per unit basis, production taxes were $4.80 per Bfo and $3.93 per Bfo, for the years ended 2011 and 2010, respectively.

Restructuring expenses for the year ended December 31, 2011 were $1.1 million. In 2011, we announced a company-wide reorganization of our operating and administrative functions. As part of the reorganization, we recognized restructuring expense of $1.1 million, including $0.7 million of one-time severance benefits, $0.2 million of retention payments, and $0.2 million of share-based compensation related to the acceleration of employee restricted stock awards and payment of share appreciation rights. There were no restructuring costs incurred for the year ended December 31, 2010.

General and administrative expense for the year ended December 31, 2011 increased $2.5 million to $17.0 million compared to $14.5 million in the same period 2010. This increase is primarily due to divestiture costs recognized in 2011 on a transaction that was terminated.

Historically, our board of directors has granted restricted stock awards and/or stock appreciation rights (SARs). Each of the restricted stock grants vests in equal increments over the vesting period provided for the particular award, typically from one to four years. The share-based compensation on the restricted stock grants was calculated using the closing price per share on each of the grant dates, and the total share-based compensation on all restricted stock grants will be recognized over their respective vesting periods. Share-based compensation expense attributable to SARs is based on the fair value re-measured at each reporting period and recognized over the four-year vesting period. The fair value calculation resulted in $0.8 million of compensation expense recognized for the year ended December 31, 2011. For the year ended December 31, 2011, we recognized a total of $3.4 million share-based compensation related to restricted stock awards compared to $3.1 million for the year ended December 31, 2010. The increase was due to accelerated vesting for retired employees pursuant to our restructuring, and a higher number of shares outstanding in the 2011 period. During the year ended December 31, 2011, $2.8 million of recognized compensation, related to restricted stock awards, was recorded as share-based compensation expense, $0.1 million was recorded as restructuring costs and $0.5 million was recorded as capitalized internal costs. During the year ended December 31, 2010, all recognized compensation was recorded to share-based compensation expense.



Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs associated with evaluated properties plus future development costs based on the ratio of production volumes for the current period to total remaining reserve volumes for the evaluated properties. Depletion expense decreased $5.8 million for the year ended December 31, 2011 from the same period in 2010 to $20.4 million. On a per unit basis, depletion expense increased $1.44 per Boe to $13.55 per Boe.

Depreciation expense associated with our other operating assets and equipment decreased $0.1 million to $1.0 million for the year ended December 31, 2011.

Accretion expense is a function of changes in the discounted asset retirement obligation liability from period to period. We recorded $1.6 million for the year ended December 31, 2011, compared to $1.5 million for the year ended December 31, 2010.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with 2010, 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 statement of operations. At December 31, 2011, we had a $3.9 million derivative asset, $1.9 million of which was classified as current and we had a $4.7 million derivative liability, $1.9 million of which was classified as current. We recorded a net derivative gain of $3.5 million ($4.8 million net unrealized gain and $1.3 million net loss for cash received on settled contracts) for the year ended December 31, 2011 compared to a net derivative gain of $1.2 million ($6.4 million net unrealized gain and $5.2 million net loss for cash paid on settled contracts) in the prior year.

Interest expense and other was $17.9 million and $22.3 million for the years ended December 31, 2011 and 2010, respectively, a decrease of $4.4 million. Interest expense decreased due to lower interest rates and lower average outstanding borrowings on our credit facilities throughout the 2011 period. As of December 31, 2011 and 2010, our blended interest rate was 6.2% and 8.0%, respectively.

For the year ended December 31, 2011, we recorded an income tax provision of $6.8 million on income before taxes of $5.4 million. The income tax provision for 2011 included a $6.0 million decrease to deferred tax assets, including a Section 382 adjustment related to net operating loss limitations and a decrease in the valuation allowance of $1.9 million. For the year ended December 31, 2010, we recorded an income tax provision of $1.0 million on income before taxes of $3.4 million. The income tax provision for 2010 included a $5.7 million decrease to deferred tax assets under Section 382 related to net operating loss limitations and a decrease in the valuation allowance of $6.6 million for revisions to future taxable income projections.

## 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 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. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change.

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, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender of an affiliate of a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement. Please refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, "Derivatives and Hedging Activities" for additional information.

We have also been exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Historically, we entered into interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At December 31, 2012, we did not have any open positions that converted our variable interest rate debt to fixed interest rates. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.

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, "Derivatives 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, 2012, total long-term debt was $2.0 billion, excluding the current portion, of which approximately 86% bears interest at a weighted average fixed interest rate of 9.1% per year. The remaining 14% of our total debt balance at December 31, 2012 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, 2012, the weighted average interest rate on our variable rate debt was 2.7% per year. If the balance of our variable rate debt at December 31, 2012 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.2 million per quarter.



## ITEM8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

## INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Management's report on internal control over financial reporting 70
Reports of independent registered public accounting firms 71
Consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 75
Consolidated balance sheets at December 31, 2012 and 2011 76
Consolidated statements of stockholders' equity for the years ended December 31, 2012, 2011 and 2010 77
Consolidated statements of cash flows for the years ended December 31, 2012, 2011 and 2010
Notes to the consolidated financial statements 79
Supplemental oil and gas information (unaudited) 132
Selected quarterly financial data (unaudited) 139



## 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's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012 excluded the acquisition of GeoResources, Inc, completed on August 1, 2012. Such exclusion was in accordance with the U.S. Securities and Exchange Commission guidance that an assessment of recently acquired businesses may be omitted in management's report on internal control over financial reporting, provided the acquisition took place within twelve months of management's evaluation. The acquisition of GeoResources, Inc. represented approximately 26% of our consolidated assets at December 31, 2012 and 37% of our consolidated revenues for the year ended December 31, 2012.

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. Based on this evaluation, management concluded that Halcón Resources Corporation's internal control over financial reporting was effective as of December 31, 2012.

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, 2012 which is included herein.

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board
and Chief Executive Officer

/s/ MARK J. MIZE

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

Houston, Texas
February 28, 2013



# 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, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at GeoResources Inc., which was acquired on August 1, 2012 and whose financial statements constitute 26% of total assets and 37% of revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2012. Accordingly, our audit did not include the internal control over financial reporting at GeoResources, Inc. 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, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.



## Table of Contents

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 28, 2013 expressed an unqualified opinion on those financial statements.

## /s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2013



# 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 consolidated balance sheet of Halcón Resources Corporation and subsidiaries (the "Company") as of December 31, 2012, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended. 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 audit. The consolidated financial statements of the Company for the years ended December 31, 2011 and 2010 were audited by other auditors whose report, dated March 5, 2012 and February 28, 2013 as to Note 2, expressed an unqualified opinion on those statements.

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 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 audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2012, and the results of their operations and their cash flows for the year then ended 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, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2013



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Halcón Resources Corporation

We have audited the accompanying consolidated balance sheet of Halcón Resources Corporation (formerly RAM Energy Resources, Inc., a Delaware corporation) and subsidiaries (the "Company") as of December 31, 2011, and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows for the two years in the period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Halcón Resources Corporation and subsidiaries at December 31, 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the accompanying consolidated financial statements have been restated.

## /s/ UHY LLP

Houston, Texas

March 5, 2012 (except for effect of the

restatement discussed in Note 2, as to

which the date is February 28, 2013)



## HALCÓN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)

<table><tr><td rowspan="2"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></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>$ 223,048</td><td>$ 82,968</td><td>$ 76,563</td><td></td></tr><tr><td>Natural gas</td><td>12,458</td><td>10,673</td><td>20,265</td><td></td></tr><tr><td>Natural gas liquids</td><td>11,088</td><td>9,880</td><td>14,156</td><td></td></tr><tr><td>Total oil, natural gas and natural gas liquids sales</td><td>246,594</td><td>103,521</td><td>110,984</td><td></td></tr><tr><td>Other</td><td>1,351</td><td>168</td><td>157</td><td></td></tr><tr><td>Total operating revenues</td><td>247,945</td><td>103,689</td><td>111,141</td><td></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>49,941</td><td>30,043</td><td>30,148</td><td></td></tr><tr><td>Workover and other</td><td>4,429</td><td>1,967</td><td>1,596</td><td></td></tr><tr><td>Taxes other than income</td><td>19,253</td><td>7,214</td><td>8,486</td><td></td></tr><tr><td>Restructuring</td><td>2,406</td><td>1,071</td><td>—</td><td></td></tr><tr><td>General and administrative</td><td>111,349</td><td>20,609</td><td>17,633</td><td></td></tr><tr><td>Depletion, depreciation and accretion</td><td>90,284</td><td>22,986</td><td>28,752</td><td></td></tr><tr><td>Total operating expenses</td><td>277,662</td><td>83,890</td><td>86,615</td><td></td></tr><tr><td>Income (loss) from operations</td><td>(29,717)</td><td>19,799</td><td>24,526</td><td></td></tr><tr><td>Other income (expenses):</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense and other</td><td>(31,223)</td><td>(17,879)</td><td>(22,307)</td><td></td></tr><tr><td>Net gain (loss) on derivative contracts</td><td>(6,126)</td><td>3,479</td><td>1,193</td><td></td></tr><tr><td>Total other income (expenses)</td><td>(37,349)</td><td>(14,400)</td><td>(21,114)</td><td></td></tr></table>



<table><tr><td>Income (loss) before income taxes</td><td>(67,066)</td><td>5,399</td><td>3,412</td></tr><tr><td>Income tax benefit (provision)</td><td>13,181</td><td>(6,802)</td><td>(995)</td></tr><tr><td>Net income (loss)</td><td>(53,885)</td><td>(1,403)</td><td>2,417</td></tr><tr><td>Non-cash preferred dividend</td><td>(88,445)</td><td>—</td><td>—</td></tr><tr><td>Net income (loss) available to common stockholders</td><td>$ (142,330)</td><td>$ (1,403)</td><td>$ 2,417</td></tr><tr><td>Net income (loss) per share of common stock:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ (0.91)</td><td>$ (0.05)</td><td>$ 0.09</td></tr><tr><td>Diluted</td><td>$ (0.91)</td><td>$ (0.05)</td><td>$0.09</td></tr><tr><td>Weighted average common shares outstanding:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>156,494</td><td>26,258</td><td>26,142</td></tr><tr><td>Diluted</td><td>156,494</td><td>26,258</td><td>26,142</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 rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011(1)</td></tr><tr><td>Current assets:</td><td></td><td></td></tr><tr><td>Cash</td><td></td><td></td></tr><tr><td></td><td>$ 2,506</td><td>$ 49</td></tr><tr><td>Accounts receivable</td><td></td><td></td></tr><tr><td></td><td>262,809</td><td>10,288</td></tr><tr><td>Receivables from derivative contracts</td><td></td><td></td></tr><tr><td></td><td>7,428</td><td>1,850</td></tr><tr><td>Current portion of deferred income taxes</td><td></td><td></td></tr><tr><td></td><td>5,307</td><td>1,080</td></tr><tr><td>Inventory</td><td></td><td></td></tr><tr><td></td><td>3,116</td><td>4,310</td></tr><tr><td>Prepaids and other</td><td></td><td></td></tr><tr><td></td><td>6,691</td><td>2,729</td></tr><tr><td>Total current assets</td><td></td><td></td></tr><tr><td></td><td>287,857</td><td>20,306</td></tr><tr><td>Oil and natural gas properties (full cost method):</td><td></td><td></td></tr><tr><td>Evaluated</td><td></td><td></td></tr><tr><td></td><td>2,669,245</td><td>715,666</td></tr><tr><td>Unevaluated</td><td></td><td></td></tr><tr><td></td><td>2,326,598</td><td>—</td></tr><tr><td>Gross oil and natural gas properties</td><td></td><td></td></tr><tr><td></td><td>4,995,843</td><td>715,666</td></tr><tr><td>Less—accumulated depletion</td><td></td><td></td></tr><tr><td></td><td>(588,207)</td><td>(501,993)</td></tr><tr><td>Net oil and natural gas properties</td><td></td><td></td></tr><tr><td></td><td>4,407,636</td><td>213,673</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></td><td></td></tr><tr><td></td><td>59,748</td><td>9,979</td></tr><tr><td>Less—accumulated depreciation</td><td></td><td></td></tr><tr><td></td><td>(8,119)</td><td>(7,133)</td></tr><tr><td>Net other operating property and equipment</td><td></td><td></td></tr><tr><td></td><td>51,629</td><td>2,846</td></tr><tr><td>Other noncurrent assets:</td><td></td><td></td></tr><tr><td>Goodwill</td><td></td><td></td></tr><tr><td></td><td>227,762</td><td>—</td></tr><tr><td>Receivables from derivative contracts</td><td></td><td></td></tr><tr><td></td><td>371</td><td>2,050</td></tr><tr><td>Debt issuance costs, net of amortization</td><td></td><td></td></tr><tr><td></td><td>51,609</td><td>5,966</td></tr><tr><td>Deferred income taxes</td><td></td><td></td></tr><tr><td></td><td>—</td><td>21,355</td></tr></table>



<table><tr><td></td><td>11,137</td><td></td></tr><tr><td>Funds in escrow</td><td></td><td></td></tr><tr><td></td><td>2,090</td><td>560</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>934</td><td>418</td></tr><tr><td>Total assets</td><td>$5,041,025</td><td>$ 267,174</td></tr><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>$ 590,551</td><td>$ 25,061</td></tr><tr><td>Liabilities from derivative contracts</td><td></td><td></td></tr><tr><td></td><td>10,429</td><td>1,855</td></tr><tr><td>Asset retirement obligations</td><td></td><td></td></tr><tr><td></td><td>2,319</td><td>1,010</td></tr><tr><td>Promissory notes</td><td></td><td></td></tr><tr><td></td><td>74,669</td><td>—</td></tr><tr><td>Total current liabilities</td><td></td><td></td></tr><tr><td></td><td>677,968</td><td>27,926</td></tr><tr><td>Long-term debt</td><td></td><td></td></tr><tr><td></td><td>2,034,498</td><td>202,000</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>2,461</td><td>2,855</td></tr><tr><td>Asset retirement obligations</td><td></td><td></td></tr><tr><td></td><td>72,813</td><td>32,703</td></tr><tr><td>Deferred income taxes</td><td></td><td></td></tr><tr><td></td><td>160,055</td><td>—</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>10</td><td>10</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>Preferred stock: 1,000,000 shares of $0.0001 par value authorized; 10,880 and no shares issued and outstanding as of December 31, 2012 and 2011, respectively</td><td></td><td></td></tr><tr><td></td><td>695,238</td><td>—</td></tr><tr><td>Stockholders&#x27; equity:</td><td></td><td></td></tr><tr><td>Common stock: 336,666,666 and 33,333,333 shares of $0.0001 par value authorized; 259,802,377 and 27,694,583 shares issued; 258,152,468 and 26,244,452 outstanding at December 31, 2012 and 2011, respectively</td><td></td><td></td></tr><tr><td></td><td>26</td><td>3</td></tr><tr><td>Additional paid-in capital</td><td></td><td></td></tr><tr><td></td><td>1,681,717</td><td>229,414</td></tr><tr><td>Treasury stock: 1,649,909 and 1,450,131 shares at December 31, 2012 and 2011, respectively, at cost</td><td></td><td></td></tr><tr><td></td><td>(9,298)</td><td>(7,159)</td></tr><tr><td>Accumulated deficit</td><td></td><td></td></tr><tr><td></td><td>(274,463)</td><td>(220,578)</td></tr><tr><td>Total stockholders&#x27; equity</td><td></td><td></td></tr><tr><td></td><td>1,397,982</td><td>1,680</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td></td><td></td></tr><tr><td></td><td>$5,041,025</td><td>$ 267,174</td></tr></table>

(1) See further discussion at Note 2, "Corrections of Immaterial Errors."






## HALCÓN RESOURCES CORPORATION

## CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

## (In thousands)

<table><tr><td></td><td colspan="2">Preferred Stock</td><td colspan="2">Common Stock</td><td rowspan="2">Additional Paid-In Capital</td><td colspan="2">Treasury Stock</td><td rowspan="2">Accumulated Deficit(1)</td><td rowspan="2">Stockholders&#x27; Equity (Deficit)(1)</td></tr><tr><td></td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Balances at January 1, 2010</td><td>—</td><td>$</td><td>—</td><td>26,916</td><td>$</td><td>3</td><td>$</td><td>(6,189)</td><td>$</td></tr><tr><td>Long-term incentive plan grants</td><td>—</td><td>—</td><td>624</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Long-term incentive plan forfeitures</td><td>—</td><td>—</td><td>(7)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,417</td><td>2,417</td></tr><tr><td>Repurchase of stock</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>138</td><td>(787)</td><td>—</td><td>(787)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,063</td><td>—</td><td>—</td><td>—</td><td>3,063</td></tr><tr><td>Balances at December 31, 2010</td><td>—</td><td>—</td><td>27,533</td><td>3</td><td>226,047</td><td>1,404</td><td>(6,976)</td><td>(219,175)</td><td>(101)</td></tr><tr><td>Long-term incentive plan grants</td><td>—</td><td>—</td><td>280</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Long-term incentive plan forfeitures</td><td>—</td><td>—</td><td>(118)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net loss</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1,403)</td><td>(1,403)</td></tr><tr><td>Repurchase of stock</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>46</td><td>(183)</td><td>—</td><td>(183)</td></tr><tr><td>Share-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,367</td><td>—</td><td>—</td><td>—</td><td>3,367</td></tr><tr><td>Balances at December 31, 2011</td><td>—</td><td>—</td><td>27,695</td><td>3</td><td>229,414</td><td>1,450</td><td>(7,159)</td><td>(220,578)</td><td>1,680</td></tr><tr><td>Warrants issued</td><td>—</td><td>—</td><td>—</td><td>—</td><td>43,590</td><td>—</td><td>—</td><td>—</td><td>43,590</td></tr><tr><td>Sale of common stock</td><td>—</td><td>—</td><td>115,232</td><td>11</td><td>568,989</td><td>—</td><td>—</td><td>—</td><td>569,000</td></tr><tr><td>Reverse-stock-split rounding</td><td>—</td><td>—</td><td>4</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Sale of preferred stock</td><td>4</td><td>311,556</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>311,556</td></tr><tr><td>Preferred stock conversion</td><td>(4)</td><td>(385,476)</td><td>44,445</td><td>5</td><td>385,471</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Offering costs</td><td>—</td><td>(14,525)</td><td>—</td><td>—</td><td>(5,078)</td><td>—</td><td>—</td><td>—</td><td>(19,603)</td></tr><tr><td>Common stock issuance</td><td>—</td><td>—</td><td>72,114</td><td>7</td><td>452,032</td><td>—</td><td>—</td><td>—</td><td>452,039</td></tr><tr><td>Net loss</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(53,885)</td><td>(53,885)</td></tr></table>

Preferred beneficial conversion feature



<table><tr><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>88,445</td><td>—</td><td>—</td><td>—</td><td>—</td><td>88,445</td></tr><tr><td>Non-cash preferred dividend</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>88,445</td><td>—</td><td>—</td><td>(88,445)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Long-term incentive plan grants</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>312</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Repurchase of stock</td><td></td><td></td><td></td><td></td><td></td><td></td><td>200</td><td>(2,139)</td><td>—</td><td>(2,139)</td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></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>7,299</td><td>—</td><td>—</td><td>—</td><td>7,299</td></tr><tr><td>Balances at December 31, 2012</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>$</td><td>—</td><td>259,802</td><td>$</td><td>26</td><td>$</td><td>1,681,717</td><td>1,650</td><td>$</td></tr></table>

(1) See further discussion at Note 2, "Corrections of Immaterial Errors."

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 colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></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></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (53,885)</td><td>$ (1,403)</td><td>$ 2,417</td><td></td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depletion, depreciation and accretion</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>90,284</td><td>22,986</td><td>28,752</td><td></td></tr><tr><td>Deferred income tax provision (benefit)</td><td>(13,060)</td><td>6,549</td><td>577</td><td></td></tr><tr><td>Share-based compensation</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>4,573</td><td>3,584</td><td>3,110</td><td></td></tr><tr><td>Unrealized loss (gain) on derivative contracts</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>11,727</td><td>(2,954)</td><td>(1,498)</td><td></td></tr><tr><td>Amortization and write-off of deferred loan costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>6,212</td><td>3,663</td><td>2,088</td><td></td></tr><tr><td>Non-cash interest and amortization of discount</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>9,387</td><td>362</td><td>3,086</td><td></td></tr><tr><td>Other expense (income)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(352)</td><td>223</td><td>(612)</td><td></td></tr><tr><td>Change in assets and liabilities, net of acquisitions:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(93,120)</td><td>295</td><td>3,704</td><td></td></tr><tr><td>Inventory</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>1,194</td><td>(927)</td><td>518</td><td></td></tr><tr><td>Derivative premium</td><td></td><td>—</td><td>4,889</td><td>(4,468)</td></tr><tr><td>Prepaids and other</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(749)</td><td>403</td><td>1,141</td><td></td></tr><tr><td>Accounts payable and accrued liabilities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>155,963</td><td>(7,835)</td><td>(940)</td><td></td></tr><tr><td>Net cash provided by (used in) operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>118,174</td><td>29,835</td><td>37,875</td><td></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></td><td></td><td></td><td></td></tr><tr><td></td><td>(1,216,835)</td><td>(25,214)</td><td>(33,535)</td><td></td></tr><tr><td>Acquisition of GeoResources, Inc., net of cash acquired</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(579,497)</td><td>—</td><td>—</td><td></td></tr><tr><td>Acquisition of East Texas Assets</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(296,139)</td><td>—</td><td>—</td><td></td></tr><tr><td>Acquisition of Williston Basin Assets</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(756,056)</td><td>—</td><td>—</td><td></td></tr><tr><td>Other operating property and equipment capital expenditures</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(38,752)</td><td>(672)</td><td>(865)</td><td></td></tr><tr><td>Proceeds received from sales of property and equipment</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>564</td><td>48</td><td>4</td><td></td></tr></table>



<table><tr><td>Proceeds received from sale of oil and gas assets</td><td>21,964</td><td>462</td><td>49,366</td></tr><tr><td>Funds held in escrow</td><td>(1,529)</td><td>—</td><td>—</td></tr><tr><td>Net cash provided by (used in) investing activities</td><td>(2,866,280)</td><td>(25,376)</td><td>14,970</td></tr><tr><td>Cash flows from financing activities:</td><td></td><td></td><td></td></tr><tr><td>Proceeds from borrowings</td><td>2,466,608</td><td>250,167</td><td>46,340</td></tr><tr><td>Repayments of borrowings</td><td>(655,000)</td><td>(245,621)</td><td>(98,490)</td></tr><tr><td>Debt issuance costs</td><td>(52,878)</td><td>(7,825)</td><td>—</td></tr><tr><td>Offering costs</td><td>(18,619)</td><td>(985)</td><td>—</td></tr><tr><td>Common stock repurchased</td><td>(2,139)</td><td>(183)</td><td>(787)</td></tr><tr><td>Preferred stock issued</td><td>311,556</td><td>—</td><td>—</td></tr><tr><td>Preferred beneficial conversion feature</td><td>88,445</td><td>—</td><td>—</td></tr><tr><td>Common stock issued</td><td>569,000</td><td>—</td><td>—</td></tr><tr><td>Warrants issued</td><td>43,590</td><td>—</td><td>—</td></tr><tr><td>Net cash provided by (used in) financing activities</td><td>2,750,563</td><td>(4,447)</td><td>(52,937)</td></tr><tr><td>Net increase (decrease) in cash</td><td>2,457</td><td>12</td><td>(92)</td></tr><tr><td>Cash at beginning of period</td><td>49</td><td>37</td><td>129</td></tr><tr><td>Cash at end of period</td><td>$ 2,506</td><td>$ 49</td><td>$ 37</td></tr><tr><td>Supplemental cash flow information:</td><td></td><td></td><td></td></tr><tr><td>Cash paid for interest, net of capitalized interest</td><td>$ 11,705</td><td>$ 554</td><td>$ 380</td></tr><tr><td>Cash paid for income taxes</td><td>89</td><td>15,326</td><td>17,988</td></tr><tr><td>Disclosure of non-cash investing and financing activities:</td><td></td><td></td><td></td></tr><tr><td>Asset retirement obligations</td><td>$ 8,587</td><td>$ 956</td><td>$ 3,006</td></tr><tr><td>Preferred dividend</td><td>88,445</td><td>—</td><td>—</td></tr><tr><td>Payment-in-kind interest</td><td>14,669</td><td>—</td><td>—</td></tr><tr><td>Common stock issued for GeoResources, Inc.</td><td>321,416</td><td>—</td><td>—</td></tr><tr><td>Common stock issued for East Texas Assets</td><td>130,623</td><td>—</td><td>—</td></tr><tr><td>Preferred stock issued for Williston Basin Assets</td><td>695,238</td><td>—</td><td>—</td></tr><tr><td>Current notes payable issued for oil and natural gas properties</td><td>74,669</td><td>—</td><td>—</td></tr></table>






# 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 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.

On February 10, 2012, the Company completed a three-for-one reverse stock split. As a result, all share and per share information included for all periods presented in these consolidated financial statements reflect the reverse stock split.

## Consolidated Financial Statements

The consolidated financial statements include the accounts of Halcón and its majority-owned subsidiaries. The equity method of accounting is used to account for its investments in affiliates in which the Company does not have a majority ownership or control, but has the ability to exert significant influence. The Company's investments in oil and gas limited partnerships for which it serves as general partner and exerts significant influence are accounted for under the equity method of accounting. All intercompany accounts and transactions have been eliminated.

## 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 assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, oil and natural gas reserves, capital accruals, amortization relating to oil and natural gas properties, asset retirement obligations, fair value estimates, beneficial conversion feature estimates 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



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. There are no significant allowances for doubtful accounts as of December 31, 2012 or 2011.

## 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 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 proved 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.

## 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 estimated useful life. 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. The Company capitalized $39.9 million for the year ended December 31, 2012 and no amounts for the year ended December 31, 2011 related to the construction of the Company's gas gathering systems.

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, leasehold improvements, fixtures, furniture and equipment, five years or the lesser of lease term; trailers, seven years; heavy equipment, ten years; and buildings, twenty years. 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.

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



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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.

## 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 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 gas balancing asset or liability. At December 31, 2012 and 2011 the Company's gas 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. In 2012, two individual purchasers of the Company's production, Shell Trading US Co. (STUSCO) and Sunoco Partners Marketing & Terminals, L.P. (Sunoco), each accounted for approximately 20% and 19%, respectively, of its total sales.

In 2011, STUSCO accounted for $70.4 million, or 68%, of the Company's oil and natural gas revenue for the year. No other purchaser accounted for 10% or more of its oil and natural gas revenue during 2011. In 2011, the Company was subject to a crude purchase contract with STUSCO covering all of its production in its Electra Field in Wichita and Wilbarger Counties, Texas. The contract term covered the period of January 1, 2011 through December 31, 2011. The Company was also subject to a crude purchase contract with STUSCO during 2011 covering all of its oil production in its Fitts and Allen Fields in Oklahoma. Effective December 1, 2011, the Company cancelled the crude purchase contract with STUSCO and entered into a new crude oil purchase agreement with Sunoco for a term of December 1, 2011 through May 31, 2012.

In 2010, STUSCO, accounted for $68.1 million, or 61%, of the Company's oil and natural gas revenue for the year. No other purchaser accounted for 10% or more of its oil and natural gas revenue during 2010. The Company's agreement with STUSCO covered all of the Company's North Texas oil production. The Company was also subject to a crude purchase contract with STUSCO covering all of its oil production in the Fitts and Allen Fields in Oklahoma.



# 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, the Company 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 bases. 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 for the years ended December 31, 2012, 2011 or 2010. 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 results of operations or statement of financial position as of December 31, 2012. 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.

The Company includes interest and penalties relating to uncertain tax positions within "Interest expense and other" on the Company's consolidated statements of operations. Refer to Note 13, "Income Taxes", for more details.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Generally, the Company's tax years 2009 through 2012 are either currently under audit or remain open and subject to examination by federal tax authorities or the tax authorities in Louisiana, New Mexico, North Dakota, Oklahoma, Texas, Ohio and Pennsylvania which are the jurisdictions in which the Company has had its 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 technically 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 discusses 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.

## Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. ASC 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. However, the Company has only one reporting unit. The Company's goodwill relates to its acquisition of GeoResources. Refer to Note 5, "Acquisitions and Divestitures" for more details regarding the Merger between the Company and GeoResources.

The Company will perform its goodwill test annually as of July 1, beginning in 2013 or more often if circumstances require. Accounting Standards Update (ASU) No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08), simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the company is required to perform the first step of the two-step impairment test. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. The first step in the two-step impairment test is to determine the fair value of the Company's reporting unit and compare it to the carrying value of the related net assets. Fair value is determined based on the Company's estimates for market values. If this fair value exceeds the carrying value no further analysis or goodwill write down is required. The second step is required if the fair value of the Company's reporting unit is less than the carrying value of the net assets. In this step the implied fair value of the Company's reporting unit is allocated to all the underlying assets and liabilities, including both recognized and unrecognized tangible and intangible assets, based on their fair values. If necessary, goodwill is then written down to its implied fair value. If the fair value of the Company's reporting unit is less than the book value (including goodwill), then goodwill is reduced to its implied fair value and the amount of the write down is charged against earnings. The assumptions used by the Company in calculating its reporting unit fair values at the time of the test include the Company's market capitalization and discounted future cash flows based on estimated reserves and production, future development and operating costs and future oil and natural gas prices. Material adverse changes to any of these factors could lead to an impairment of all or a portion of the Company's goodwill in future periods.

## 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 $1.8 million, $0.7 million, and $0.7 million in 2012, 2011, and 2010, respectively. As of January 1, 2013, the Company matches employee contributions dollar-for-dollar on the first 10% of an employee's pre-tax earnings, subject to individual IRS limitations.

## Recently Issued Accounting Pronouncements

In May 2011, FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in the U.S. Generally Accepted Accounting Principles (GAAP) and International Financial Accounting Reporting Standards (IFRS) (ASU 2011-04). This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011. The adoption of ASU 2011-04 on January 1, 2012 did not have a material impact on the Company's financial position, results of operations or disclosures.

In July 2011, the FASB issued ASU No. 2011-06, Fees Paid to the Federal Government by Health Insurers (ASU 2011-06). This amendment discusses how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (the Acts). The Acts impose an annual fee upon health insurers for each calendar year on or after January 1, 2014. The annual fee imposed on the health insurance industry will be allocated to



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

individual entities providing health insurance to employees based on a ratio, as provided for in the Acts. The health insurer's portion of the fee becomes payable to the United States Treasury once an entity provides health insurance for any United States health risk for each calendar year. ASU 2011-06 specifies that the liability for the entity's fee should be estimated and recorded in full once the entity has provided qualifying health insurance in the calendar year in which the fee is payable to the government. A corresponding deferred cost should be recorded and amortized on a straight line basis (unless a better amortization method is available) over the calendar year that the fee is payable. The amendments in this update are effective for calendar years beginning after December 15, 2013, once the fee is instituted. The Company is currently assessing the impact that the adoption of ASU 2011-06 will have on its operating results, financial position, cash flows and disclosures.

In September 2011, the FASB issued ASU No. 2011-08, Testing for Goodwill Impairment (ASU 2011-08) to simplify how companies test goodwill for impairment. ASU 2011-08 simplifies testing for goodwill impairments by allowing entities to first assess qualitative factors to determine whether the facts or circumstances lead to the conclusion that it is more likely than not that the fair value of a reporting unit is less than the carrying value. If the entity concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then the entity does not have to perform the two-step impairment test. However, if the same conclusion is not reached, the Company is required to perform the first step of the two-step impairment test. In this step, the fair value of the reporting unit is calculated and compared to the carrying value of the reporting unit. If the carrying value exceeds the fair value, then the entity must perform the second step of the impairment test to measure the amount of impairment loss, if any. ASU 2011-08 also allows a company to bypass the qualitative assessment and proceed directly with performing the two-step goodwill impairment test. ASU 2011-08 is effective for annual and interim goodwill impairment tests for fiscal years beginning after December 15, 2011 and early adoption is permitted. The adoption of ASU 2011-08 did not have a significant impact on the Company's financial position or results of operations.

In December 2011, the FASB issued ASU No. 2011-11, Disclosures About Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 enhances disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This pronouncement was issued to facilitate comparison between financial statements prepared on the basis of GAAP and IFRS. This update is effective for annual and interim reporting periods beginning on or after January 1, 2013 and is to be applied retroactively for all comparative periods presented. The adoption of ASU 2011-11 is not expected to have a significant impact on the Company's disclosures.

## 2. CORRECTIONS OF IMMATERIAL ERRORS

The consolidated balance sheet as of December 31, 2011 has been restated to reflect the correction of tax basis adjustments to "Oil and natural gas properties" and "Deferred income taxes" for periods prior to January 1, 2007, and as such, the consolidated statement of stockholders' equity at January 1, 2010 was adjusted by $4.3 million. The Company completed a review of its tax basis in oil and natural gas properties and its deferred tax assets related to oil and natural gas properties and gain on asset dispositions and determined that the adjustments in the table below were needed to correct its December 31, 2011 balance sheet related to prior periods.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 2. CORRECTIONS OF IMMATERIAL ERRORS (Continued)

The Company noted the following changes to its consolidated balance sheet as of December 31, 2011:

<table><tr><td>Balance Sheet Location</td><td>As Reported</td><td>Adjustment (In thousands)</td><td>As Restated</td></tr><tr><td>Net current deferred income tax assets</td><td>$ 2,601</td><td>$ (1,521)</td><td>$ 1,080</td></tr><tr><td>Other noncurrent assets—Deferred income taxes</td><td>24,102</td><td>(2,747)</td><td>21,355</td></tr><tr><td>Total assets</td><td>271,442</td><td>(4,268)</td><td>267,174</td></tr><tr><td>Accumulated deficit</td><td>(216,310)</td><td>(4,268)</td><td>(220,578)</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td>271,442</td><td>(4,268)</td><td>267,174</td></tr></table>

The Company noted the following changes to its consolidated statements of stockholders' equity through December 31, 2011:

<table><tr><td>Adjustments to Statement of Stockholders&#x27; Equity</td><td>As Reported</td><td>Adjustment (In thousands)</td><td>As Restated</td></tr><tr><td>Accumulated Deficit—Balance at January 1, 2010</td><td>$ (217,324)</td><td>$ (4,268)</td><td>$ (221,592)</td></tr><tr><td>Stockholders&#x27; Equity—Balance at January 1, 2010</td><td>(526)</td><td>(4,268)</td><td>(4,794)</td></tr><tr><td>Accumulated Deficit—Balance at December 31, 2010</td><td>(214,907)</td><td>(4,268)</td><td>(219,175)</td></tr><tr><td>Stockholders&#x27; Equity—Balance at December 31, 2010</td><td>4,167</td><td>(4,268)</td><td>(101)</td></tr><tr><td>Accumulated Deficit—Balance at December 31, 2011</td><td>(216,310)</td><td>(4,268)</td><td>(220,578)</td></tr><tr><td>Stockholders&#x27; Equity—Balance at December 31, 2011</td><td>5,948</td><td>(4,268)</td><td>1,680</td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 2. CORRECTIONS OF IMMATERIAL ERRORS (Continued)

The Company noted the following changes to its deferred income tax presentation in Note 13, "Income Taxes" as of December 31, 2011:

<table><tr><td></td><td>As Reported</td><td>Adjustment (In thousands)</td><td>As Restated</td></tr><tr><td>Deferred current income tax assets:</td><td></td><td></td><td></td></tr><tr><td>Unrealized hedging transactions</td><td>$     796</td><td>$ (2,465)</td><td>$ (1,669)</td></tr><tr><td>Other</td><td>2,372</td><td>699</td><td>3,071</td></tr><tr><td>Gross deferred current income tax assets</td><td>3,168</td><td>(1,766)</td><td>1,402</td></tr><tr><td>Valuation allowance</td><td>(245)</td><td>245</td><td>—</td></tr><tr><td>Deferred current income tax assets</td><td>$     2,923</td><td>$ (1,521)</td><td>$ 1,402</td></tr><tr><td>Deferred current income tax liabilities:</td><td></td><td></td><td></td></tr><tr><td>Other</td><td>$ (322)</td><td>$ —</td><td>$ (322)</td></tr><tr><td>Deferred current income tax liabilities</td><td>$ (322)</td><td>$ —</td><td>$ (322)</td></tr><tr><td>Net current deferred income tax assets</td><td>$ 2,601</td><td>$ (1,521)</td><td>$ 1,080</td></tr><tr><td>Deferred noncurrent income tax assets:</td><td></td><td></td><td></td></tr><tr><td>Net operating loss carry-forwards</td><td>$ 16,901</td><td>$ 8,149</td><td>$ 25,050</td></tr><tr><td>Depreciable/depletable property, plant and equipment</td><td>8,041</td><td>(8,945)</td><td>(904)</td></tr><tr><td>Other</td><td>1,382</td><td>(1,706)</td><td>(324)</td></tr><tr><td>Gross deferred noncurrent income tax assets</td><td>26,324</td><td>(2,502)</td><td>23,822</td></tr><tr><td>Valuation allowance</td><td>(2,040)</td><td>(245)</td><td>(2,285)</td></tr><tr><td>Deferred noncurrent income tax assets</td><td>$ 24,284</td><td>$ (2,747)</td><td>$ 21,537</td></tr><tr><td>Deferred noncurrent income tax liabilities:</td><td></td><td></td><td></td></tr><tr><td>Other</td><td>$ (182)</td><td>$ —</td><td>$ (182)</td></tr><tr><td>Deferred noncurrent income tax liabilities</td><td>$ (182)</td><td>$ —</td><td>$ (182)</td></tr><tr><td>Net noncurrent deferred income tax assets</td><td>$ 24,102</td><td>$ (2,747)</td><td>$ 21,355</td></tr></table>



## 3. RECAPITALIZATION

On December 21, 2011, the Company entered into a Securities Purchase Agreement (the Purchase Agreement) with HALRES LLC, formerly Halcón Resources, LLC (HALRES). Pursuant to the Purchase Agreement, (i) HALRES purchased and the Company sold 73.3 million shares of the Company's common stock (the Shares) for a purchase price of $275 million and (ii) HALRES purchased and the Company issued a senior convertible promissory note in the principal amount of $275 million (the 2017 Note), together with five year warrants (the February 2012 Warrants) to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share (the Recapitalization), subject to adjustment under certain circumstances. The 2017 Note is convertible after February 8, 2014 into 61.1 million shares of common stock at a conversion price of $4.50 per share, subject to adjustment under certain circumstances. The Company and HALRES closed the transaction contemplated by the Purchase Agreement on February 8, 2012.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. RECAPITALIZATION (Continued)

In January 2012, shareholders holding a majority of the Company's outstanding shares of common stock approved the issuance of the Shares, the 2017 Note and the February 2012 Warrants pursuant to the terms of the Purchase Agreement. Additionally, the board of directors approved, effective upon the closing (i) the amendment of the Company's certificate of incorporation to (a) increase the Company's authorized shares of common stock from 100 million shares to 1.01 billion shares, both of which were before the one-for-three reverse stock split; (b) a one-for-three reverse stock split of the Company's common stock (which reduced the Company's authorized shares of common stock from 1.01 billion to 336.7 million shares); and (c) a name change from RAM Energy Resources, Inc. to Halcón Resources Corporation; (ii) the amendment of the Company's 2006 Long-Term Incentive Plan (the Plan) to increase the number of shares that may be issued under the Plan from 2.5 million to 3.7 million shares; and (iii) on an advisory (non-binding) basis, the payments made to the Company's named executive officers in connection with the transactions contemplated by the Purchase Agreement.

The closing of the transaction resulted in a change in control of the Company. Material events and items resulting from the transaction include the following:

• completion of transactions contemplated by the Purchase Agreement and shareholder approval as discussed above;

• the resignation and termination of the Company's four executive officers and the resignation of certain other officers;

• change in control payments of $4.6 million to the officers of the Company recorded in general and administrative expense;

• change in control payment of $0.8 million pursuant to a retainer agreement with the Company's then outside law firm recorded in general and administrative expense;

• accelerated vesting of all unvested employee restricted stock shares and accelerated vesting and exercise of all unvested stock appreciation rights resulting in $4.3 million of share-based compensation expense recorded in general and administrative expense;

• payoff and termination of the Company's March 2011 Credit Facilities of $133.0 million plus accrued interest, as well as the expensing of the related unamortized debt issuance costs of $2.9 million;

• payoff and termination of the Company's second lien term facility of $75.0 million plus accrued interest and a prepayment fee of $1.5 million, as well as the expensing of the related unamortized debt issuance costs of $2.9 million; and

• closing costs of $11.2 million related to engagement fees and various professional fees including $2.5 million recorded in general and administrative expense related to a termination fee pursuant to a previous engagement.

In January 2012, the Company approved a one-for-three reverse stock split, which was implemented on February 10, 2012. Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these financial statements reflects the reverse stock split.

In February 2012, the transaction with HALRES resulted in an "ownership change" as defined under Section 382 of the Internal Revenue Code of 1986, as amended. As a consequence, the Company



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 3. RECAPITALIZATION (Continued)

has additional limitations on its ability to use the net operating losses it accrued before the ownership change as a deduction against any taxable income the Company realizes after the ownership change.

## 4. RESTRUCTURING

In March 2012, the Company announced its intention to close its Plano, Texas office and begin the process of relocating key administrative functions to Houston, Texas (the Restructuring). As part of the Restructuring, the Company offered certain severance and retention benefits, collectively known as, the Severance Program, to the affected employees. The estimated total expense of the Severance Program is approximately $3.2 million and related costs will be recognized as restructuring expense over the requisite service periods through May 2013, as applicable. Below is a reconciliation of the beginning and ending liability balance.

<table><tr><td></td><td>Severance Program (In thousands)</td></tr><tr><td>Beginning balance, December 31, 2011</td><td>$ —</td></tr><tr><td>Severance and Retention payments</td><td></td></tr><tr><td>Increase in accrual</td><td>(275)</td></tr><tr><td>Ending balance, December 31, 2012</td><td>$ 2,406</td></tr></table>

## 5. ACQUISITIONS AND DIVESTITURES

## Acquisitions

## Williston Basin Assets

On December 6, 2012, the Company completed the acquisition of two wholly-owned subsidiaries of Petro-Hunt Holdings, LLC and Pillar Holdings, LLC (the Petro-Hunt Parties), which owned acreage prospective for the Bakken / Three Forks formations primarily located in North Dakota, in Williams, Montrall, McKenzie and Dunn counties (the Williston Basin Assets). The Company completed the acquisition of the Williston Basin Assets, thereby acquiring Halcón Williston I, LLC and Halcón Williston II, LLC (the Williston Subs) for a total consideration of approximately $1.5 billion, consisting of approximately $756.1 million in cash and approximately 10,880 shares of the Company's preferred stock that automatically converted into 108.8 million shares of Halcón common stock on January 18, 2013 (equivalent to a conversion price of approximately $7.45 per share of Halcón common stock based on the liquidation preference), following stockholder approval of such conversion and an amendment to Halcón's certificate of incorporation to increase the number of shares of common stock that Halcón is authorized to issue (the Williston Basin Acquisition). No proceeds were received by the Company upon conversion of the preferred stock. No cash dividends were paid on the convertible preferred stock as it converted into common stock before April 6, 2013. The shares of preferred stock were issued to the Petro-Hunt Parties in a private placement pursuant to the exemptions from registration under Section 4(2) of the Securities Act of 1933, as amended. The Williston Basin Acquisition significantly expanded the Company's presence in North Dakota, adding undeveloped acreage, oil and natural gas reserves and production to its existing asset base and operations in this area.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

Immediately following the completion of the Williston Basin Acquisition (and the related private placement of Halcón common stock described in Note 12, "Preferred Stock and Stockholders' Equity"), the Petro-Hunt Parties held preferred stock representing approximately 22% of Halcón's outstanding common stock on an as-converted, fully diluted basis. In addition, Halcón agreed to cause one individual designated by the Petro-Hunt Parties to be elected or appointed to Halcón's board of directors, subject to the reasonable approval of Halcón's Nominating and Corporate Governance Committee, for so long as the Petro-Hunt Parties beneficially own at least 5% of the outstanding shares of Halcón common stock. On December 6, 2012, in connection with the closing of the Williston Basin Transaction and pursuant to the terms of the Reorganization and Interest Purchase Agreement, David S. Hunt was appointed to Halcón's board of directors as a Class B director with a term expiring in 2015.

The transaction had an effective date of June 1, 2012 and was subject to customary closing conditions, including the expiration or early termination of the waiting period mandated under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as well as the execution and delivery of certain other agreements, including a registration rights agreement, a lock-up agreement and a transition services agreement. Under the terms of the registration rights agreement, Halcón has agreed to file with the SEC on or before July 4, 2013, a shelf registration statement covering resales of the 108.8 million shares of Halcón common stock issued as partial consideration in the Williston Basin Acquisition and use commercially reasonable efforts to cause the registration statement to be declared effective as soon as reasonably practicable after the registration statement is filed. The lock-up agreement prohibits the Petro-Hunt Parties from offering for sale, selling, pledging or otherwise disposing of the shares of Halcón common stock received as consideration for the transaction for a period of 180 days following the closing of the transaction.

The Williston Basin Acquisition was accounted for as a business combination in accordance with Accounting Standards Codification (ASC) No. 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The estimated fair value of the properties approximates the fair value of consideration and as a result no goodwill was recognized.

The purchase price allocation presented below is preliminary with respect to accruals and working capital adjustments, and includes the use of estimates based on information that was available to management at the time these audited consolidated financial statements were prepared. The Company believes the estimates used are reasonable and the significant effects of the Williston Basin Acquisition are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. The following table summarizes the consideration paid to



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

acquire the Williston Basin Assets, as well as the amounts of assets acquired and liabilities assumed as of the acquisition date (in thousands, except stock prices):

<table><tr><td>Purchase Price(1):</td><td></td></tr><tr><td>Halcón preferred shares issued to Williston Basin Assets Sellers(2)</td><td>$ 695,238</td></tr><tr><td>Cash consideration paid to Williston Basin Assets Sellers(3)</td><td>756,056</td></tr><tr><td>Total purchase price</td><td>$ 1,451,294</td></tr><tr><td>Estimated Fair Value of Liabilities Assumed:</td><td></td></tr><tr><td>Current liabilities(4)</td><td>$ 72,850</td></tr><tr><td>Asset retirement obligations</td><td>5,207</td></tr><tr><td>Amount attributable to liabilities assumed</td><td>78,057</td></tr><tr><td>Total purchase price plus liabilities assumed</td><td>$ 1,529,351</td></tr><tr><td>Estimated Fair Value of Assets Acquired:</td><td></td></tr><tr><td>Current assets(4)</td><td>$ 27,139</td></tr><tr><td>Evaluated oil and natural gas properties(5)(6)</td><td>635,216</td></tr><tr><td>Unevaluated oil and natural gas properties</td><td>866,996</td></tr><tr><td>Amount attributable to assets acquired</td><td>$ 1,529,351</td></tr><tr><td>Goodwill</td><td>—</td></tr></table>

(1) Based on the terms of the reorganization and interest purchase agreement, consideration paid by Halcón at closing consisted of $756.1 million in cash plus approximately 10,880 shares of convertible preferred stock. The total purchase price is based upon the fair value of the preferred shares which was determined using the lowest price of $6.39 per share of the Company's common stock on December 6, 2012, the number of convertible preferred shares issued and the conversion rate of each convertible preferred share to 10,000 shares of common stock.

(2) Represents the fair value of convertible preferred stock par value $0.0001 per share issued to sellers with each preferred share convertible into 10,000 shares of common stock. The preferred shares are presented on the balance sheet as mezzanine equity due to the fact that the conversion of the preferred shares to common shares was still contingent upon shareholder approval at the December 31, 2012 balance sheet date. See further discussion of the preferred shares at Note 12, "Preferred Stock and Stockholders' Equity".

(3) Represents amount of cash consideration for the purchase of the Williston Basin Assets funded by the issuance of the $750 million 8.875% senior notes with net proceeds of $725.6 million and borrowings under the Senior Credit Agreement revolver. See discussion of 8.875% note and Senior Credit Agreement at Note 7, "Long-term Debt".

(4) In accordance with the purchase agreement, the effective date of the acquisition was June 1, 2012 and therefore revenues, expenses and related capital expenditures from June 1, 2012 through the closing of the Williston Basin Acquisition have been reflected as part of the purchase accounting and subsequent to closing of the transaction have resulted in working capital adjustments. As a result, the Company recorded a net liability of $45.7 million in post-closing adjustments reducing the working capital at December 31, 2012.






# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

(5) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount for future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs. For additional information on Level 3 inputs, see Note 8, "Fair Value Measurements".

(6) Weighted average commodity prices utilized in the determination of the pro forma fair value of oil and natural gas properties were $95.17 per barrel of oil and $10.85 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The pricing used in the determination of fair value reflects the differential applied to future prices; differentials for natural gas reflect relatively higher British thermal unit (Btu) gas content.

## GeoResources, Inc.

On August 1, 2012, the Company completed an acquisition of GeoResources, Inc. (GeoResources) by means of the merger of GeoResources into a wholly-owned subsidiary of the Company (the Merger). In connection with the Merger, each share of GeoResources common stock issued and outstanding immediately prior to the effective date of the Merger was converted into the right to receive $20.00 in cash and 1.932 shares of the Company's common stock. All outstanding options to purchase GeoResources common stock were exercised immediately prior to the effective date of the Merger on a net cashless basis. All outstanding GeoResources restricted stock units vested and were settled in shares of GeoResources common stock immediately prior to the effective date of the Merger. All outstanding warrants to purchase GeoResources common stock were assumed by the Company and converted into warrants (the August 2012 Warrants) to acquire equivalent Merger consideration.

In connection with the consummation of the Merger, the Company issued a total of approximately 51.3 million shares of its common stock and paid approximately $531.5 million in cash to former GeoResources stockholders in exchange for their shares of GeoResources common stock. The acquisition expanded the Company's presence in the Bakken / Three Forks formations of North Dakota and Montana, and the Austin Chalk trend and Eagle Ford Shale in Texas, adding oil and natural gas reserves and production to its existing asset base in these areas.

The acquisition was accounted for as a business combination in accordance with ASC 805 which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. GeoResources results of operations are reflected in the Company's consolidated statements of operations, beginning August 1, 2012.

A preliminary allocation of the purchase price as of August 1, 2012 was prepared in connection with the Company's quarterly financial statements filed on Form 10-Q for the period ended September 30, 2012. In January 2013, the Company received the final year-end reserve report prepared by Netherland, Sewell & Associates, Inc. (Netherland, Sewell) which was compared to the preliminary reserve estimates that were used to prepare the initial purchase price allocation. With the new reserve information, the Company updated the oil and natural gas property amounts acquired, as well as certain other estimates used in the initial purchase price allocation related to asset retirement obligations, deferred tax amounts and other accruals based on more current information. The following allocation is still preliminary with respect to final tax amounts, pending completion of the 2012 GeoResources' tax return and certain accruals and includes the use of estimates based on information



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

that was available to management at the time these audited consolidated financial statements were prepared. The Company believes the estimates used are reasonable and the significant effects of the Merger are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. Additional changes to the purchase price allocation may result in a corresponding change to the goodwill in the period of change. The following table summarizes the consideration paid to acquire GeoResources and the estimated values of assets



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

acquired and liabilities assumed in the accompanying audited consolidated balance sheets based on their fair values on August 1, 2012 (in thousands, except stock price):

<table><tr><td></td><td>August 1, 2012 (As initially reported)</td><td>Measurement Period Adjustments(1)</td><td>August 1, 2012 (As Adjusted)</td></tr><tr><td>Purchase price(2):</td><td></td><td></td><td></td></tr><tr><td>Shares of Halcón common stock issued to GeoResources&#x27; stockholders</td><td>50,378</td><td>—</td><td>50,378</td></tr><tr><td>Shares of Halcón common stock issued to GeoResources&#x27; stock option holders</td><td>966</td><td>—</td><td>966</td></tr><tr><td>Total Halcón common stock issued</td><td>51,344</td><td>—</td><td>51,344</td></tr><tr><td>Halcón common stock price</td><td>$ 6.26</td><td>—</td><td>$ 6.26</td></tr><tr><td>Fair value of common stock issued</td><td>$ 321,416</td><td>—</td><td>$ 321,416</td></tr><tr><td>Cash consideration paid to GeoResources&#x27; stockholders(3)</td><td>521,526</td><td>—</td><td>521,526</td></tr><tr><td>Cash consideration paid to GeoResources&#x27; stock option holders(3)</td><td>9,996</td><td>—</td><td>9,996</td></tr><tr><td>Fair value of warrants assumed by Halcón(4)</td><td>1,474</td><td>—</td><td>1,474</td></tr><tr><td>Total purchase price</td><td>$ 854,412</td><td>—</td><td>$ 854,412</td></tr><tr><td>Estimated fair value of liabilities assumed:</td><td></td><td></td><td></td></tr><tr><td>Current liabilities</td><td>$ 112,641</td><td>$ (417)</td><td>$ 112,224</td></tr><tr><td>Deferred tax liability(5)</td><td>238,882</td><td>(48,638)</td><td>190,244</td></tr><tr><td>Asset retirement obligations</td><td>9,320</td><td>18,744</td><td>28,064</td></tr><tr><td>Other non-current liabilities</td><td>80,024</td><td>—</td><td>80,024</td></tr><tr><td>Amount attributable to liabilities assumed</td><td>$ 440,867</td><td>$ (30,311)</td><td>$ 410,556</td></tr><tr><td>Total purchase price plus liabilities assumed</td><td>$ 1,295,279</td><td>$ (30,311)</td><td>$ 1,264,968</td></tr><tr><td>Estimated fair value of assets acquired:</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 122,528</td><td>$ (11,677)</td><td>$ 110,851</td></tr><tr><td>Evaluated oil and natural gas properties(6)(7)</td><td>542,820</td><td>(84,256)</td><td>458,564</td></tr><tr><td>Unevaluated oil and natural gas properties</td><td></td><td></td><td></td></tr></table>



<table><tr><td></td><td>455,000</td><td>(1,000)</td><td>454,000</td></tr><tr><td>Net other operating property and equipment</td><td></td><td></td><td></td></tr><tr><td></td><td>1,179</td><td>—</td><td>1,179</td></tr><tr><td>Equity in oil and gas partnerships(8)</td><td></td><td></td><td></td></tr><tr><td></td><td>11,189</td><td>(222)</td><td>10,967</td></tr><tr><td>Other non-current assets</td><td></td><td></td><td></td></tr><tr><td></td><td>1,645</td><td>—</td><td>1,645</td></tr><tr><td>Amount attributable to assets acquired</td><td></td><td></td><td></td></tr><tr><td></td><td>$ 1,134,361</td><td>$ (97,155)</td><td>$ 1,037,206</td></tr><tr><td>Goodwill(9)</td><td></td><td></td><td></td></tr><tr><td></td><td>$ 160,918</td><td>$ 66,844</td><td>$ 227,762</td></tr></table>

(1) After the September 30, 2012 condensed consolidated financial statements were issued, the Company updated certain estimates used in the purchase price allocation, primarily with respect to oil and natural gas property amounts, asset retirement obligations, deferred tax amounts and other accruals due to more current information. The adjustments are based on updated assumptions and information related to facts and circumstances that existed as of the acquisition date for oil and



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

natural gas properties and estimated retirement obligations, as well as confirmatory information related to accruals. Adjustments related to the revised amounts are also reflected in the depletion and accretion expense for the period based on the updated fair values.

(2) Under the terms of the Merger Agreement, consideration paid by Halcón consisted of $20.00 in cash plus 1.932 shares of Halcón common stock for each share of GeoResources common stock. The total purchase price was based upon the price of Halcón common stock on the closing date of the transaction, August 1, 2012, and approximately 26.6 million shares of GeoResources common stock outstanding at the effective time of the Merger. The Company issued a total of 51.3 million shares of its common stock and paid $531.5 million in cash to former GeoResources stockholders in exchange for their shares of GeoResources common stock.

(3) Components of cash flow for the Merger (in thousands):

<table><tr><td>Total cash consideration for Merger and stock options(i)</td><td>$ 531,522</td></tr><tr><td>Retirement of GeoResources&#x27; long-term debt(ii)</td><td>80,328</td></tr><tr><td>Cash acquired on date of Merger</td><td>(32,353)</td></tr><tr><td>Total cash outflows, net</td><td>$ 579,497</td></tr></table>

(i) The majority of the cash consideration was funded by the net proceeds from the issuance of the 9.75% senior notes.

(ii) Includes accrued interest and fees.

(4) The $1.5 million fair value of the assumed warrants was calculated using a Black-Scholes valuation model with assumptions for the following variables: price of Halcón stock on the closing date of the merger; risk-free interest rates; and expected volatility. The assumed warrants have been classified as liabilities as the warrant holders can receive cash. The assumed warrants are classified as current liabilities as all the warrants will expire within twelve months from December 31, 2012.

(5) Halcón received carryover tax basis in GeoResources' assets and liabilities because the Merger was not a taxable transaction under the United States Internal Revenue Code of 1986, as amended. Based upon the purchase price allocation, a step-up in financial reporting carrying value related to the property acquired from GeoResources resulted in a Halcón deferred tax liability of approximately $190.2 million, an increase of approximately $128.8 million to GeoResources' existing $61.4 million deferred tax liability.

(6) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties was $6.65 per Mcf of natural gas, $35.66 per barrel of oil equivalent for natural gas liquids and $98.37 per barrel of oil, after adjustment for transportation fees and regional price differentials.

(7) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount for future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs. For additional information on Level 3 inputs, see Note 8, "Fair Value Measurements".



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

(8) As a part of the Merger, the Company acquired investments, in the form of general partnership interests, in two affiliated partnerships, SBE Partners LP (SBE Partners) and OKLA Energy Partners LP (OKLA Energy). These partnerships hold direct working interests in oil and natural gas properties. The Company's investment in an unconsolidated entity in which the Company does not have a majority interest or control, but does have significant influence, is accounted for under the equity method. The Company holds a 2% general partner interest, in OKLA Energy, which reverts to 35.66% interest when the limited partner realizes a contractually specified rate of return. The Company holds a 30% general partner interest in SBE Partners. Under the equity method of accounting the Company records its net share of income and expenses in "Interest expense and other" on the consolidated statements of operations. Contributions to the investment increase the Company's investment while distributions from the investment decrease the Company's carrying value of the investment in "Equity in oil and gas partnerships" on the consolidated balance sheets. The Company reviews its equity method investment for potential impairment whenever events or changes in circumstances indicate that an other-than-temporary decline in the value of the investment has occurred.

(9) Goodwill was determined as the excess consideration transferred over the fair value of the GeoResources net assets acquired on August 1, 2012. Goodwill recognized will not be deductible for tax purposes.

## East Texas Assets

Between August 1, 2012 and August 3, 2012, the Company completed the acquisition of oil and gas leaseholds in East Texas (the East Texas Assets) from CH4 Energy II, LLC, PetroMax Leon, LLC, Petro Texas LLC, King King LLC and several other selling parties for total consideration of $426.8 million comprised of $296.1 million in cash and 20.8 million shares of the Company's common stock (East Texas Acquisition). The East Texas Acquisition expanded the Company's presence in East Texas, adding oil and natural gas reserves and production to its existing asset base in this area. On August 27, 2012 the Company filed a registration statement with the SEC that registered under the Securities Act the resale of the shares of common stock issued as consideration in the East Texas Acquisition.

The East Texas Acquisition was accounted for as a business combination in accordance with ASC 805 which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The effective date of the East Texas Acquisition was April 1, 2012. The estimated fair value of the properties approximates the fair value of consideration and as a result no goodwill was recognized.

A preliminary allocation of the purchase price as of August 3, 2012 was prepared in connection with the Company's quarterly financial statements filed on Form 10-Q for the period ended September 30, 2012. In January 2013, the Company received the final year-end reserve report prepared by Netherland, Sewell which was compared to the preliminary reserve estimates that were used to prepare the initial purchase price allocation. With the new reserve information, the Company updated the oil and natural gas property amounts acquired, as well as certain other estimates used in the initial purchase price allocation related to accruals. The following allocation is still preliminary with respect to accruals and includes the use of estimates. This preliminary allocation is based on information that was available to management at the time these audited consolidated financial statements were prepared.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

The Company believes the estimates used are reasonable and the significant effects of the East Texas Acquisition are properly reflected. However, the estimates are subject to change as additional information becomes available and is assessed by the Company. The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of the acquisition date (in thousands, except stock prices):

<table><tr><td></td><td>August 1 - 3, 2012 (As initially reported)</td><td>Measurement Period Adjustments(1)</td><td>August 1 - 3, 2012 (As Adjusted)</td></tr><tr><td>Purchase price(2):</td><td></td><td></td><td></td></tr><tr><td>Shares of Halcón common stock issued on August 1, 2012</td><td>16,460</td><td>—</td><td>16,460</td></tr><tr><td>Shares of Halcón common stock issued on August 2, 2012</td><td>4,310</td><td>—</td><td>4,310</td></tr><tr><td>Total Halcón common stock issued</td><td>20,770</td><td>—</td><td>20,770</td></tr><tr><td>Halcón common stock price on August 1, 2012</td><td>$ 6.26</td><td>$ —</td><td>$ 6.26</td></tr><tr><td>Halcón common stock price on August 2, 2012</td><td>$ 6.40</td><td>$ —</td><td>$ 6.40</td></tr><tr><td>Fair value of Halcón common stock issued</td><td>$ 130,623</td><td>$ —</td><td>$ 130,623</td></tr><tr><td>Cash consideration paid to sellers of East Texas Assets(3)</td><td>301,569</td><td>(5,430)</td><td>296,139</td></tr><tr><td>Total purchase price(3)</td><td>$ 432,192</td><td>$ (5,430)</td><td>$ 426,762</td></tr><tr><td>Estimated fair value of liabilities assumed:</td><td></td><td></td><td></td></tr><tr><td>Current liabilities</td><td>$ —</td><td>$ 192</td><td>$ 192</td></tr><tr><td>Asset retirement obligations</td><td>337</td><td>—</td><td>337</td></tr><tr><td>Amount attributable to liabilities assumed</td><td>$ 337</td><td>$ 192</td><td>$ 529</td></tr><tr><td>Total purchase price plus liabilities assumed</td><td>$ 432,529</td><td>$ (5,238)</td><td>$ 427,291</td></tr><tr><td>Estimated fair value of assets acquired:</td><td></td><td></td><td></td></tr><tr><td>Evaluated oil and natural gas properties(4)(5)</td><td>$ 334,080</td><td>$ 3,223</td><td>$ 337,303</td></tr><tr><td>Unevaluated oil and natural gas properties</td><td>98,449</td><td>(8,461)</td><td>89,988</td></tr><tr><td>Amount attributable to assets acquired</td><td>$ 432,529</td><td>$ (5,238)</td><td>$ 427,291</td></tr><tr><td>Goodwill</td><td>$ —</td><td>$ —</td><td>$ —</td></tr></table>

(1) After the September 30, 2012 consolidated financial statements were issued, the Company updated certain estimates used in the purchase price allocation, primarily with respect to oil and natural gas property amounts and other accruals. The adjustments are based on updated



assumptions related to facts and circumstances that existed as of the acquisition date for oil and natural gas properties, as well as confirmatory information for customary post-close adjustments. Adjustments related to the revised amounts are also reflected in the depletion expense for the period based on the updated fair values.

(2) Based on the terms of the purchase and sale agreements relating to the East Texas Assets, consideration paid by Halcón at closing consisted of $301.6 million in cash plus 20.8 million shares of Halcón common stock. The total purchase price is based upon the price on August 1, 2012 of $6.26 per share of Halcón's common stock for CH4 Energy II, LLC, Petromax Leon, LLC and Petro Texas, LLC (Initial Sellers) and price on August 2, 2012 of $6.40 per share of Halcón's



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

common stock for King King LLC. The East Texas Acquisition was partially financed with the net proceeds from the issuance of $750.0 million of 9.75% senior unsecured notes and cash on hand. See Note 7 "Long-Term Debt" for discussion of the accounting treatment of the 9.75% senior notes.

(3) In accordance with the purchase agreement, the effective date of the acquisition was April 1, 2012 and therefore revenues, expenses and related capital expenditures from April 1, 2012 through the closing of the East Texas Acquisition have been reflected as part of the purchase accounting and subsequent to closing of the transaction have resulted in a reduction of the purchase price. As a result, the Company recorded $5.4 million in post-closing adjustments reducing the total purchase price and cash consideration paid to $426.8 million and $296.1 million, respectively at December 31, 2012.

(4) The market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount for future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates used by the Company to estimate the fair value of the oil and natural gas properties represent Level 3 inputs. For additional information on Level 3 inputs, see Note 8 "Fair Value Measurements".

(5) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $6.26 per Mcf of natural gas, $49.68 per Boe for natural gas liquids and $98.35 per barrel of oil, after adjustment for transportation fees and regional price differentials.

The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2012 and 2011 as though the Merger, East Texas Acquisition and the Williston Basin Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2011. The pro forma combined results of operations for the years ended December 31, 2012 and 2011 have been prepared by adjusting the historical results of the Company to include the historical results of GeoResources, the East Texas Assets and the Williston Basin Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Merger, the East Texas Acquisition and the Williston Basin Acquisition or any estimated costs that will be incurred to integrate GeoResources, the Williston Basin Assets and the



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

East Texas Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors.

<table><tr><td rowspan="2"></td><td colspan="3">Years ended December 31,</td></tr><tr><td>2012 (Unaudited) (in thousands, except per share amounts)</td><td>2011 (Unaudited)</td><td></td></tr><tr><td>Revenue</td><td>$ 607,715</td><td>$ 329,606</td><td></td></tr><tr><td>Net income</td><td>34,896</td><td>14,355</td><td></td></tr><tr><td>Loss available to Halcón common stockholders</td><td>(125,828)</td><td>(52,333)</td><td></td></tr><tr><td>Pro forma net loss per common share:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ (0.63)</td><td>$ (0.53)</td><td></td></tr><tr><td>Diluted</td><td>$ (0.63)</td><td>$ (0.53)</td><td></td><td rowspan="2"></td></tr><tr><td></td><td></td><td></td><td></td></tr></table>

The Company's historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Merger and the acquisitions of the East Texas Assets and the Williston Basin Assets and factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of assets acquired and liabilities assumed in the Merger and the acquisitions of the East Texas Assets and the Williston Basin Assets with the following adjustments:

• Adjustment to recognize incremental depletion expense under the full cost method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties at acquisition;

• Eliminate historical interest expense for GeoResources debt that was extinguished;

• Adjustment to recognize interest expense, net of capitalized interest, and preferred dividends for debt and preferred shares issued in connection with the transactions;

• Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for GeoResources and the Company in the amount of $59.5 million. Transaction costs directly related to the transactions that do not have a continuing impact on the combined Company's operating results have been excluded from the 2012 and 2011 pro forma earnings;

• Adjustment to recognize pro forma income tax based on an assumed 38% rate;

• Eliminate historical impairment expense for GeoResources that would not have been incurred under the full cost method of accounting;

• Adjustment to convert successful efforts method financial statements of GeoResources to full cost method financial statements to adjust exploration expenses which would have been capitalized under the full cost method of accounting for oil and natural gas activities;

• Adjustment to GeoResources' historical revenue to reclass net settlements on commodity derivatives that under cash flow hedge accounting were included in GeoResources' revenues from oil and natural gas sales, and adjustment to reflect unrealized gain on commodity derivatives. In accordance with the Company's accounting policy, it does not apply cash flow hedge accounting treatment and the realized and unrealized gain (loss) on commodity derivatives have been reflected as a gain (loss) on derivative contracts;



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

• Adjustment to recognize the issuance of 51.3 million shares of Halcón common stock as consideration for the GeoResources Merger; and

• Adjustment to recognize the issuance of the 20.8 million shares of Halcón common stock as consideration for the acquisition of the East Texas Assets.

For the year ended December 31, 2012, the Company recognized $19.7 million of oil, natural gas and natural gas liquids sales related to properties acquired in the acquisition of the Williston Basin Assets and $6.7 million of net field operating income (oil, natural gas and natural gas liquids revenues less lease operating expense, workover expense, production taxes, depletion expense and income taxes) related to properties acquired in the acquisition of the Williston Basin Assets. Additionally, non-recurring transaction costs of $14.2 million related to the acquisition of the Williston Basin Assets for the year ended December 31, 2012 are included in the consolidated statements of operations in "General and administrative" expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented in the above table.

For the year ended December 31, 2012, the Company recognized $90.8 million of oil, natural gas and natural gas liquids sales and $25.7 million of net field operating income (oil, natural gas and natural gas liquids revenues less lease operating expenses, workover expense, production taxes, depletion expense and income taxes) related to properties acquired in the Merger. Additionally, non-recurring transaction costs of $21.5 million related to the Merger for the year ended December 31, 2012 are included in the consolidated statements of operations in "General and administrative" expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented in the above table.

For the year ended December 31, 2012, the Company recognized $34.8 million of oil, natural gas and natural gas liquids revenues related to properties acquired in the acquisition of the East Texas Assets and $16.5 million of net field operating income (oil, natural gas and natural gas liquids revenues less lease operating expense, workover expense, production taxes, depletion expense and income taxes) related to properties acquired in the acquisition of the East Texas Assets. Additionally, non-recurring transaction costs of $1.1 million related to the acquisition of the East Texas Assets for the year ended December 31, 2012 are included in the consolidated statements of operations in "General and administrative" expenses; these non-recurring transaction costs have been excluded from the pro forma results for all periods presented in the above table.

## Other Acquisitions

On December 28, 2012, the Company completed the acquisition of certain oil and natural gas properties, located in Brazos County, Texas, from a group of private sellers for approximately $83.7 million, before customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. The promissory notes have a maturity date of August 30, 2013. The transaction had an effective date of December 1, 2012. Refer to Note 7, "Long-term debt," for more details regarding the promissory notes.

On September 12, 2012, the Company completed the acquisition of certain oil and natural gas properties, located in Leon County, Texas from a group of private sellers for approximately $14.0 million, before customary closing adjustments. The transaction had an effective date of September 1, 2012. The acquisition was funded with cash on hand.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 5. ACQUISITIONS AND DIVESTITURES (Continued)

## Acquisition of Unevaluated Acreage

On June 28, 2012, the Company acquired a working interest in acreage in Eastern Ohio that it believes is prospective for the Utica / Point Pleasant formations. The purchase price in the transaction was approximately $164.0 million. The acquisition was funded with cash on hand.

## Divestitures

## Louisiana Properties

On November 29, 2012, the Company completed the sale of certain oil and natural gas properties located in Eloi Bay/Half Moon Lakes Field, Chandeleur Sound Block 71 Field and Quarantine Bay Field to Cox Oil, LLC for $22.0 million in cash, after customary closing adjustments. Proceeds from the sale were recorded as a reduction to the carrying value of the Company's full cost pool with no gain or loss recorded. The transaction had an effective date of August 1, 2012.

## Electra/Burkburnett Field

During 2011, the Company entered into an agreement in principle to sell a majority interest in the Company's Electra / Burkburnett Field to Argent Energy Trust, a recently formed Canadian energy trust. Argent filed a preliminary prospectus with Canadian regulatory authorities for an initial public offering of its trust units in Canada (Argent IPO). The sale of the Company's Electra / Burkburnett Field was contingent upon several conditions, including completion of the Argent IPO. The Argent IPO was not completed and the agreement between the Company and Argent terminated during December 2011. The Company incurred approximately $2.4 million in related fees. Due to the termination of the agreement these fees are reflected in general and administrative expense in 2011.

## North Texas Barnett Shale & Boonsville

On December 8, 2010, the Company closed the sale on all of its oil and natural gas properties and related assets in the Boonsville and Newark East fields of Jack and Wise Counties in Texas to Milagro Producing, LLC for $43.7 million, before customary closing adjustments. The effective date under the agreement was October 1, 2010. In accordance with the full cost method of accounting, the Company did not record a gain or loss on the sale. The full cost pool at December 31, 2010 was reduced by the net proceeds, including closing adjustments, of $41.0 million. Proceeds of $16.0 million were used to reduce the outstanding balance on the Company's revolving credit facility and the remaining net proceeds were used to reduce the outstanding balance on the Company's term loan.

## Eastern Oklahoma

On December 30, 2010, the Company completed the sale of certain non-operated natural gas properties located in eastern Oklahoma for $8.0 million, before customary closing adjustments. The effective date under the agreement was December 1, 2010. The full cost pool at December 31, 2010 was reduced by the net proceeds, including closing adjustments, of $7.8 million in accordance with the full cost method of accounting. The proceeds were used to reduce outstanding borrowings under the Company's revolving credit facility.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 6. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties as of December 31, 2012 and 2011 consisted of the following:

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td colspan="2">(In thousands)</td></tr><tr><td>Subject to depletion</td><td></td><td></td></tr><tr><td></td><td>$ 2,669,245</td><td>$ 715,666</td></tr><tr><td>Not subject to depletion:</td><td></td><td></td></tr><tr><td>Exploration and extension wells in progress</td><td></td><td></td></tr><tr><td></td><td>67,992</td><td>—</td></tr><tr><td>Other capital costs:</td><td></td><td></td></tr><tr><td>Incurred in 2012</td><td></td><td></td></tr><tr><td></td><td>2,258,606</td><td>—</td></tr><tr><td>Incurred in 2011</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Incurred in 2010</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Incurrent in 2009 and prior</td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td></tr><tr><td>Total not subject to depletion</td><td></td><td></td></tr><tr><td></td><td>2,326,598</td><td>—</td></tr><tr><td>Gross oil and natural gas properties</td><td></td><td></td></tr><tr><td></td><td>4,995,843</td><td>715,666</td></tr><tr><td>Less accumulated depletion</td><td></td><td></td></tr><tr><td></td><td>(588,207)</td><td>(501,993)</td></tr><tr><td>Net oil and natural gas properties</td><td></td><td></td></tr><tr><td></td><td>$ 4,407,636</td><td>$ 213,673</td></tr></table>

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.

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 an 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 amortization and the full cost ceiling test limitation.

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 capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that are 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 are recorded as additions to unevaluated oil and natural gas properties on the consolidated balance sheet. As the costs excluded are transferred to the full cost



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

pool, the associated capitalized interest is also transferred to the full cost pool. For the year ended December 31, 2012, the Company capitalized interest costs of $53.5 million. In 2011 and 2010, the Company did not capitalize any interest costs.

The Company has capitalized internal costs of approximately $14.6 million, $4.3 million and $3.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Such capitalized costs include salaries and related benefits of individuals directly involved in the Company's acquisition, exploration and development activities based on the percentage of their time devoted to such activities.

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)(2)</td><td>Henry Hub (per MMBtu)(3)</td></tr><tr><td>December 31, 2012</td><td>$ 94.71</td><td>$ 2.76</td></tr><tr><td>December 31, 2011</td><td>96.19</td><td>4.12</td></tr><tr><td>December 31, 2010</td><td>79.43</td><td>4.38</td></tr></table>

(1) First day average of the 12-months ended December 31, 2012 spot price, adjusted by lease or field for quality, transportation fees and regional price differentials.

(2) First day average of the 12-months ended December 31, 2011 and 2010 posted price, adjusted by lease or field for quality, transportation fees and regional price differentials.

(3) First day average of the 12-months ended price, adjusted by lease or field for quality, transportation fees and regional price differentials.

At December 31, 2012, 2011 and 2010, the Company's net book value of oil and natural gas properties did not exceed the respective ceiling amounts. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Company's actual ceiling test calculation and impairment analyses in future periods.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT

Long-term debt as of December 31, 2012 and 2011 consisted of the following:

<table><tr><td rowspan="3"></td><td colspan="3">December 31,</td></tr><tr><td>2012(1)</td><td>2011</td><td></td></tr><tr><td colspan="3">(In thousands)</td></tr><tr><td>Senior revolving credit facility</td><td></td><td></td><td></td></tr><tr><td></td><td>$ 298,000</td><td>$ —</td><td></td></tr><tr><td>8.875% $750 million senior notes(2)</td><td></td><td></td><td></td></tr><tr><td></td><td>744,421</td><td>—</td><td></td></tr><tr><td>9.75% $750 million senior notes(3)</td><td></td><td></td><td></td></tr><tr><td></td><td>740,232</td><td>—</td><td></td></tr><tr><td>8.0% $275 million senior note(4)</td><td></td><td></td><td></td></tr><tr><td></td><td>251,845</td><td>—</td><td></td></tr><tr><td>Revolving credit facility</td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>127,000</td><td></td></tr><tr><td>Term loan facility</td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>75,000</td><td></td></tr><tr><td></td><td>$ 2,034,498</td><td>$ 202,000</td><td></td></tr></table>

(1) Amount excludes $74.7 million of promissory notes which have been classified as current at December 31, 2012.

(2) Amount is net of a $5.6 million unamortized discount at December 31, 2012. See "8.875% Note" below for more details.

(3) Amount is net of a $9.8 million unamortized discount at December 31, 2012. See "9.75% Notes" below for more details.

(4) Amount is net of a $37.8 million unamortized discount at December 31, 2012. See "8.0% Notes" below for more details.

## Senior Revolving Credit Facility

In connection with the closing of the Recapitalization, discussed in Note 3, "Recapitalization", the Company entered into a senior secured revolving credit agreement (the Senior Credit Agreement) with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders on February 8, 2012. Initially, the Senior Credit Agreement provided for a $500.0 million facility with an initial borrowing base of $225.0 million. Amounts borrowed under the Senior Credit Agreement will mature on February 8, 2017. The borrowing base will be redetermined semi-annually, 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 Company's oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Senior Credit Agreement may be paid down and re-borrowed during the five-year term of the revolver. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 0.50% to 1.50% for ABR-based loans or at specified margins over LIBOR of 1.50% to 2.50% for Eurodollar-based loans. These margins fluctuate based on the Company's utilization of the facility. Advances under the Senior Credit Agreement are secured by liens on substantially all of the Company's properties and assets. The Senior Credit Agreement contains representations, warranties and covenants customary in transactions of this nature including restrictions on the payment of



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

dividends on the Company's capital stock and financial covenants, including minimum working capital levels (the ratio of current assets plus the unused commitment under the Senior Credit Agreement to current liabilities) of not less than 1.0 to 1.0 and minimum coverage of interest expenses (as defined in the Senior Credit Agreement) of not less than 2.5 to 1.0.

On August 1, 2012, in connection with the closing of the GeoResources and East Texas Assets acquisition, the Company entered into the First Amendment to the Senior Credit Agreement (the First Amendment). The First Amendment increased the commitments under the Senior Credit Agreement to an aggregate amount up to $1.5 billion and the borrowing base from $225.0 million to $525.0 million. On December 6, 2012, the borrowing base was increased from $525.0 million to $850.0 million. At December 31, 2012, the Company had $298.0 million of indebtedness outstanding, $1.3 million of letters of credit outstanding and $550.7 million of borrowing capacity available under the Senior Credit Agreement. At December 31, 2012 and as of the date of this filing, the Company is in compliance with the financial debt covenants under the Senior Credit Agreement.

On January 25, 2013, the Company entered into the Second Amendment (the Second Amendment) which amends the Senior Credit Agreement with respect to the Company's ability to enter into certain commodity hedging agreements. The Second Amendment provides, among other things, that the Company and its subsidiaries may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of the Company's internally forecasted production (i) from the Company's crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, from such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, the Company may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% (i) of the reasonably anticipated projected production from the Company's proved reserves for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, of the reasonably anticipated projected production from proved reserves from such oil and gas properties that are the subject of such proposed acquisition for the period of 25 to 48 months following the date such agreement is entered into. The 85% limitations discussed above do not apply to volumes hedged by the Company using puts, floors and/or basis differential swap agreements. See Note 16, "Subsequent Events", for further discussion.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from the Company's proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas liquids and natural gas, for the 66 months following the date such agreement was entered into.

## March 2011 Credit Facilities

The Company's March 2011 credit facilities included a $250.0 million revolving credit facility and a $75.0 million second lien term loan facility (the March 2011 Credit Facilities), replacing the November 2007 facility. SunTrust Bank was the administrative agent for the revolving credit facility, and Guggenheim Corporate Funding, LLC was the administrative agent for the second lien term loan facility. The revolving credit facility allowed for funds advanced to be paid down and reborrowed.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

during the five-year term of the revolver, and bore interest at LIBOR plus a margin ranging from 2.5% to 3.25% based on a percentage of usage. The second lien term loan facility provided for payments of interest only during its 5.5 year term, and bore interest at LIBOR plus 9.0% with a 2.0% LIBOR floor, or if any period the Company elected to pay a portion of the interest "in kind", then the interest rate would have been LIBOR plus 10.0% with a 2.0% LIBOR floor, and with 7.0% of the interest amount paid in cash and the remaining 3.0% paid in kind by being added to principal. At December 31, 2011, $127.0 million was outstanding under the revolving credit facility and $75.0 million was outstanding under the second lien term loan facility. On February 8, 2012, the Company paid in full the outstanding balances under the revolving credit facility and the second lien term loan facility and both facilities were terminated, resulting in a $1.5 million charge to interest expense related to an early termination penalty.

## 8.875% Senior Notes

On November 6, 2012, the Company completed a private offering to eligible purchasers of an aggregate principal amount of $750.0 million of its 8.875% senior notes due 2021 (the 2021 Notes), issued at 99.247% of par. The net proceeds from the offering were approximately $725.6 million after deducting the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Williston Basin Assets acquisition.

The 2021 Notes bear interest at a rate of 8.875% per annum, payable semi-annually on May 15 and November 15 of each year, beginning on May 15, 2013. The Notes will mature on May 15, 2021. The 2021 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2021 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing wholly-owned subsidiaries. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2021 Notes, the Company entered into a Registration Rights Agreement, dated November 6, 2012, between the Company and Wells Fargo Securities, LLC, on behalf of the Initial Purchasers (the Registration Rights Agreement, dated November 6, 2012). Pursuant to the Registration Rights Agreement, dated November 6, 2012, the Company has agreed to conduct a registered exchange offer for the 8.875% Notes or cause to become effective a shelf registration statement providing for the resale of the 2021 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement (the Registration Statement for the 2021 Notes) and use reasonable best efforts to cause such Registration Statement for the 2021 Notes to become effective, (b) promptly following the effectiveness of the Registration Statement for the 2021 Notes, offer to exchange each note of the 2021 Notes for a new note of the Company having terms substantially identical in all material respects to the 2021 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2021 Notes. If the exchange offer is not consummated within 365 days after November 6, 2012, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the Registration Rights Agreement, dated November 6, 2012, it will be required to pay liquidated damages in the form of additional cash interest to the holders of the Notes.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

On or before November 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2021 Notes with the net cash proceeds of certain equity offerings at a redemption price of 108.875% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2021 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the date of closing of the related equity offering. In addition, at any time prior to November 15, 2016, the Company may redeem some or all of the 2021 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at November 15, 2016, plus (ii) any required interest payments due on the notes through November 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

On or after November 15, 2016, the Company may redeem some or all of the 2021 Notes at any time or from time to time at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning November 15 of the years indicated below:

<table><tr><td>Year</td><td>Percentage</td></tr><tr><td>2016</td><td>104.438%</td></tr><tr><td>2017</td><td>102.219%</td></tr><tr><td>2018 and thereafter</td><td>100.000%</td></tr></table>

In addition, upon a change of control of the Company, holders of the 2021 Notes will have the right to require the Company to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest. The 2021 Notes were issued under and governed by an Indenture dated November 6, 2012, between the Company, U.S. Bank National Association, as trustee and the Company's subsidiaries named therein as guarantors (the Indenture). The Indenture contains covenants that, among other things, limit the ability of the Company and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens enter into transactions with affiliates; see assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of the Company's assets.

In conjunction with the issuance of the 2021 Notes, the Company recorded a discount of approximately $5.65 million to be amortized over the remaining life of the 2021 Notes using the effective interest method. The remaining unamortized discount was $5.58 million at December 31, 2012.

On January 14, 2013, the Company completed the issuance of an additional 600 million aggregate principal amount of its 8.875% senior notes due 2021 (the additional 2021 Notes), issued at 105.0% of par. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees). The net proceeds from this offering will be used to repay all of the outstanding borrowings under the Company's Senior Credit Agreement and for general corporate purposes, including funding a portion of the Company's 2013 capital expenditures program. There was no borrowing base reduction to the Company's Senior Credit Agreement as a result of the issuance of the additional 2021 Notes. For further discussion of this transaction, see Note 16, "Subsequent Events."



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

## 9.75% Senior Notes

On July 16, 2012, the Company completed a private offering of $750.0 million aggregate principal amount of 9.75% senior unsecured 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 the initial purchasers' discounts, commissions and offering expenses and were used to fund a portion of the cash consideration paid in the Merger and the East Texas Assets acquisition.

The 2020 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2013. The 2020 Notes will mature on July 15, 2020. The 2020 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness. The 2020 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company's existing wholly-owned subsidiaries. Halcón, the issuer of the 2021 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries.

In connection with the sale of the 2020 Notes, the Company entered into a Registration Rights Agreement, dated July 16, 2012, between the Company and Barclays Capital Inc., on behalf of the Initial Purchasers (the Registration Rights Agreement, dated July 16, 2012). Pursuant to the Registration Rights Agreement, dated July 16, 2012, the Company agreed to conduct a registered exchange offer for the 2020 Notes or cause to become effective a shelf registration statement providing for the resale of the 2020 Notes. In connection with the exchange offer, the Company is required to (a) file an exchange offer registration statement (the Registration Statement for the 2020 Notes) and use reasonable best efforts to cause such Registration Statement for the 2020 Notes to become effective, (b) promptly following the effectiveness of the Registration Statement for the 2020 Notes, offer to exchange each note of the 2020 Notes for a new note of the Company having terms substantially identical in all material respects to the 2020 Notes, and (c) keep the registered exchange offer open for not less than 20 business days after the date notice of the exchange offer is mailed to the holders of the 2020 Notes. If the exchange offer is not consummated within 365 days after July 16, 2012, or upon the occurrence of certain other contingencies, the Company has agreed to file a shelf registration statement to cover resales of the 2020 Notes by holders who satisfy certain conditions relating to the provision of information in connection with the shelf registration statement. If the Company fails to comply with certain obligations under the Registration Rights Agreement, dated July 16, 2012, it will be required to pay liquidated damages in the form of additional cash interest to the holders of the 2020 Notes.

On or before July 15, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 Notes with the net cash proceeds of certain equity offerings at a redemption price of 109.750% of the principal amount plus accrued and unpaid interest to the redemption date provided that: at least 65% in aggregate principal amount of the 2020 Notes originally issued remains outstanding immediately after the redemption and the redemption occurs within 180 days of the equity offering. In addition, at any time prior to July 15, 2016, the Company may redeem some or all of the 2020 Notes for the principal amount thereof, plus accrued and unpaid interest plus a make whole premium equal to the excess, if any of (a) the present value at such time of (i) the redemption price of such note at July 15, 2016, plus (ii) any required interest payments due on the notes through July 15, 2016 (excluding currently accrued and unpaid interest) computed using a discount rate equal to the



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis, over (b) the principal amount of such note.

On or after July 15, 2016, the Company may redeem some or all of the 2020 Notes at any time or from time to time at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning July 15 of the years indicated below:

<table><tr><td>Year</td><td>Percentage</td></tr><tr><td>2016</td><td>104.875%</td></tr><tr><td>2017</td><td>102.438%</td></tr><tr><td>2018 and thereafter</td><td>100.000%</td></tr></table>

In addition, upon a change of control of the Company, holders of the 2020 Notes will have the right to require the Company to repurchase all or any part of their notes for cash at a price equal to 101% of the aggregate principal amount of the notes repurchased, plus any accrued and unpaid interest. The 2020 Notes were issued under and governed by an Indenture dated July 16, 2012, between the Company, U.S. Bank National Association, as trustee and the Company's subsidiaries named therein as guarantors (the Indenture). The Indenture contains covenants that, among other things, limit the ability of the Company and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens enter into transactions with affiliates; see assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of the Company's assets.

In conjunction with the issuance of the 2020 Notes, the Company recorded a discount of approximately $10.2 million to be amortized over the remaining life of the 2020 Notes using the effective interest method. The remaining unamortized discount was $9.8 million at December 31, 2012.

## 8.0% Convertible Note

On February 8, 2012, the Company issued the 2017 Note in the principal amount of $275.0 million together with the February 2012 Warrants for an aggregate purchase price of $275.0 million. The 2017 Note bears interest at a rate of 8% per annum, payable quarterly on March 31, June 30, September 30 and December 31 of each year and matures on February 8, 2017. Through the March 31, 2014 interest payment date, the Company may elect to pay-in-kind, by adding to the principal of the 2017 Note, all or any portion of the interest due on the 2017 Note. The Company elected to pay the interest in kind on March 31, June 30 and September 30, 2012, and rolled $3.2 million, $5.7 million and $5.8 million of interest incurred during the first, second and third quarters of 2012, respectively, into the 2017 Note, increasing the principal amount to $289.7 million. For the three months ended December 31, 2012, the Company did not elect to pay-in-kind interest. At any time after February 8, 2014, the noteholder may elect to convert all or any portion of the principal amount and accrued but unpaid interest into common stock. Each $4.50 of principal and accrued but unpaid interest is convertible into one share of the Company's common stock. The 2017 Note is a senior unsecured obligation of the Company.

The Company allocated the proceeds received for the 2017 Note and February 2012 Warrants on a relative fair value basis. Consequently, the Company recorded a discount of $43.6 million to be



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 7. LONG-TERM DEBT (Continued)

amortized over the remaining life of the 2017 Note utilizing the effective interest rate method. The remaining unamortized discount was $37.8 million at December 31, 2012.

## Promissory Notes

On December 28, 2012, the Company completed acquisition of certain oil and natural gas properties in Brazos County, Texas for approximately $83.7 million, before customary closing adjustments, consisting of approximately $8.4 million in cash and approximately $75.3 million in promissory notes. The promissory notes accrue interest beginning March 29, 2013, to the extent there is a remaining principal balance of the promissory notes at such date. Interest accrues based on the Wall Street Journal Prime Rate effective March 29, 2013. The promissory notes mature on August 30, 2013 and are classified as current as of December 31, 2012.

In conjunction with the issuance of the promissory notes, the Company recorded a discount of approximately $0.6 million to be amortized over the remaining life of the promissory notes using the effective interest method. The remaining unamortized discount was $0.6 million at December 31, 2012.

## Debt Maturities

Aggregate maturities required on long-term debt at December 31, 2012 are due in future years as follows (in thousands):



(1) Amount includes $ 75.3 million of promissory notes which have been classified as current at December 31, 2012.

## Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. During 2012, the Company capitalized approximately $3.3 million, $13.7 million, $16.8 million and $20.0 million in costs associated with the issuance of the 2017 Note, Senior Credit Agreement, 2020 Notes and 2021 Notes, respectively. During February 2012, the Company expensed $5.8 million of debt issuance costs as a result of the pay off and termination of the March 2011 Credit Facilities. The Company expensed the remaining debt issuance cost associated with the November 2007 facility totaling approximately $2.7 million in the first quarter 2011. At December 31, 2012 and December 31, 2011, the Company had approximately $51.6 million and $6.0 million, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurements and Disclosures (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 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.

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, 2012 and 2011. 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.

<table><tr><td rowspan="2"></td><td colspan="4">December 31, 2012</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td>Assets</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></tr><tr><td></td><td>$ —</td><td>$ 7,799</td><td>$ —</td><td>$ 7,799</td></tr><tr><td>Liabilities</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></tr><tr><td></td><td>$ —</td><td>$ 12,890</td><td>$ —</td><td>$ 12,890</td></tr><tr><td>Liabilities from warrants(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>1,342</td><td>—</td><td>1,342</td></tr><tr><td>Total Liabilities</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ 14,232</td><td>$ —</td><td>$ 14,232</td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td colspan="4">December 31, 2011</td></tr><tr><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td></td><td colspan="4">(In thousands)</td></tr><tr><td>Assets</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></tr><tr><td></td><td>$ —</td><td>$ 3,900</td><td>$ —</td><td>$ 3,900</td></tr><tr><td>Liabilities</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></tr><tr><td></td><td>$ —</td><td>$ 4,710</td><td>$ —</td><td>$ 4,710</td></tr></table>

(1) Liabilities from warrants are recorded in "Accounts payable and accrued liabilities" on the consolidated balance sheet.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS (Continued)

Derivatives listed above include collars, swaps and put options and interest rate swaps 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 changes in the forward curves. See Note 9, "Derivative and Hedging Activities" for additional discussion of derivatives.

As of December 31, 2012 and 2011, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. The counterparties to the Company's current derivative contracts are lenders in the Company's Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.

Warrants listed above are carried at fair value. The Company records the net change in fair value on the August 2012 Warrants in "Interest expense and other" in the Company's consolidated statements of operations. During the year ended December 31, 2012 an unrealized gain of $0.1 million was recorded to reflect the change in fair value. The Company valued the August 2012 Warrants based on observable market data, including treasury rates, historical volatility and data for similar instruments which resulted in the Company reporting its warrants as Level 2. See Note 12, "Preferred Stock and Stockholders' Equity" for additional discussion on the terms of the warrants.

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, the March 2011 Credit Facilities and the promissory notes approximates carrying value because the facilities interest rate approximates 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, 2012 (excluding discounts):

<table><tr><td rowspan="3">Debt</td><td colspan="3">December 31, 2012</td></tr><tr><td>Carrying Amount</td><td colspan="2">Estimated Fair Value</td></tr><tr><td colspan="3">(In thousands)</td></tr><tr><td>8.875% $750 million senior notes</td><td></td><td></td><td></td></tr><tr><td>9.75% $750 million senior notes</td><td></td><td></td><td></td></tr><tr><td>8.0% $275 million senior note</td><td></td><td></td><td></td></tr><tr><td></td><td></td><td>750,000</td><td>798,750</td></tr><tr><td></td><td></td><td>750,000</td><td>815,160</td></tr><tr><td></td><td></td><td>289,669</td><td>625,425</td></tr><tr><td></td><td></td><td>$ 1,789,669</td><td>$ 2,239,335</td></tr></table>

The fair value of the Company's fixed interest debt instruments was calculated using quoted market prices based on trades of such debt as of December 31, 2012.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 8. FAIR VALUE MEASUREMENTS (Continued)

## Changes in Level 3 Instruments Measured at Fair Value on a Recurring Basis

At December 31, 2012, the Company transferred amounts from Level 3 to Level 2 for its 2020 Notes because inputs became more observable with the passage of time and the larger amount of trading activity which provides the quoted market prices. The following table provides a reconciliation of financial assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

<table><tr><td></td><td>Carrying Amount (In thousands)</td></tr><tr><td>December 31, 2011</td><td>$ —</td></tr><tr><td>Transfer into Level 3</td><td>750,000</td></tr><tr><td>Transfer out of Level 3</td><td>(750,000)</td></tr><tr><td>December 31, 2012</td><td>$ —</td></tr></table>

The Company now believes it has readily determinable market prices which allow for the long-term debt to be properly measured and the long-term debt was reclassified from Level 3 to Level 2.

## 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 economically 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. The Company 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. Historically, the Company has also entered into interest rate swaps to mitigate exposure to market rate fluctuations.

It is the Company's policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current derivative contracts are lenders or affiliates of lenders in its Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Company's Senior Credit Agreement.

At December 31, 2012 and 2011, the Company's crude oil and natural gas derivative positions consisted of swaps, costless put/call "collars" and sold 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. 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. 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



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

well as all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

In February 2012, pursuant to the Senior Credit Agreement, the Company novated its oil and natural gas derivative instruments to counterparties that are lenders within the Senior Credit Agreement resulting in a realized loss of $0.4 million for novation fees and terminated the interest rate derivatives resulting in a $0.6 million realized loss.

In April 2011, pursuant to the Company's March 2011 Credit Facilities, the Company was required to reduce the volume of its existing oil and natural gas derivative contracts so it would not exceed the maximum allowable volumes for future production periods and to novate derivative contracts to counterparties that are lenders within the March 2011 Credit Facilities. During the second quarter of 2011, the Company recognized a $0.9 million realized loss on the unwind of the excess oil and natural gas derivative contracts and paid $0.5 million in fees to complete the novation, both of which were included in "Net gain (loss) on derivative contracts" on the consolidated statements of operations.

At December 31, 2012, the Company had 47 open commodity derivative contracts summarized in the tables below: two natural gas collar arrangements, two natural gas swaps, one natural gas basis swap, 28 oil collar arrangements, 10 oil three-way collars, and four oil swaps.

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 summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2012 and 2011:

<table><tr><td rowspan="2">Derivatives not designated as hedging contracts under ASC 815</td><td rowspan="2">Balance sheet location</td><td colspan="2">Asset derivative contracts</td><td colspan="2">Liability derivative contracts</td></tr><tr><td>December 31,</td><td></td><td>December 31,</td><td></td></tr><tr><td></td><td></td><td>2012 (In thousands)</td><td>2011 (In thousands)</td><td>2012 (In thousands)</td><td>2011 (In thousands)</td></tr><tr><td>Commodity contracts</td><td>Current assets—receivables from derivative contracts</td><td>$ 7,428</td><td>$ 1,850</td><td>Current liabilities—liabilities from derivative contracts</td><td>$ (10,429)</td></tr><tr><td>Commodity contracts</td><td>Other noncurrent assets—receivables from derivative contracts</td><td>371</td><td>2,050</td><td>Noncurrent liabilities—liabilities from derivative contracts</td><td>(2,461)</td></tr><tr><td>Interest rate contracts</td><td>Current assets—receivables from derivative contracts</td><td>—</td><td>—</td><td>Current liabilities—liabilities from derivative contracts</td><td>—</td></tr><tr><td>Interest rate contracts</td><td>Other noncurrent assets—receivables from derivative contracts</td><td>—</td><td>—</td><td>Other noncurrent liabilities—liabilities from derivative contracts</td><td>—</td></tr><tr><td></td><td></td><td>$ 7,799</td><td>$ 3,900</td><td></td><td>$ (12,890)</td></tr><tr><td colspan="3">Total derivatives not designated as hedging contracts under ASC 815</td><td></td><td></td><td></td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

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:

<table><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>Amount of gain or (loss) recognized in income on derivative contracts for the year ended December 31,</td></tr><tr><td>Commodity contracts:</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>$ (13,723)</td></tr><tr><td>Realized gain (loss) on commodity contracts</td><td>Other income (expenses)—net gain (loss) on derivative contracts</td><td>$ 5,269</td></tr><tr><td>Total net gain (loss) on commodity contracts</td><td></td><td>$ (1,078)</td></tr><tr><td>Interest rate swaps:</td><td></td><td>$ (6,068)</td></tr><tr><td>Unrealized gain (loss) on interest rate swaps</td><td>Other income (expenses)—net gain (loss) on derivative contracts</td><td>$ 4,191</td></tr><tr><td>Realized loss on interest rate swaps</td><td></td><td>$ (206)</td></tr><tr><td>Total net loss on interest rate swaps</td><td></td><td>$ (712)</td></tr><tr><td>Total net gain (loss) on derivative contracts</td><td>Other income (expenses)—net gain (loss) on derivative contracts</td><td>$ 3,479</td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 9. DERIVATIVE AND HEDGING ACTIVITIES (Continued)

At December 31, 2012 and 2011, the Company had the following open 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="9">December 31, 2012</td></tr><tr><td rowspan="2">Volume in Mmbtu&#x27;s/ Bbl&#x27;s</td><td colspan="3">Floors</td><td colspan="3">Ceilings</td><td colspan="2">Put Options Sold</td></tr><tr><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Price / Price Range</td><td>Weighted Average Price</td><td></td></tr><tr><td>January 2013 - March 2013</td><td>3-Way Collars</td><td>Crude Oil</td><td>130,500</td><td>$95.00 - 100.00</td><td>$ 95.34</td><td>$105.50 - 109.50</td><td>$ 101.36</td><td>$ 70.00</td><td>$ 70.00</td><td></td><td></td></tr><tr><td>January 2013 - March 2013</td><td>Basis Swap</td><td>Natural Gas</td><td>225,000</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - March 2013</td><td>Collars</td><td>Crude Oil</td><td>31,500</td><td>95.00</td><td>95.00</td><td>101.50</td><td>101.50</td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - March 2013</td><td>Fixed swap</td><td>Natural Gas</td><td>225,000</td><td>4.85</td><td>4.85</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>April 2013 - June 2013</td><td>3-Way Collars</td><td>Crude Oil</td><td>120,575</td><td>95.00</td><td>95.00</td><td>99.50 - 100.60</td><td>99.77</td><td>70.00</td><td>70.00</td><td></td><td></td></tr><tr><td>April 2013 - June 2013</td><td>Collars</td><td>Crude Oil</td><td>29,575</td><td>95.00</td><td>95.00</td><td>100.60</td><td>100.60</td><td></td><td></td><td></td><td></td></tr><tr><td>July 2013 - September 2013</td><td>Collars</td><td>Crude Oil</td><td>147,200</td><td>95.00</td><td>95.00</td><td>99.00 - 101.50</td><td>99.94</td><td></td><td></td><td></td><td></td></tr><tr><td>October 2013 - December 2013</td><td>Collars</td><td>Crude Oil</td><td>142,600</td><td>95.00</td><td>95.00</td><td>99.00 - 101.00</td><td>99.71</td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - December 2013</td><td>Collars</td><td>Crude Oil</td><td>5,201,250</td><td>80.00 - 100.00</td><td>89.04</td><td>91.65 - 107.25</td><td>98.06</td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - December 2013</td><td>Collars</td><td>Natural Gas</td><td>1,825,000</td><td>3.75</td><td>3.75</td><td>4.26</td><td>4.26</td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - December 2013</td><td>Fixed swap</td><td>Natural Gas</td><td>240,000</td><td>3.56</td><td>3.56</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>January 2013 - December 2013</td><td>Fixed swap</td><td>Crude Oil</td><td>360,000</td><td>97.60 - 105.55</td><td>102.18</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>February 2013 - December 2013</td><td>Collars</td><td>Crude Oil</td><td>250,500</td><td>100.00</td><td>100.00</td><td>104.15</td><td>104.15</td><td></td><td></td><td></td><td></td></tr><tr><td>April 2014 - June 2014</td><td>3-Way Collars</td><td>Crude Oil</td><td>136,500</td><td>95.00</td><td>95.00</td><td>98.20 - 101.00</td><td>99.13</td><td>70.00</td><td>70.00</td><td></td><td></td></tr><tr><td>January 2014 - March 2014</td><td>3-Way Collars</td><td>Crude Oil</td><td>144,000</td><td>95.00</td><td>95.00</td><td>98.60 - 109.50</td><td>100.03</td><td>70.00</td><td>70.00</td><td></td><td></td></tr><tr><td>January 2014 - December 2014</td><td>Collars</td><td>Crude Oil</td><td>2,190,000</td><td>85.00</td><td>85.00</td><td>95.10 - 96.35</td><td>95.92</td><td></td><td></td><td></td><td></td></tr><tr><td>January 2014 - December 2014</td><td>Collars</td><td>Natural Gas</td><td>1,825,000</td><td>3.75</td><td>3.75</td><td>4.26</td><td>4.26</td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td rowspan="2">Period</td><td rowspan="2">Instrument</td><td rowspan="2">Commodity</td><td rowspan="2">Volume in Mbtu&#x27;s/ Bbl&#x27;s</td><td colspan="3">Floors</td><td colspan="3">Ceilings</td><td colspan="3">Put Options Sold</td></tr><tr><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Weighted Average Price</td><td>Price / Price Range</td><td>Price / Price Range</td><td>Weighted Average Price</td><td></td><td></td></tr><tr><td>January 2012 - December 2012</td><td>3-Way Collars</td><td>Crude Oil</td><td>400,500</td><td>$80.00 - 100.00</td><td>$</td><td>87.15</td><td>$101.70 - 113.25</td><td>$</td><td>104.89</td><td>$70.00</td><td>$</td><td>70.00</td></tr><tr><td>January 2012 - December 2012</td><td>Collars</td><td>Crude Oil</td><td>299,300</td><td>80.00 - 95.00</td><td></td><td>84.34</td><td>102.40 - 107.00</td><td></td><td>105.43</td><td></td><td></td><td></td></tr><tr><td>January 2012 - March 2012</td><td>Put Options</td><td>Natural gas</td><td>609,700</td><td>4.00 - 4.50</td><td></td><td>4.35</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>April 2012 - September 2012</td><td>Collars</td><td>Natural gas</td><td>915,000</td><td>4.00</td><td></td><td>4.00</td><td>6.00</td><td></td><td>6.00</td><td></td><td></td><td></td></tr><tr><td>January 2013 - June 2013</td><td>3-Way Collars</td><td>Crude Oil</td><td>251,075</td><td>95.00 - 100.00</td><td></td><td>95.18</td><td>99.50 - 109.50</td><td></td><td>100.60</td><td>70.00</td><td>70.00</td><td></td></tr><tr><td>January 2013 - December 2013</td><td>Collars</td><td>Crude Oil</td><td>350,875</td><td>95.00</td><td></td><td>95.00</td><td>99.00 - 101.50</td><td></td><td>100.04</td><td></td><td></td><td></td></tr><tr><td>January 2014 - December 2014</td><td>3-Way Collars</td><td>Crude Oil</td><td>280,500</td><td>95.00</td><td></td><td>95.00</td><td>98.20 - 109.50</td><td></td><td>99.59</td><td>70.00</td><td>70.00</td><td></td></tr></table>

The Company's interest rate derivative positions at December 31, 2011, consisting of interest rate swaps, are shown in the following table.

<table><tr><td rowspan="2">Year</td><td colspan="5">Interest Rate Swaps(1)(3)</td></tr><tr><td>Notional Amount (in thousands)</td><td>Fixed Rate</td><td>Counterparty Floating Rate(2)</td><td>Months Covered</td><td></td></tr><tr><td>2012</td><td>$</td><td>50,000</td><td>2.51% 3—Month LIBOR</td><td>January - December</td><td></td></tr><tr><td>2013</td><td></td><td>50,000</td><td>2.51% 3—Month LIBOR</td><td>January - December</td><td></td></tr><tr><td>2014</td><td></td><td>50,000</td><td>2.51% 3—Month LIBOR</td><td>January - March</td><td></td></tr></table>

(1) Settlement is paid to the Company if the counterparty floating exceeds the fixed rate and settlement is paid by the Company if the counterparty floating rate is below the fixed rate. Settlement is calculated as the difference in the fixed rate and the counterparty rate.

(2) Subject to minimum rate of 2%

(3) All outstanding interest rate swaps were terminated in conjunction with the recapitalization during February 2012.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 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. 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 the ARO liability for the years ended December 31, 2012 and 2011 (in thousands, inclusive of current portion):

<table><tr><td>Liability for asset retirement obligation as of December 31, 2010</td><td>$ 31,409</td></tr><tr><td>Liabilities settled and divested</td><td>(514)</td></tr><tr><td>Additions</td><td>207</td></tr><tr><td>Accretion expense</td><td>1,641</td></tr><tr><td>Revisions in estimated cash flows</td><td>970</td></tr><tr><td>Liability for asset retirement obligation as of December 31, 2011</td><td>$ 33,713</td></tr><tr><td>Liabilities settled and divested</td><td>(4,213)</td></tr><tr><td>Additions</td><td>2,627</td></tr><tr><td>Acquisitions(1)</td><td>33,855</td></tr><tr><td>Accretion expense</td><td>2,306</td></tr><tr><td>Revisions in estimated cash flows</td><td>6,844</td></tr><tr><td>Liability for asset retirement obligation as of December 31, 2012</td><td>$ 75,132</td></tr></table>

(1) See Note 5, "Acquisitions and Divestitures" for additional information on acquisitions.

## 11. COMMITMENTS AND CONTINGENCIES

## Commitments

The Company leases corporate office space in Houston and Plano, Texas; Tulsa, Oklahoma; Denver, Colorado; and Williston, North Dakota 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 2020. Rent expense was approximately $3.7 million, $1.3 million and $1.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Approximate future minimum lease payments for



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 11. COMMITMENTS AND CONTINGENCIES (Continued)

subsequent annual periods for all non-cancelable operating leases as of December 31, 2012 are as follows (in thousands):



As of December 31, 2012, the Company has drilling rig commitments totaling $79.4 million as follows (in thousands):



As of December 31, 2012, early termination of the drilling rigs commitments would require termination penalties of $50.8 million, which would be in lieu of paying the remaining drilling commitments of $79.4 million.

The Company has various other contractual commitments for, among other things, pipeline and well equipment and infrastructure related expenditures.






<table><tr><td>Thereafter</td><td>—</td></tr><tr><td>Total</td><td>$ 17,809</td></tr></table>

The Company has committed to one long-term natural gas sales contract in its Williams County, North Dakota project area in the Bakken trend. Under the terms of this contract the Company has committed substantially all of the natural gas production for the life of its leases to one purchaser. In return for the life of lease commitment, the purchaser has committed to building a gas gathering system across the Company's project area. The sales price under this contract is based on a posted market rate.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 11. COMMITMENTS AND CONTINGENCIES (Continued)

## 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.

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY

## Preferred Stock and Non-Cash Preferred Stock Dividend

On February 29, 2012 (the Commitment Date), the Company entered into definitive agreements with a group of certain institutional and selected other accredited investors (collectively, the investors) to sell, in a private offering, 4,444,4511 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on February 29, 2012, the Company received an executed written consent (the Consent) in lieu of a stockholders' meeting authorizing and approving the conversion of the Preferred Stock into common stock. On March 2, 2012, the Company filed a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation) with the Delaware Secretary of State which stated the conversion was to occur on the twentieth day after the mailing of a definitive information statement to stockholders. On March 5, 2012, the Company issued the Preferred Stock to the investors at $90,000 per share. Gross proceeds from the offering were approximately $400.0 million, or $9.00 per share of common stock, before offering expenses. The Company incurred placement agent fees of $14.0 million and associated expenses of approximately $0.5 million in connection with this offering. On March 28, 2012, the Company mailed a definitive information statement to its common stockholders notifying them that Halcón's majority stockholder had consented to the issuance of common stock, par value $0.0001, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 44.4 million shares of common stock on April 17, 2012 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to May 31, 2012.

In accordance with ASC 470—Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the common stock of $10.99 per share on the Commitment Date was greater than the conversion price of $9.00 per share of common stock, representing a beneficial conversion feature of $1.99 per share of common stock, or $88.4 million in aggregate. Under ASC 470, $88.4 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to additional paid-in capital, creating a discount on the Preferred Stock (the Discount). The Discount resulting from the allocation of value to the beneficial conversion feature was required to be amortized on a non-cash basis over the approximate 71-month period between the issuance date and the required redemption date of February 9, 2018, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. As a result, approximately $1.1 million of the Discount was amortized and a non-cash preferred dividend was recorded in the first quarter of 2012 and due to the conversion date occurring on April 17, 2012, the remaining $87.3 million of Discount amortization was accelerated to the conversion date and was fully amortized in the second quarter of 2012 as per the guidance of ASC 470. The Discount amortization is reflected as non-cash



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

preferred dividend in the consolidated statements of operations. In accordance with the guidance in ASC 480, the preferred dividend was charged against additional paid-in capital since no retained earnings were available.

On December 6, 2012, the Company completed the Williston Basin Acquisition for a total adjusted purchase price of approximately $1.5 billion, consisting of approximately $756.1 million in cash and approximately $695.2 million in newly issued shares of Halcón preferred stock that automatically converted into 108.8 million shares of Halcón common stock (equivalent to a conversion price of approximately $7.45 per share of Halcón common stock), following stockholder approval on January 17, 2013 of such conversion and an amendment to Halcón's certificate of incorporation to increase the number of shares of common stock that Halcón is authorized to issue. The shares of preferred stock were issued to the Petro-Hunt Parties in a private placement pursuant to the exemptions from registration under Section 4(2) of the Securities Act of 1933, as amended.

Immediately following the completion of the Williston Basin Acquisition (and the related private placement of Halcon common stock described below), the Petro-Hunt Parties held preferred stock representing approximately 22% of Halcón's outstanding common stock on an as-converted, fully diluted basis. In addition, Halcón has agreed to cause one individual designated by the Petro-Hunt Parties to be elected or appointed to Halcón's board of directors, subject to the reasonable approval of Halcón's Nominating and Corporate Governance Committee, for so long as the Petro-Hunt Parties beneficially own at least 5% of the outstanding shares of Halcón common stock. On December 6, 2012, in connection with the closing of the Williston Basin Transaction and pursuant to the terms of the Purchase Agreement, David S. Hunt was appointed to Halcón's board of directors as a Class B director with a term expiring in 2015.

On January 17, 2013, the Company received the results from the special stockholders' meeting authorizing and approving the issuance of 108.8 million shares of common stock upon the conversion of the convertible preferred stock issued to Petro-Hunt Parties. Following the approval by the stockholders, on January 18, 2013, each outstanding share of the Company's preferred stock converted into 10,000 shares of its common stock at an effective conversion price of approximately $7.45 per share. No proceeds were received by the Company upon conversion of the preferred stock. No cash dividends were paid on the preferred stock since pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to April 6, 2013.

## Common Stock

In January 2012, the Company approved a one-for-three reverse stock split, which was implemented on February 10, 2012. Retroactive application of the reverse stock split is required and all share and per share information included for all periods presented in these financial statements reflects the reverse stock split.

On February 8, 2012 pursuant to the closing of the recapitalization described in Note 3, "Recapitalization," the Company issued 73.3 million shares of the Company's common stock for a purchase price of $275.0 million. Costs incurred of $4.0 million were netted against the proceeds of the common stock and recorded accordingly. In addition, the Company amended its certificate of incorporation to increase the Company's authorized shares of common stock from 33.3 million shares to 336.7 million shares.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

In early August 2012, in connection with the Merger and the East Texas Acquisition, the Company issued 51.3 million and 20.8 million shares of common stock, respectively. The shares were issued at closing of the transactions as a portion of the consideration of the purchase price. See Note 5, "Acquisitions and Divestitures," for additional discussion on the issuance of common stock in connection with these transactions.

On December 6, 2012, the Company completed the private placement of 41.9 million shares of common stock, par value $0.0001 per share, to CPP Investment Board PMI-2 Inc. (CPPIB), for gross proceeds of approximately $300.0 million, or $7.16 per share of common stock (the CPPIB Transaction). The net proceeds to the Company were $294.0 million following the payment of a $6.0 million capital commitment payment to CPPIB upon closing of the transaction. The shares of Halcón common stock were issued to CPPIB in a private placement pursuant to the exemptions from registration provided under Section 4(2) of the Securities Act.

Concurrent with the closing of the CPPIB Transaction, Halcón and CPPIB entered into a Stockholders' Agreement (the Stockholders' Agreement) that provided among other things, that for as long as CPPIB beneficially owns at least 5% of Halcón's common stock, it may designate one individual to serve on Halcón's board of directors and two individuals for so long as it owns 20% or more of Halcón's common stock, such individual(s) to be subject to the reasonable approval of Halcón's Nominating and Corporate Governance Committee. On December 6, 2012, in connection with the closing of the CPPIB Transaction and pursuant to the terms of the Stockholders Agreement, Kevin E. Godwin was appointed to Halcón's board of directors as a Class B director with a term expiring in 2015. At the close of the CPPIB Transaction, CPPIB held approximately 9% of Halcón's outstanding common stock on a fully diluted basis after giving effect to the completion of the Williston Basin Assets acquisition. CPPIB agreed to a one-year lock-up period, ending October 19, 2013, during which time it will not offer for sale, sell, pledge or otherwise dispose of the shares of Halcón common stock it acquired pursuant to the Common Stock Purchase Agreement, subject to certain exceptions. The Stockholders' Agreement also provided CPPIB with certain pre-emptive rights to acquire additional Halcón securities, as well as shelf registration, demand underwriting and piggyback registration rights.

Also, on January 17, 2013 with stockholder approval, the 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 333.3 million shares for a total of 670.0 million authorized shares of common stock.

## Warrants

In February 2012, in conjunction with the issuance of the 2017 Notes, the Company issued February 2012 Warrants to purchase 36.7 million shares of the Company's common stock at an exercise price of $4.50 per share of common stock pursuant to the recapitalization described in Note 3, "Recapitalization." The Company allocated $43.6 million to the February 2012 Warrants which is reflected in additional paid-in capital in stockholders' equity, net of $0.6 million in issuance costs. The February 2012 Warrants entitle the holders to exercise the warrants in whole or in part at any time prior to the expiration date of February 8, 2017.

In August 2012, as part of Merger, the Company assumed outstanding GeoResources stock warrants. At the date of the Merger 0.6 million warrants were outstanding and converted to 1.2 million Halcón warrants (the August 2012 Warrants). Each GeoResources warrant was converted into an August 2012 Warrant to acquire one share of Halcón common stock (Share Portion) at an exercise



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

price of $8.40 per share of common stock and the right to receive $20 in cash per equivalent assumed share (Cash Portion) at an exercise price of $0.82 per $1.00 received. The August 2012 Warrants will expire on June 9, 2013 and contain substantially the same terms of the original GeoResources warrants with adjustments to the exercise price and addition of the Cash Portion to reflect the impact of the consideration per share from the Merger. These adjustments convert the terms to fundamentally equal what the warrant holders would have received had the warrants been exercised immediately prior to the close of the Merger. Under the terms of the August 2012 Warrants, the warrant holder must exercise the Share Portion and the Cash Portion in tandem. The August 2012 Warrants are reflected as a current liability in the consolidated balance sheets and at December 31, 2012 are recorded at fair value. Changes in fair value are recognized in "Interest expense and other" in the consolidated statements of operations.

## Incentive Plan

On May 8, 2006, the Company's stockholders first approved its 2006 Long-Term Incentive Plan (the Plan). The Company reserved a maximum of 0.8 million shares of its common stock for issuances under the Plan. On May 8, 2008, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 0.8 million to 2.0 million. On May 3, 2010, the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2.0 million to 2.5 million. On February 8, 2012, as part of the Recapitalization described in Note 3 "Recapitalization," the Plan was amended to increase the maximum authorized number of shares to be issued under the Plan from 2.5 million to 3.7 million. On May 17, 2012, shareholders approved an amendment and restatement of the Plan to (i) increase the maximum number of shares to be issued under the Plan from 3.7 million to 11.5 million; (ii) extend the effectiveness of the Plan for ten years from the date of approval; and (iii) amend various other provisions of the Plan. As of December 31, 2012 and December 31, 2011, a maximum of 4.4 million and 491,450 shares of common stock, respectively, remained reserved for issuance under the Plan.

The Company accounts for share-based payment accruals under authoritative guidance on stock compensation, as set forth in ASC Topic 718. 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 the years ended December 31, 2012, 2011 and 2010, respectively, the Company recognized $6.7 million, $3.6 million, and $3.1 million, respectively, of share-based compensation expense as a component of "General and administrative" on the consolidated statements of operations.

## Stock Options

During the year ended December 31, 2012, the Company granted stock options under the Plan covering 4.8 million 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. The stock options have exercise prices ranging from $5.48 per share of common stock to $11.55 per share of common stock with a weighted average exercise price of $7.24 per share of common stock. The weighted average grant date fair value of options granted in 2012 was $16.5 million. 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. At December 31, 2012, the unrecognized compensation expense related to stock options totaled $12.9 million and will be recognized on the graded-vesting method over the requisite service periods. The weighted average remaining vesting period as of December 31, 2012 was 1.7 years.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

The following table sets forth the stock option transactions for the year ended December 31, 2012:

<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, 2009</td><td>—</td><td>—</td><td>—</td><td>—</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>—</td><td>—</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2010</td><td>—</td><td>—</td><td>—</td><td>—</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>—</td><td>—</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2011</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>4,847,333</td><td>7.24</td><td></td><td></td></tr><tr><td>Exercised</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Forfeited</td><td>(35,500)</td><td>9.35</td><td></td><td></td></tr><tr><td>Outstanding at December 31, 2012</td><td>4,811,833</td><td>7.22</td><td>2,944</td><td>9.7</td></tr></table>

(1) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. No stock options were exercised during the year ended December 31, 2012.

Options outstanding at December 31, 2012 consisted of the following:

<table><tr><td colspan="4">Outstanding</td><td colspan="5">Exercisable(1)</td></tr><tr><td rowspan="2">Range of Grant Prices Per Share</td><td colspan="2">Weighted Average</td><td rowspan="2">Weighted Average Remaining Contractual Life (Years)</td><td rowspan="2">Number</td><td colspan="2">Weighted Average</td><td rowspan="2">Aggregate Intrinsic Value</td><td rowspan="2">Weighted Average Remaining Contractual Life (Years)</td></tr><tr><td>Number</td><td>Exercise Price per Share</td><td>Number</td><td>Exercise Price per Share</td></tr><tr><td>$5.48 - $5.96</td><td>1,790,000</td><td>$</td><td>5.49</td><td>9.9</td><td>—</td><td>$</td><td>—</td><td>—</td></tr><tr><td>5.97 - 6.92</td><td>1,357,000</td><td></td><td>6.64</td><td>9.8</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>6.93 - 10.00</td><td>721,500</td><td></td><td>8.45</td><td>9.5</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>10.01 - 11.55</td><td>943,333</td><td></td><td>10.41</td><td>9.4</td><td>—</td><td>—</td><td>—</td><td>—</td></tr></table>

(1) At December 31, 2012, none of the Company's options were exercisable due to service or performance conditions.



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

The assumptions used in calculating the year ended December 31, 2012 fair value of the Company's share-based compensation are disclosed in the following table:

<table><tr><td>Weighted average value per option granted during the period</td><td>$ 3.40</td></tr><tr><td>Assumptions:</td><td></td></tr><tr><td>Stock price volatility(1)</td><td>61.84%</td></tr><tr><td>Risk free rate of return</td><td>0.54%</td></tr><tr><td>Expected term</td><td>4 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 options prices and assumptions are 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 vests 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. At the request of certain of the grantees, the Company repurchased a portion of the vested shares at the closing market price of the Company's common stock as of the vesting date, to satisfy the requesting grantees' federal and state income tax withholding requirements. The repurchased shares are held by the Company as treasury stock.

The number of shares repurchased and their weighted average prices for the three year period ended December 31, 2012 were as follows:

<table><tr><td colspan="4">Shares Repurchased</td></tr><tr><td>Year ended</td><td>Number of Shares</td><td>Weighted Average Closing Price</td><td></td></tr><tr><td>December 31, 2010</td><td>138,018</td><td>$ 5.70</td><td></td></tr><tr><td>December 31, 2011</td><td>46,516</td><td>3.93</td><td></td></tr><tr><td>December 31, 2012</td><td>199,778</td><td>10.75</td><td></td></tr></table>

The weighted average grant date fair value of the shares granted in 2012, 2011, and 2010 was $2.8 million, $1.5 million and $3.7 million, respectively. At December 31, 2012, 2011 and 2010, the unrecognized compensation expense related to non-vested restricted stock totaled $1.6 million, $2.7 million and $5.1 million, respectively. The weighted average remaining vesting period as of December 31, 2012, 2011, and 2010 was 2.0 years.

In February 2012, the Company realized compensation expense of $2.6 million primarily from the accelerated vesting of all unvested employee restricted stock shares outstanding at the time of the change in control in the Company resulting from the recapitalization as described in Note 3, "Recapitalization."



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

The following table sets forth the restricted stock transactions for the years ended December 31, 2012, 2011 and 2010:

<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, 2009</td><td>787,998</td><td>$ 7.92</td><td>$ 4,846</td></tr><tr><td>Granted</td><td>623,885</td><td>5.97</td><td></td></tr><tr><td>Vested</td><td>(519,159)</td><td>7.95</td><td></td></tr><tr><td>Forfeited</td><td>(7,500)</td><td>6.81</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2010</td><td>885,224</td><td>$ 6.51</td><td>$ 4,886</td></tr><tr><td>Granted</td><td>279,907</td><td>5.23</td><td></td></tr><tr><td>Vested</td><td>(209,710)</td><td>7.81</td><td></td></tr><tr><td>Forfeited</td><td>(117,934)</td><td>5.26</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2011</td><td>837,487</td><td>$ 5.92</td><td>$ 7,864</td></tr><tr><td>Granted</td><td>312,900</td><td>8.91</td><td></td></tr><tr><td>Vested</td><td>(334,838)</td><td>5.44</td><td></td></tr><tr><td>Accelerated vesting(2)</td><td>(547,649)</td><td>7.43</td><td></td></tr><tr><td>Forfeited</td><td>—</td><td>—</td><td></td></tr><tr><td>Unvested outstanding shares at December 31, 2012</td><td>267,900</td><td>$ 8.72</td><td>$ 1,854</td></tr></table>

(1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2012, 2011, 2010 and 2009 of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested were $9.2 million, $0.8 million and $3.1 million for the years 2012, 2011, and 2010, respectively.

(2) Represents accelerated vesting of all unvested employee restricted stock shares outstanding at the time of the change in control in the Company resulting from the Recapitalization.

## Stock Appreciation Rights

In May 2011, the Company granted 0.5 million stock appreciation rights (SARs) under the Plan at an exercise price of $5.19 per share of common stock, which was the weighted average closing price of the Company's common stock on the date of grant. Compensation expense related to the SARs is based on fair value re-measured at each reporting period and recognized over the vesting period (generally four years). As of December 31, 2011, the fair value calculation resulted in $0.8 million unrealized loss recognized as share-based compensation expense, a component of "General and administrative" on the consolidated statements of operations, and $0.1 million as restructuring costs on the consolidated statements of operations during the year ended December 31, 2011. The SARs expire ten years from date of grant and upon exercise. The terms of the SARs require settlement in cash, net of applicable taxes. In February 2012, the Company accelerated vesting and exercise of all unvested stock appreciation rights under the Plan, due to the change in control of the Company resulting from the recapitalization described in Note 3, "Recapitalization." The Company settled the SARs in cash, resulting in $2.2 million of share-based compensation expense recognized for the year ended



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 12. PREFERRED STOCK AND STOCKHOLDERS' EQUITY (Continued)

December 31, 2012. The realized compensation expense was partially offset by the reversal of $0.8 million of unrealized losses recorded at December 31, 2011. A summary of the non-vested SARs as of December 31, 2012, and changes during the year ended December 31, 2012, is presented below:

<table><tr><td></td><td>Number</td><td>Weighted Average Grant Date Fair Value</td></tr><tr><td>Non-vested at December 31, 2010</td><td>—</td><td>$ —</td></tr><tr><td>Granted</td><td>510,167</td><td>5.19</td></tr><tr><td>Vested</td><td>(20,000)</td><td>5.19</td></tr><tr><td>Forfeited</td><td>(71,834)</td><td>5.19</td></tr><tr><td>Non-vested at December 31, 2011</td><td>418,333</td><td>5.19</td></tr><tr><td>Granted</td><td>—</td><td>—</td></tr><tr><td>Vested</td><td>(84,418)</td><td>5.19</td></tr><tr><td>Accelerated Vesting(1)</td><td>(333,915)</td><td>5.19</td></tr><tr><td>Forfeited</td><td>—</td><td>—</td></tr><tr><td>Nonvested at December 31, 2012</td><td>—</td><td>—</td></tr></table>

(1) Represents accelerated vesting of all unvested employee SARs outstanding at the time of the change in control in the Company resulting from the Recapitalization.

The Company uses the Black-Scholes option pricing model to compute the fair value of the SARs. The following assumptions were used in calculating fair value:

• The risk-free interest rate is based on the zero coupon United States Treasury yield for the expected life of the grant.

- The dividend yield on the Company's common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.

- The volatility of the Company's common stock is based on volatility of the market price of the Company's common stock over a period of time equal to the expected term and ending on the grant date.



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. INCOME TAXES

Income tax (provision) benefit for the indicated periods is comprised of the following:

<table><tr><td rowspan="2"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td></td><td colspan="4">(In thousands)</td></tr><tr><td>Current:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ —</td><td>$ (253)</td><td>$ (418)</td><td></td></tr><tr><td>State</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>121</td><td>—</td><td>—</td><td></td></tr><tr><td></td><td>121</td><td>(253)</td><td>(418)</td><td></td></tr><tr><td>Deferred:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>12,265</td><td>(6,549)</td><td>(577)</td><td></td></tr><tr><td>State</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>795</td><td>—</td><td>—</td><td></td></tr><tr><td></td><td>13,060</td><td>(6,549)</td><td>(577)</td><td></td></tr><tr><td>Total income tax (provision) benefit</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 13,181</td><td>$ (6,802)</td><td>$ (995)</td><td></td></tr></table>

The actual income tax (provision) benefit differs from the expected income tax (provision) benefit as computed by applying the United States Federal corporate income tax rate of 35% for each period as follows:

<table><tr><td rowspan="2"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td></td><td colspan="4">(In thousands)</td></tr><tr><td>Expected tax (provision) benefit</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 23,485</td><td>$ (1,836)</td><td>$ (1,160)</td><td></td></tr><tr><td>State income tax expense, net of federal benefit</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>455</td><td>(557)</td><td>(124)</td><td></td></tr><tr><td>Merger costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(3,580)</td><td>—</td><td>—</td><td></td></tr><tr><td>Debt related costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(3,239)</td><td>—</td><td>—</td><td></td></tr><tr><td>Meals and entertainment expense</td><td></td><td>(29)</td><td>(19)</td><td>(25)</td></tr><tr><td>Non-deductible dues</td><td></td><td>(28)</td><td>(124)</td><td>(69)</td></tr><tr><td>Reduction in deferred tax asset</td><td></td><td>(3,218)</td><td>(5,957)</td><td>(5,731)</td></tr><tr><td>Change in valuation allowance and related items</td><td></td><td>—</td><td>1,883</td><td>6,572</td></tr><tr><td>Share-based compensation</td><td></td><td>(638)</td><td>(260)</td><td>(393)</td></tr><tr><td>Other</td><td></td><td>(27)</td><td>68</td><td>(65)</td></tr><tr><td>Total income tax (provision) benefit</td><td></td><td>$ 13,181</td><td>$ (6,802)</td><td>$ (995)</td></tr></table>






## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. INCOME TAXES (Continued)

The components of net deferred income tax assets and (liabilities) recognized are as follows:

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011(1)</td></tr><tr><td colspan="2">(In thousands)</td></tr><tr><td>Deferred current income tax assets:</td><td></td><td></td></tr><tr><td>Unrealized hedging transactions</td><td>$     3,588</td><td>$ (1,669)</td></tr><tr><td>Other</td><td>$     1,719</td><td>3,071</td></tr><tr><td>Gross deferred current income tax assets</td><td>5,307</td><td>1,402</td></tr><tr><td>Valuation allowance</td><td>—</td><td>—</td></tr><tr><td>Deferred current income tax assets</td><td>$     5,307</td><td>$     1,402</td></tr><tr><td>Deferred current income tax liabilities:</td><td></td><td></td></tr><tr><td>Other</td><td>$      —</td><td>$ (322)</td></tr><tr><td>Deferred current income tax liabilities</td><td>$      —</td><td>$ (322)</td></tr><tr><td>Net noncurrent deferred income tax assets</td><td>$     5,307</td><td>$     1,080</td></tr><tr><td>Deferred noncurrent income tax assets:</td><td></td><td></td></tr><tr><td>Net operating loss carry-forwards</td><td>$     157,316</td><td>$     25,050</td></tr><tr><td>Depreciable/depletable property, plant and equipment</td><td>—</td><td>(904)</td></tr><tr><td>Share-based compensation expense</td><td>1,063</td><td>—</td></tr><tr><td>Asset retirement obligations</td><td>28,488</td><td>—</td></tr><tr><td>Other</td><td>2,299</td><td>(324)</td></tr><tr><td>Gross deferred noncurrent income tax assets</td><td>189,166</td><td>23,822</td></tr><tr><td>Valuation allowance</td><td>(2,285)</td><td>(2,285)</td></tr><tr><td>Deferred noncurrent income tax assets</td><td>$     186,881</td><td>$     21,537</td></tr><tr><td>Deferred noncurrent income tax liabilities:</td><td></td><td></td></tr><tr><td>Book-tax differences in property basis</td><td>$ (339,607)</td><td>$     —</td></tr></table>



<table><tr><td>Unrealized hedging transactions</td><td>(2,620)</td><td>—</td></tr><tr><td>Investment in unconsolidated entities</td><td>(4,156)</td><td>—</td></tr><tr><td>Other</td><td>(553)</td><td>(182)</td></tr><tr><td>Deferred noncurrent income tax liabilities</td><td>$ (346,936)</td><td>$ (182)</td></tr><tr><td>Net noncurrent deferred income tax assets</td><td>$ (160,055)</td><td>$ 21,355</td></tr></table>

(1) See further discussion at Note 2, "Corrections of Immaterial Errors."

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 unrecognized tax benefits for the years ended December 31, 2010, 2011 or 2012.

Generally, the Company's income tax years 2009 through 2012 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana, New Mexico, North Dakota,



# HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 13. INCOME TAXES (Continued)

Oklahoma, Texas, Ohio, Pennsylvania and certain other small state taxing jurisdictions where the Company has its principal 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 Company recognizes interest and penalties accrued to unrecognized benefits in "Interest expense and other" in its statements of operations. For the years ended December 31, 2012, 2011 and 2010 the Company recognized no interest and penalties.

As of December 31, 2012, the Company has available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $423.3 million (net of excess income tax benefits not recognized of $4.2 million) which expires in the years 2020 thru 2030. The majority of these net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (the "Code"). Despite this limitation, the Company expects that the deferred tax benefits related to the NOLs will be utilized prior to their expiration. The Company also has various state NOL carryforwards of approximately $34.5 million, net of the valuation allowance for losses that the Company anticipates will expire before they can be utilized, as of December 31, 2012 with varying lengths of allowable carryforward periods ranging from five to 20 years that can be used to offset future state taxable income. It is expected that these deferred income tax benefits will be utilized prior to their expiration.

## 14. EARNINGS PER SHARE

The following represents the calculation of earnings per share:

<table><tr><td rowspan="3"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td colspan="4">(In thousands, except per share amounts)</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></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (142,330)</td><td>$ (1,403)</td><td>$ 2,417</td><td></td></tr><tr><td>Weighted average basic number of common shares outstanding</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>156,494</td><td>26,258</td><td>26,142</td><td></td></tr><tr><td>Basic net income (loss) per common share</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (0.91)</td><td>$ (0.05)</td><td>$ 0.09</td><td></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></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (142,330)</td><td>$ (1,403)</td><td>$ 2,417</td><td></td></tr><tr><td>Weighted average basic number of common shares outstanding</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>156,494</td><td>26,258</td><td>26,142</td><td></td></tr><tr><td>Common stock equivalent shares representing shares issuable upon exercise of stock options</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Common stock equivalent shares representing shares issuable upon exercise of warrants</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Common stock equivalent shares representing shares issuable upon conversion of debt or preferred stock</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Weighted average diluted number of common shares outstanding</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>156,494</td><td>26,258</td><td>26,142</td><td></td></tr><tr><td>Diluted net income (loss) per common share</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (0.91)</td><td>$ (0.05)</td><td>$ 0.09</td><td></td></tr></table>



## HALCÓN RESOURCES CORPORATION

## NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 14. EARNINGS PER SHARE (Continued)

Common stock equivalents, including stock options, warrants and convertible debt and convertible preferred stock, totaling 215.8 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, 2012. There were no convertible shares for the years ended December 31, 2011 and 2010, respectively.

## 15. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following:

<table><tr><td rowspan="3"></td><td colspan="2">December 31,</td></tr><tr><td>2012</td><td>2011</td></tr><tr><td colspan="2">(In thousands)</td></tr><tr><td>Accounts receivable:</td><td></td><td></td></tr><tr><td>Oil, natural gas and natural gas liquids revenues</td><td></td><td></td></tr><tr><td></td><td>$ 143,794</td><td>$ 9,519</td></tr><tr><td>Joint interest accounts</td><td></td><td></td></tr><tr><td></td><td>113,671</td><td>597</td></tr><tr><td>Affiliated partnerships</td><td></td><td></td></tr><tr><td></td><td>475</td><td>—</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>4,869</td><td>172</td></tr><tr><td></td><td>$ 262,809</td><td>$ 10,288</td></tr><tr><td>Prepaids and other:</td><td></td><td></td></tr><tr><td>Prepaid</td><td></td><td></td></tr><tr><td></td><td>$ 3,690</td><td>$ 936</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>3,001</td><td>1,793</td></tr><tr><td></td><td>$ 6,691</td><td>$ 2,729</td></tr><tr><td>Accounts payable and accrued liabilities:</td><td></td><td></td></tr><tr><td>Trade payables</td><td></td><td></td></tr><tr><td></td><td>$ 147,679</td><td>$ 11,498</td></tr><tr><td>Accrued oil and natural gas capital costs</td><td></td><td></td></tr><tr><td></td><td>282,245</td><td>1,392</td></tr><tr><td>Revenues and royalties payable</td><td></td><td></td></tr><tr><td></td><td>91,761</td><td>8,564</td></tr><tr><td>Accrued interest expense</td><td></td><td></td></tr><tr><td></td><td>45,201</td><td>464</td></tr><tr><td>Accrued income taxes payable</td><td></td><td></td></tr><tr><td></td><td>130</td><td>406</td></tr><tr><td>Accrued employee compensation</td><td></td><td></td></tr><tr><td></td><td>12,321</td><td>1,600</td></tr><tr><td>Drilling advances from partners</td><td></td><td></td></tr><tr><td></td><td>8,840</td><td>26</td></tr><tr><td>Accounts payable to affiliated partnerships</td><td></td><td></td></tr><tr><td></td><td>822</td><td>—</td></tr><tr><td>Other</td><td></td><td></td></tr><tr><td></td><td>1,552</td><td>1,111</td></tr><tr><td></td><td>$ 590,551</td><td>$ 25,061</td></tr></table>



## 16. SUBSEQUENT EVENTS

## Issuance of Additional 2021 Notes

On January 14, 2013, the Company completed the issuance of an additional $600 million aggregate principal amount of its 8.875% senior notes due 2021 (the additional 2021 Notes). The additional 2021 Notes are additional notes under an indenture pursuant to which the Company issued its 8.875% Senior Notes due 2021, in an aggregate principal amount of $750.0 million on November 6, 2012 (the Existing Notes). The additional 2021 Notes were issued under the same indenture as the Existing Notes.



# HALCÓN RESOURCES CORPORATION

# NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)

## 16. SUBSEQUENT EVENTS (Continued)

and are part of the same series. Interest on the additional 2021 Notes is payable on May 15 and November 15 of each year, beginning on May 15, 2013. Interest on the additional 2021 Notes will accrue from November 6, 2012, the original issuance date of the series. The additional 2021 Notes are senior unsecured obligations of the Company and rank equally with all of its current and future senior indebtedness.

The additional 2021 Notes were sold at 105.0% of the aggregate principal amount of the additional 2021 Notes plus accrued interest. The net proceeds from the sale of the additional 2021 Notes were approximately $619.5 million (after deducting offering fees and expenses). The net proceeds from this offering were used to repay all of the outstanding borrowings under the Company's senior revolving credit facility and for general corporate purposes, including funding a portion of the Company's 2013 capital expenditures program. There was no borrowing base reduction to the Company's Senior Credit Agreement as a result of the issuance of the additional 2021 Notes.

## Second Amendment to the Senior Credit Agreement

On January 25, 2013, the Company entered into the Second Amendment to Senior Credit Agreement (the Second Amendment) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders signatory thereto. The Second Amendment amends the Senior Credit Agreement with respect to the Company's ability to enter into certain commodity hedging agreements.

The Second Amendment provides, among other things, that the Company and its subsidiary guarantors may enter into commodity swap, collar and/or call option agreements with approved counterparties so long as the volumes for such agreements do not exceed 85% of the Company's internally forecasted production (i) from the Company's crude oil, natural gas liquids and natural gas, or (ii) in the case of a proposed acquisition of oil and gas properties, from such oil and gas properties that are the subject of such proposed acquisition, in each case for the 24 months following the date such agreement is entered into. Additionally, the Company may enter into commodity swap, collar and/or call option agreements so long as the volumes for such agreements do not exceed 85% (i) of the reasonably anticipated projected production from the Company's proved reserves (as forecast based upon the most recently delivered reserve report) for the period of 25 to 66 months following the date such agreement is entered into, or (ii) in the case of a proposed acquisition of oil and gas properties, of the reasonably anticipated projected production from proved reserves (as forecast based upon the most recently delivered reserve report) from such oil and gas properties that are the subject of such proposed acquisition for the period of 25 to 48 months following the date such agreement is entered into. The 85% limitations discussed above do not apply to volumes hedged by the Company using puts, floors and/or basis differential swap agreements.

Prior to the Second Amendment, the volumes for commodity swap, collar and/or call option agreements under the Senior Credit Agreement could not exceed 85% of the reasonably anticipated projected production from the Company's proved reserves (as forecast based upon the most recently delivered reserve report), for each month during the period during which the agreement was in effect for each of crude oil, natural gas liquids and natural gas, for the 66 months following the date such agreement was entered into.



# 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.

Estimates of proved reserves at December 31, 2012 were prepared by Netherland, Sewell & Associates, Inc. (Netherland, Sewell), our independent consulting petroleum engineers. Our estimated proved reserves as of December 31, 2011 and 2010 were prepared by Forrest A. Garb & Associates, an independent oil and natural gas reservoir engineering consulting firm. Netherland, Sewell is 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 has been practicing consulting petroleum engineering at Netherland, Sewell since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 27 years of experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton has been practicing consulting petroleum geology at Netherland, Sewell since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 30 years of practical experience in petroleum geosciences, with over 23 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. 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 an independent reserves committee composed of three outside directors, all of whom have experience in energy company reserve evaluations. Our independent engineering firm reports jointly to the reserves committee and to our Manager, 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 accept the report prepared by our independent consulting petroleum engineers. The Manager, Corporate Reserves is the technical person primarily responsible for



overseeing the preparation of the annual reserve report. He holds a Bachelor of Science degree in Mechanical Engineering from The University of Missouri-Rolla and has over 35 years of experience in reservoir engineering, economic modeling and reserve evaluation.

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, 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 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.

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, 2012, 2011 and 2010 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 $94.71 per barrel, $96.19 per barrel and $79.43 per barrel, respectively. The oil and natural gas liquids prices were adjusted by lease or field for quality, transportation fees, and regional price differentials. The natural gas prices as of December 31, 2012, 2011 and 2010 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 $2.76 per Mmbtu, $4.12 per Mmbtu and $4.38 per Mmbtu, respectively. All prices are adjusted by lease or field.



for energy content, transportation fees, and regional price 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, 2009</td><td>14,067</td><td>89,227</td><td>4,983</td><td>33,921</td></tr><tr><td>Extensions and discoveries</td><td>347</td><td>821</td><td>61</td><td>545</td></tr><tr><td>Purchase of minerals in place</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Production</td><td>(995)</td><td>(4,816)</td><td>(364)</td><td>(2,162)</td></tr><tr><td>Sale of minerals in place</td><td>(174)</td><td>(14,591)</td><td>(2,004)</td><td>(4,610)</td></tr><tr><td>Revision of previous estimates</td><td>(159)</td><td>(17,033)</td><td>(301)</td><td>(3,299)</td></tr><tr><td>Proved reserves, December 31, 2010</td><td>13,086</td><td>53,608</td><td>2,375</td><td>24,395</td></tr><tr><td>Extensions and discoveries</td><td>339</td><td>20</td><td>1</td><td>343</td></tr><tr><td>Purchase of minerals in place</td><td>5</td><td>—</td><td>—</td><td>5</td></tr><tr><td>Production</td><td>(884)</td><td>(2,662)</td><td>(176)</td><td>(1,504)</td></tr><tr><td>Sale of minerals in place</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Revision of previous estimates</td><td>(175)</td><td>(10,912)</td><td>(190)</td><td>(2,182)</td></tr><tr><td>Proved reserves, December 31, 2011</td><td>12,371</td><td>40,054</td><td>2,010</td><td>21,057</td></tr><tr><td>Extensions and discoveries</td><td>11,691</td><td>6,742</td><td>352</td><td>13,167</td></tr><tr><td>Purchase of minerals in place</td><td>66,240</td><td>71,560</td><td>3,433</td><td>81,600</td></tr><tr><td>Production</td><td>(2,415)</td><td>(4,554)</td><td>(268)</td><td>(3,442)</td></tr><tr><td>Sale of minerals in place</td><td>(1,789)</td><td>(2,025)</td><td>—</td><td>(2,127)</td></tr><tr><td>Revision of previous estimates</td><td>1,280</td><td>(15,632)</td><td>(144)</td><td>(1,470)</td></tr><tr><td>Proved reserves, December 31, 2012</td><td>87,378</td><td>96,145</td><td>5,383</td><td>108,785</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, 2012</td><td>38,429</td><td>58,785</td><td>3,172</td><td>51,399</td></tr><tr><td>December 31, 2011</td><td>8,643</td><td>20,997</td><td>1,237</td><td>13,381</td></tr></table>



<table><tr><td colspan="5">Proved Undeveloped Reserves</td></tr><tr><td></td><td>Oil (MBbls)</td><td>Natural Gas (Mmcf)</td><td>Natural Gas Liquids (MBbls)</td><td>Equivalent (MBoe)</td></tr><tr><td>December 31, 2010</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>48,949</td><td>37,360</td><td>2,211</td><td>57,386</td></tr><tr><td>December 31, 2012</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>3,728</td><td>19,057</td><td>773</td><td>7,676</td></tr><tr><td>December 31, 2011</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>4,672</td><td>21,832</td><td>889</td><td>9,199</td></tr></table>

During 2012, through several transactions, the Company acquired 81.6 million barrels of oil equivalent in proved reserves primarily in the Bakken / Three Forks area and Woodbine / Eagle Ford area. As a result of the Company's active development programs in these areas, the Company added 13.2 million barrels of oil equivalent. In 2012, the Company had one divestiture of 2.1 million barrels of oil equivalent in its non-core area. The small negative revision of 1.5 million barrels of oil equivalent comes mostly from the Company's non-core areas and is due to lower gas prices, well performance changes and expiring proved undeveloped locations.



The Company added 0.3 million Boe in proved reserve extensions and discoveries in 2011 primarily as a result of its development drilling in its Electra/Burkburnett Field in North Texas and in its La Copita Field in South Texas. A significant portion of these reserves is a result of drilling locations in Electra/Burkburnett, Northeast Fitts and Allen Fields that were not booked as proved locations as of December 31, 2010. The revisions of previous reserve estimates in 2011 decreased proved reserves by 2.2 million Boe or approximately 9% of proved reserves at the beginning of the year. The revisions include a positive increase of 0.9 million Boe or 4% of the beginning of the year proved reserves caused by higher crude oil and natural gas prices. This positive revision was offset by the downward revision of 1.4 million barrels of oil equivalent caused by the transfer of proved reserves to unproved categories as a result of updated geological and engineering evaluations and changes to the Company development plans during 2011, and 1.7 million Boe of downward revisions were mostly due to changes in well performance.

The Company added 0.5 million Boe in proved reserve extensions and discoveries in 2010 as a result of development drilling in its Electra/Burkburnett Field in North Texas and in its La Copita Field in South Texas. A significant portion of these reserves is a result of drilling locations in its Electra/Burkburnett Field that were not booked as proved location at year-end 2009. The remainder of the extensions and discoveries in 2010 is primarily from wells drilled in South Texas not previously booked as proved and from a discovery well in Osage County, Oklahoma. Sales of reserves in place during 2010 were primarily due to sales of assets during December 2010 of the Company's North Texas Barnett Shale and Boonsville properties and certain non-operated natural gas properties located in eastern Oklahoma. The revisions of previous reserve estimates decreased proved reserves by 3.3 million Boe or approximately 10% of proved reserves at the beginning of the year. The revisions included a positive increase of 1.8 million Boe caused by higher oil and gas prices. This positive revision was offset by a downward revision of 1.1 million Boe caused by the transfer of proved undeveloped to unproved categories as a result of changes to the Company's development plans during 2010, and 4.0 million Boe of the downward revisions were mostly due to changes in well performance in the Company's gas properties in South Texas.

The Company's reserves have been estimated using deterministic methods. The total proved reserve additions of 87,728 Mboe are comprised of 38,018 Mboe in proved developed and 49,710 Mboe in proved undeveloped reserves, and are primarily from the Bakken / Three Forks area and the Woodbine / Eagle Ford area, driven by the Merger and the acquisitions of the East Texas Assets and the Williston Basin Assets.

At December 31, 2012, our estimated proved undeveloped (PUD) reserves were approximately 57.4 MMBoe, a 49.7 MMBoe net increase over the previous year's estimate of 7.7 MMBoe. The increase is largely due to acquisitions totaling 42.9 MMBoe of undeveloped reserves primarily in the Bakken/Three Forks and Woodbine/Eagle Ford areas. As of December 31, 2012, more than 97% of our PUD reserves are less than five years old. The following details the changes in proved undeveloped reserves for 2012 (MBoE):

<table><tr><td>Beginning proved undeveloped reserves at December 31, 2011</td><td>7,676</td></tr><tr><td>Undeveloped reserves transferred to developed</td><td>(4,285)</td></tr><tr><td>Revisions</td><td>2,879</td></tr><tr><td>Purchases</td><td>42,926</td></tr><tr><td>Divestitures</td><td>(466)</td></tr><tr><td>Extensions and discoveries</td><td>8,656</td></tr><tr><td>Ending proved undeveloped reserves at December 31, 2012</td><td>57,386</td></tr></table>

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. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Reliable technologies were used to determine areas where proved undeveloped (PUD) locations are more than one offset 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. 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.

<table><tr><td rowspan="3"></td><td colspan="4">December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td colspan="4">(In thousands)</td></tr><tr><td>Evaluated oil and natural gas properties(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 2,669,245</td><td>$ 715,666</td><td>$ 689,472</td><td></td></tr><tr><td>Unevaluated oil and natural gas properties</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2,326,598</td><td>—</td><td>—</td><td></td></tr><tr><td></td><td>4,995,843</td><td>715,666</td><td>689,472</td><td></td></tr><tr><td>Accumulated depletion, depreciation and amortization(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>(588,207)</td><td>(501,993)</td><td>(482,886)</td><td></td></tr><tr><td></td><td>$ 4,407,636</td><td>$ 213,673</td><td>$ 206,586</td><td></td></tr></table>

(1) Amounts do not include costs for our 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="3"></td><td colspan="4">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td></td></tr><tr><td colspan="4">(In thousands)</td></tr><tr><td>Property acquisition costs, proved/(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 1,495,372</td><td>$ 724</td><td>$ 1,133</td><td></td></tr><tr><td>Property acquisition costs, unproved/(1)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>2,324,439</td><td>—</td><td>—</td><td></td></tr><tr><td>Exploration and extension well costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>232,685</td><td>7,135</td><td>4,552</td><td></td></tr><tr><td>Development costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>254,499</td><td>17,355</td><td>27,850</td><td></td></tr><tr><td>Total costs</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 4,306,995</td><td>$ 25,214</td><td>$ 33,535</td><td></td></tr></table>

(1) Property acquisition costs include preferred stock issued for Williston Basin Assets of $695.2 million, common stock issued for Geo Resources, Inc. of $321.4 million, and common stock issued for East Texas Assets of $130.6 million.

## 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 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 of Discounted Future Net Cash Flows (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, 2012, 2011 and 2010, 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>2012</td><td>2011 (In thousands)</td><td>2010</td></tr><tr><td>Future cash inflows</td><td>$ 8,714,938</td><td>$ 1,440,088</td><td>$ 1,355,233</td></tr><tr><td>Future production costs</td><td>(2,726,382)</td><td>(582,662)</td><td>(548,638)</td></tr><tr><td>Future development costs</td><td>(1,416,967)</td><td>(102,231)</td><td>(117,860)</td></tr><tr><td>Future income tax expense</td><td>(651,070)</td><td>(205,457)</td><td>(161,736)</td></tr><tr><td>Future net cash flows before 10% discount</td><td>3,920,519</td><td>549,738</td><td>526,999</td></tr><tr><td>10% annual discount for estimated timing of cash flows</td><td>(1,966,467)</td><td>(262,849)</td><td>(248,952)</td></tr><tr><td>Standardized measure of discounted future net cash flows</td><td>$ 1,954,052</td><td>$ 286,889</td><td>$ 278,047</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, 2012:

<table><tr><td rowspan="3"></td><td colspan="3">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td></tr><tr><td colspan="3">(In thousands)</td></tr><tr><td>Beginning of year</td><td>$ 286,889</td><td>$ 278,047</td><td>$ 274,234</td></tr><tr><td>Sale of oil and natural gas produced, net of production costs</td><td>(172,971)</td><td>(64,451)</td><td>(71,028)</td></tr><tr><td>Purchase of minerals in place</td><td>1,898,345</td><td>104</td><td>—</td></tr><tr><td>Sales of minerals in place</td><td>(53,452)</td><td>—</td><td>(25,267)</td></tr><tr><td>Extensions and discoveries</td><td>290,668</td><td>24,659</td><td>13,888</td></tr><tr><td>Changes in income taxes, net</td><td>(195,007)</td><td>(18,691)</td><td>(24,382)</td></tr><tr><td>Changes in prices and costs</td><td>(2,985)</td><td>93,411</td><td>131,366</td></tr><tr><td>Previously estimated development costs incurred</td><td>36,142</td><td>11,209</td><td>16,840</td></tr><tr><td>Net changes in future development costs</td><td>(124,483)</td><td>1,940</td><td>(1,184)</td></tr><tr><td>Revisions of previous quantities</td><td>(32,681)</td><td>(49,782)</td><td>(58,029)</td></tr><tr><td>Accretion of discount</td><td>87,075</td><td>36,425</td><td>33,605</td></tr><tr><td>Changes in production rates and other</td><td>(63,488)</td><td>(25,982)</td><td>(11,996)</td></tr><tr><td>End of year</td><td>$ 1,954,052</td><td>$ 286,889</td><td>$ 278,047</td></tr></table>






## SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

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.

<table><tr><td rowspan="3"></td><td colspan="5">Quarters Ended</td></tr><tr><td>March 31</td><td>June 30</td><td>September 30</td><td>December 31</td><td></td></tr><tr><td colspan="5">(In thousands, except per share amounts)</td></tr><tr><td>2012</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total operating revenues</td><td>$ 26,870</td><td>$ 23,281</td><td>$ 73,140</td><td>$ 124,654</td><td></td></tr><tr><td>Income (loss) from operations</td><td>(9,785)</td><td>(7,220)</td><td>(4,569)</td><td>(8,143)</td><td></td></tr><tr><td>Net income (loss)</td><td>(33,322)</td><td>7,659</td><td>(20,181)</td><td>(8,041)</td><td></td></tr><tr><td>Net income (loss) available to common stockholders</td><td>(34,424)</td><td>(79,684)</td><td>(20,181)</td><td>(8,041)</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>$ (0.50)</td><td>$ (0.59)</td><td>$ (0.11)</td><td>$ (0.04)</td><td></td></tr><tr><td>Diluted</td><td>$ (0.50)</td><td>$ (0.59)</td><td>$ (0.11)</td><td>$ (0.04)</td><td></td></tr><tr><td></td><td colspan="5">Quarters Ended</td></tr><tr><td></td><td>March 31</td><td>June 30</td><td>September 30</td><td>December 31</td><td></td></tr><tr><td>2011</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total operating revenues</td><td>$ 25,770</td><td>$ 28,152</td><td>$ 24,186</td><td>$ 25,581</td><td></td></tr><tr><td>Income (loss) from operations</td><td>5,762</td><td>8,271</td><td>5,730</td><td>36</td><td></td></tr><tr><td>Net income (loss)</td><td>(9,911)</td><td>8,936</td><td>11,776</td><td>(12,204)</td><td></td></tr><tr><td>Net income (loss) available to common stockholders</td><td>(9,911)</td><td>8,936</td><td>11,776</td><td>(12,204)</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>$ (0.38)</td><td>$ 0.34</td><td>$ 0.45</td><td>$ (0.46)</td><td></td></tr><tr><td>Diluted</td><td>$ (0.38)</td><td>$ 0.34</td><td>$ 0.45</td><td>$ (0.46)</td><td></td></tr></table>



## ITEM9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As previously reported on Form 8-K filed with the SEC on April 4, 2012 (the "prior 8-K"), on April 3, 2012, we dismissed our prior independent registered public accounting firm and appointed Deloitte & Touche LLP as our independent registered public accounting firm for the 2012 fiscal year. For more information, please refer to the prior 8-K.

## ITEM9A. 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 as of the end of the period covered by this report. In conducting our evaluation of the effectiveness of internal control over financial reporting, we excluded the Merger, which was completed on August 1, 2012. The total assets constitute approximately $1.3 billion, or 26% of our consolidated assets at December 31, 2012, and total revenues for the period from the August 1, 2012 closing date until December 31, 2012 of $90.8 million, or 37% of consolidated revenues for the year ended December 31, 2012. We expect to first include GeoResources in our annual assessment for the year ended December 31, 2013, as permitted for recently acquired businesses. 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, 2012 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, 2012. 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

## ITEM9B. OTHER INFORMATION

None.



## PART III

## ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.

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 internet 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 internet website. The waiver information will remain on the website for at least twelve months after the initial disclosure of such waiver.

## ITEM 11. EXECUTIVE COMPENSATION

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.

## ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

## Equity Compensation Plan Information

The following table sets forth certain information as of December 31, 2012 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(i)</td><td>5,079,733(2)\(</td><td>7.22</td><td>4,400,051</td></tr><tr><td>Equity compensation plans not approved by security holders</td><td>—</td><td>—</td><td>—</td></tr><tr><td></td><td>5,079,733(2)\(</td><td>7.22</td><td>4,400,051</td></tr></table>

(1) Represents information for the 2012 Long-Term Incentive Plan.

(2) Includes 267,900 shares of restricted stock not yet vested.

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.



## ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.

## ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders.



## 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 Securities Purchase Agreement dated December 21, 2011 by and between RAM Energy Resources, Inc. and Halcón Resources LLC (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed December 22, 2011).

2.1.1 First Amendment to Securities Purchase Agreement dated January 4, 2012 by and between RAM Energy Resources, Inc. and Halcón Resources LLC (Incorporated by reference to Exhibit 2.1.1 of our Current Report on Form 8-K filed January 5, 2012).

2.2 Agreement and Plan of Merger, dated as of April 24, 2012 by and among Halcón Resources Corporation, Leopard Sub I, Inc., Leopard Sub II, LLC and GeoResources, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed April 25, 2012).

2.3 Agreement of Sale and Purchase dated May 8, 2012 between NCL Appalachian Partners, L.P., as Seller, and Halcón Energy Properties, Inc., as Buyer (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed July 2, 2012).

2.4 Purchase and Sale Agreement dated as of the 5th day of June, 2012, among CH4 Energy II, LLC, PetroMax Leon, LLC and Petro Texas LLC and Halcón Energy Properties, Inc., and joined by PetroMax Operating Co., Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed August 7, 2012).

2.5 Reorganization and Interest Purchase Agreement dated October 19, 2012 by and among Halcón Energy Properties, Inc., Petro-Hunt, L.L.C. and Pillar Energy, LLC (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed October 22, 2012).

3.1 Amended and Restated Certificate of Incorporation of RAM Energy Resources, Inc. dated February 8, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed February 9, 2012).

3.1.1 Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Halcón Resources Corporation, effective as of February 10, 2012 (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed February 9, 2012).

3.1.2 Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated March 2, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed March 5, 2012).



3.1.3 Certificate of Elimination of 8% Automatically Convertible Preferred Stock dated November 30, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 4, 2012).

3.1.4 Certificate of Designation, Preferences, Rights and Limitations of 8% Automatically Convertible Preferred Stock of Halcón Resources Corporation dated December 5, 2012 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed December 11, 2012).

3.2 Fourth Amended and Restated Bylaws of Halcón Resources Corporation (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed November 6, 2012).

4.1 Convertible Promissory Note dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed February 9, 2012).

4.2 Warrant Certificate dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed February 9, 2012).

4.3 Registration Rights Agreement dated February 8, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed February 9, 2012).

4.4 Indenture dated as of July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 9.75% Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed July 17, 2012).

4.5 Registration Rights Agreement dated July 16, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed July 17, 2012).

4.6 First Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 2, 2012).

4.7 Second Supplemental Indenture dated as of August 1, 2012, by and among Halcón Resources Corporation, the parties named therein as subsidiary guarantors, and U.S. Bank National Association, as Trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed August 2, 2012).

4.8 Registration Rights Agreement dated as of August 1, 2012, among CH4 Energy II, LLC, PetroMax Leon, LLC and Petro Texas LLC and Halcón Resources Corporation (subsequently joined by U.S. King King LLC) (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed August 7, 2012).

4.9 Registration Rights Agreement dated March 5, 2012, between Halcón Resources Corporation and Barclays Capital, Inc. as lead placement agent for the benefit of the initial holders named therein (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed March 5, 2012).



4.10 Registration Rights Agreement dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein, and the initial purchaser named therein (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed November 7, 2012).

4.11 Indenture dated as of November 6, 2012, among Halcón Resources Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee, relating to Halcón Resources Corporation's 8.875% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed November 7, 2012).

4.12 First Supplemental Indenture dated December 6, 2012, among Halcón Williston I, LLC and Halcón Williston II, LLC, the existing guarantors, Halcón Resources Corporation, the parties named therein as subsidiary guarantors and U.S. Bank National Association, as trustee, relating to the 9.75% senior notes due 2020 (Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K filed December 11, 2012).

4.13 Third Supplemental Indenture dated December 6, 2012, among Halcón Resources Corporation and U.S. Bank National Association, as Trustee, relating to the 8.875% senior notes due 2021 (Incorporated by reference to Exhibit 4.4 of our Current Report on Form 8-K filed December 11, 2012).

4.14 First Amendment to Registration Rights Agreement dated December 6, 2012, between Halcón Resources Corporation and HALRES LLC (formerly Halcón Resources LLC) (Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed December 11, 2012).

10.1 \( ^{†} \)  Employment Agreement between Registrant and Larry E. Lee dated May 8, 2006 (Incorporated by reference to Exhibit 10.15 of our Current Report on Form 8-K filed May 12, 2006).

10.1.1 \( ^{†} \)  First Amendment to Employment Agreement between Registrant and Larry E. Lee dated October 18, 2006 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 5, 2006).

10.1.2 \( ^{†} \)  Second Amendment to Employment Agreement of Larry E. Lee dated February 25, 2008 (Incorporated by reference to Exhibit 10.6.2 of our Current Report on Form 8-K filed February 26, 2008).

10.1.3 \( ^{†} \)  Third Amendment to Employment Agreement of Larry E. Lee dated December 30, 2008 (Incorporated by reference to Exhibit 10.6.3 of our Current Report on Form 8-K filed January 5, 2009).

10.1.4 \( ^{†} \)  Fourth Amendment to Employment Agreement of Larry E. Lee dated March 24, 2009 (Incorporated by reference to Exhibit 10.6.4 of our Current Report on Form 8-K filed March 25, 2009).

10.1.5 \( ^{†} \)  Fifth Amendment to Employment Agreement of Larry E. Lee dated March 17, 2010 (Incorporated by reference to Exhibit 10.6.5 of our Current Report on Form 8-K filed March 18, 2010).

10.1.6 \( ^{†} \)  Sixth Amendment to Employment Agreement of Larry E. Lee dated March 8, 2011 (Incorporated by reference to Exhibit 10.6.6 of our Current Report on Form 8-K filed March 10, 2011).



10.2 Senior Revolving Credit Agreement dated as of February 8, 2012, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 9, 2012).

10.3 Guarantee and Collateral Agreement dated as of February 8, 2012, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed February 9, 2012).

10.4 Compensation Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 8, 2012).

10.5 Stock Ownership Guidelines Policy (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed March 8, 2012).

10.6 Form of Indemnity Agreement (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 13, 2012).

10.7 Voting Agreement dated as of April 24, 2012 by and between GeoResources, Inc. and HALRES LLC (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed April 25, 2012).

10.8 Voting Agreement dated as of April 24, 2012 by and among Halcón Resources Corporation, Leopard Sub I, Inc. and each of the stockholders party thereto (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed April 25, 2012).

10.9 Confidential Information, Non-Competition and Non-Solicit Agreement dated as of April 24, 2012 by and between Halcón Resources Corporation and Frank A. Lodzinski (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed April 25, 2012).

10.10 \( ^{\dagger} \)  Halcón Resources Corporation 2012 Long-Term Incentive Plan effective May 17, 2012 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 22, 2012).

10.11 \( ^{\dagger} \)  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).

10.12 \( ^{\dagger} \)  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).

10.13 \( ^{\dagger} \)  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).

10.14 \( ^{\dagger} \)  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).

10.15 \( ^{\dagger} \)  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).

10.16 \( ^{\dagger} \)  Form of Stock Option Award Agreement (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed June 13, 2012).



10.17† Form of Employee Restricted Stock Agreement (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed June 13, 2012).

10.18† Form of Non-Employee Director Restricted Stock Agreement (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed June 13, 2012).

10.19* Purchase Agreement dated June 29, 2012, by and between Halcón Resources Corporation and Wells Fargo Securities, LLC as representative of the initial purchasers named therein relating to Halcón Resources Corporation's 9.75% Senior Notes due 2020.

10.20 Escrow Agreement, dated as of July 16, 2012, by and among Halcón Resources Corporation, U.S. Bank National Association, as trustee under the Indenture, and U.S. Bank National Association, as escrow and paying agent (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed July 17, 2012).

10.21 First Amendment to Senior Revolving Credit Agreement, dated as of August 1, 2012, among Halcón Resources Corporation, as borrower, each of the lenders from time to time party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed August 2, 2012).

10.22† Employment Agreement between Robert J. Anderson and Halcón Resources Corporation dated August 1, 2012 (Incorporated by reference to Exhibit 10.12 of our Quarterly Report on Form 10-Q filed November 8, 2012).

10.23 Common Stock Purchase Agreement dated October 19, 2012, by and between Halcón Resources Corporation and CPP Investment Board PMI-2 Inc. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 22, 2012).

10.24 Purchase Agreement dated October 23, 2012, by and between Halcón Resources Corporation and Wells Fargo Securities, LLC as representative of the initial purchasers named therein relating to Halcón Resources Corporation's 8.875% Senior Notes due 2021 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 26, 2012).

10.25 Escrow Agreement, dated as of November 6, 2012, by and among Halcón Resources Corporation, U.S. Bank National Association, as trustee under the Indenture, and U.S. Bank National Association, as escrow and paying agent (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 7, 2012).

10.26 Stockholders Agreement dated December 6, 2012, between Halcón Resources Corporation and CPP Investment Board PMI-2 Inc. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 11, 2012).

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 UHY LLP

23.3* Consent of Netherland, Sewell & Associates, Inc.

23.4* Consent of Forrest A. Garb & 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.

† 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, 2013

By:

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board and
Chief Executive Officer

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>Chairman of the Board, Chief Executive Officer and Director</td><td>February 28, 2013</td></tr><tr><td>Floyd C. Wilson</td><td></td><td></td></tr><tr><td>/s/ MARK J. MIZE</td><td>Executive Vice President, Chief Financial Officer and Treasurer</td><td>February 28, 2013</td></tr><tr><td>Mark J. Mize</td><td></td><td></td></tr><tr><td>/s/ JOSEPH S. RINANDO, III</td><td>Vice President, Chief Accounting Officer</td><td>February 28, 2013</td></tr><tr><td>Joseph S. Rinando, III</td><td></td><td></td></tr><tr><td>/s/ TUCKER S. BRIDWELL</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>Tucker S. Bridwell</td><td></td><td></td></tr><tr><td>/s/ JAMES W. CHRISTMAS</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>James W. Christmas</td><td></td><td></td></tr><tr><td>/s/ THOMAS R. FULLER</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>Thomas R. Fuller</td><td></td><td></td></tr><tr><td>/s/ KEVIN E. GODWIN</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>Kevin E. Godwin</td><td></td><td></td></tr></table>



<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ DAVID S. HUNT</td><td></td><td></td></tr><tr><td>David S. Hunt</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ JAMES L. IRISH III</td><td></td><td></td></tr><tr><td>James L. Irish III</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ DAVID B. MILLER</td><td></td><td></td></tr><tr><td>David B. Miller</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ DANIEL A. RIOUX</td><td></td><td></td></tr><tr><td>Daniel A. Rioux</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ STEPHEN P. SMILEY</td><td></td><td></td></tr><tr><td>Stephen P. Smiley</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ MICHAEL A. VLASIC</td><td></td><td></td></tr><tr><td>Michael A. Vlasic</td><td>Director</td><td>February 28, 2013</td></tr><tr><td>/s/ MARK A. WELSH IV</td><td></td><td></td></tr><tr><td>Mark A. Welsh IV</td><td>Director</td><td>February 28, 2013</td></tr></table>



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# HALCÓN RESOURCES CORPORATION
9.75% SENIOR NOTES DUE 2020

# PURCHASE AGREEMENT

BARCLAYS CAPITAL INC.

As Representative of the several
Initial Purchasers named in Schedule I attached hereto,

c/o Barclays Capital Inc.
745 Seventh Avenue
New York, New York 10019

Ladies and Gentlemen:

Halcón Resources Corporation, a Delaware corporation (the “Company”), proposes, upon the terms and conditions set forth in this agreement (this “Agreement”), to issue and sell to you, as the initial purchasers (the “Initial Purchasers”), $750,000,000 in aggregate principal amount of its 9.75% Senior Notes due 2020 (the “Notes”). The Notes will (i) have terms and provisions that are summarized in the Offering Memorandum (as defined below), and (ii) are to be issued pursuant to an Indenture (the “Indenture”) to be entered into among the Company, the Guarantors (as defined below) and U.S. Bank Trust National Association, as trustee (the “Trustee”). The Company’s obligations under the Notes, including the due and punctual payment of interest on the Notes, will be irrevocably and unconditionally guaranteed (the “Guarantees”) by the guarantors listed in Schedule II hereto (together the “Guarantors”). As used herein, the term “Notes” shall include the Guarantees, unless the context otherwise requires. This Agreement is to confirm the agreement concerning the purchase of the Notes from the Company by the Initial Purchasers.

1. Purchase and Resale of the Notes. The Notes will be offered and sold to the Initial Purchasers without registration under the Securities Act of 1933, as amended (the “Securities Act”), in reliance on an exemption pursuant to Section 4(2) under the Securities Act. The Company and the Guarantors have prepared a preliminary offering memorandum, dated June 25, 2012 (the “Preliminary Offering Memorandum”), a pricing term sheet substantially in the form attached hereto as Schedule III (the “Pricing Term Sheet”) setting forth the terms of the Notes omitted from the Preliminary Offering Memorandum and certain other information and an offering memorandum, dated June 29, 2012 (the “Offering Memorandum”), setting forth information regarding the Company, the Guarantors, the Notes and the Exchange Notes (as defined herein) and the Guarantees and the Exchange Guarantees (as defined herein). The

Preliminary Offering Memorandum, as supplemented and amended as of the Applicable Time (as defined below), together with the Pricing Term Sheet and any of the documents listed on Schedule IV(A) hereto are collectively referred to as the “Pricing Disclosure Package”. The Company and the Guarantors hereby confirm that they have authorized the use of the Pricing Disclosure Package and the Offering Memorandum in connection with the offering and resale of the Notes by the Initial Purchasers. “Applicable Time” means 3:00 p.m. (New York City time) on the date of this Agreement.

Any reference to the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum shall be deemed to refer to and include each of the Company’s and GeoResources’ most recent Annual Report on Form 10-K and all subsequent documents filed with the United States Securities and Exchange Commission (the “Commission”) pursuant to Section 13(a), 13(c) or 15(d) of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), on or prior to the date of the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum, as the case may be that are incorporated by reference therein. Any reference to the Preliminary Offering Memorandum, Pricing Disclosure Package or the Offering Memorandum, as the case may be, as amended or supplemented, as of any specified date, shall be deemed to include any documents filed with the Commission by the Company pursuant to Section 13(a), 13(c) or 15(d) of the Exchange Act after the date of the Preliminary Offering Memorandum, Pricing Disclosure Package or the Offering Memorandum, as the case may be, and prior to such specified date. All documents filed under the Exchange Act that are incorporated by reference therein shall be deemed to be included in the Preliminary Offering Memorandum, Pricing Disclosure Package or the Offering Memorandum, as the case may be, or any amendment or supplement thereto are hereinafter called the “Exchange Act Reports.”

You have advised the Company that you will offer and resell (the “Exempt Resales”) the Notes purchased by you hereunder on the terms set forth in each of the Pricing Disclosure Package and the Offering Memorandum, as amended or supplemented, solely to (i) persons whom you reasonably believe to be “qualified institutional buyers” as defined in Rule 144A under the Securities Act (“QIBs”), and (ii) outside the United States to certain persons who are not U.S. Persons (as defined in Regulation S under the Securities Act (“Regulation S”)) (such persons, “Non-U.S. Persons”) in offshore transactions in reliance on Regulation S. As used herein, the terms “offshore transaction” and “United States” have the meanings assigned to them in Regulation S. Those persons specified in clauses (i) and (ii) are referred to herein as “Eligible Purchasers.”

The Notes are being issued to finance a portion of the consideration for the acquisition of all the issued and outstanding shares of GeoResources, Inc. (“GeoResources”) common stock pursuant to the Merger Agreement (the “Merger Agreement”) between the Company and GeoResources, effective April 24, 2012 which provides, among other things, for the merger of GeoResources with a wholly-owned subsidiary of the Company (the “GeoResources Merger”). On or prior to the Closing Date, the Company and U.S. Bank Trust National Association, as escrow agent (the “Escrow Agent”) will execute an escrow agreement, in form and substance to be agreed between the Escrow Agent, the Trustee and the Initial Purchasers, which shall conform in all material



respects with the description thereof included in the Pricing Disclosure Package and the Offering Memorandum (the “Escrow Agreement”), and will direct the deposit in an

escrow account (the “Escrow Account”) with the Escrow Agent, of the aggregate purchase price of the Notes. The Escrow Agreement shall provide that the escrowed funds shall only be released and paid out pursuant to the terms of the Escrow Agreement.

In addition, immediately following the consummation of the GeoResources Merger, the Representative and each entity acquired in the GeoResources Merger that will become a Guarantor under the Indenture pursuant to the terms thereof (the “Acquired Guarantors”) shall execute and deliver a joinder agreement in the form attached hereto as Exhibit A (the “Joinder Agreement”) whereby each such Acquired Guarantor will agree to observe and fully perform all of the rights, obligations and liabilities contemplated herein as if it were an original signatory hereto.

Holders (including subsequent transferees) of the Notes will have the registration rights set forth in the registration rights agreement in a form satisfactory to the Initial Purchasers (the “Registration Rights Agreement”) between the Company, the Guarantors and the Initial Purchasers to be dated the Closing Date (as defined herein), for so long as such Notes constitute “Transfer Restricted Securities” (as defined in the Registration Rights Agreement). Pursuant to the Registration Rights Agreement, the Company and the Guarantors will agree to file with the Commission under the circumstances set forth therein, a registration statement under the Securities Act relating to the Company’s 9.75% Senior Notes due 2020 (the “Exchange Notes”) and the Guarantors’ Exchange Guarantees (the “Exchange Guarantees” to be offered in exchange for the Notes and the Guarantees. Such portion of the offering is referred to as the “Exchange Offer”.

2.

(A) Representations, Warranties and Agreements of the Company and the Guarantors. The Company and each of the Guarantors, jointly and severally, represent, warrant and agree as follows:

(a) When the Notes and Guarantees are issued and delivered pursuant to this Agreement, such Notes and Guarantees will not be of the same class (within the meaning of Rule 144A under the Securities Act) as securities of the Company or the Guarantors that are listed on a national securities exchange registered under Section 6 of the Exchange Act or that are quoted in a United States automated inter-dealer quotation system.

(b) Neither the Company nor any subsidiary of the Company is or, after giving effect to the offer and sale of the Notes and the application of the proceeds therefrom as described under “Use of Proceeds” in each of the Pricing Disclosure Package and the Offering Memorandum, will be an “investment company” or a company “controlled” by an “investment company” within the meaning of the Investment Company Act of 1940, as amended, and the rules and regulations of the Commission thereunder.

(c) Assuming the accuracy of your representations and warranties in Section 3(b), the purchase and resale of the Notes pursuant hereto (including pursuant to the Exempt Resales) are exempt from the registration requirements of the Securities Act. No form of general solicitation or general advertising within the meaning of Regulation D (including, but not limited

to, advertisements, articles, notices or other communications published in any newspaper, magazine or similar medium or broadcast over television or radio, or any seminar or meeting whose attendees have been invited by any general solicitation or general advertising) was used by the Company, the Guarantors, or any person acting on behalf of the Company or the Guarantors (other than you, as to whom the Company and the Guarantors make no representation) in connection with the offer and sale of the Notes.

(d) No directed selling efforts within the meaning of Rule 902 under the Securities Act were used by the Company, the Guarantors, any affiliate of the Company or the Guarantors or any person acting on behalf of the Company or the Guarantors (other than you, as to whom the Company and the Guarantors make no representation) with respect to Notes sold outside the United States to Non-U.S. Persons, and the Company and any person acting on its behalf (other than you, as to whom the Company and the Guarantors make no representation) has complied with and will implement the “offering restrictions” required by Rule 902 under the Securities Act.

(e) Each of the Preliminary Offering Memorandum, the Pricing Disclosure Package and the Offering Memorandum, each as of its respective date, contains all the information specified in, and meeting the requirements of, Rule 144A(d)(4) under the Securities Act.

(f) The Preliminary Offering Memorandum, the Pricing Disclosure Package and the Offering Memorandum have been prepared by the Company and the Guarantors for use by the Initial Purchasers in connection with the Exempt Resales. No order or decree preventing the use of the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum, or any order asserting that the transactions contemplated by this Agreement are subject to the registration requirements of the Securities Act has been issued, and no proceeding for that purpose has commenced or is pending or, to the knowledge of the Company or any of the Guarantors is contemplated.

(g) The Pricing Disclosure Package did not, as of the Applicable Time, and will not, as of the Closing Date, contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Pricing Disclosure Package in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Initial Purchaser specifically for inclusion therein, which information is specified in Section 8(e).

(h) The Offering Memorandum will not, as of its date or as of the Closing Date, contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Offering Memorandum in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Initial Purchaser specifically for inclusion therein, which information is specified in Section 8(e).



information furnished to the Company through the Representatives by or on behalf of any Initial Purchaser specifically for inclusion therein, which information is specified in Section 8(e).

(i) Neither the Company nor any Guarantor has made any offer to sell or solicitation of an offer to buy the Notes that would constitute a “free writing prospectus” (if the offering of the Notes was made pursuant to a registered offering under the Securities Act), as defined in Rule 405 under the Securities Act (a “Free Writing Offering Document”) without the prior consent of the Representatives; any such Free Writing Offering Document the use of which has been previously consented to by the Initial Purchasers is listed on Schedule IV.

(j) The Pricing Disclosure Package, when taken together with each Free Writing Offering Document listed in Schedule IV(B) hereto, did not, as of the Applicable Time, and will not, as of the Closing Date, contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Pricing Disclosure Package (or Free Writing Offering Document listed in Schedule IV(B) hereto) in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Initial Purchaser specifically for inclusion therein, which information is specified in Section 8(e).

(k) The Company’s Exchange Act Reports, when they were or are filed with the Commission, conformed or will conform in all material respects to the applicable requirements of the Exchange Act and the applicable rules and regulations of the Commission thereunder. The Company’s Exchange Act Reports did not and will not, when filed with the Commission, contain an untrue statement of material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

(l) The statistical and market-related data relating to the Company included in the Pricing Disclosure Package and the Offering Memorandum and the consolidated financial statements of the Company and its subsidiaries and the financial statements of the East Texas Assets included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum are based on or derived from sources that the Company believes to be reliable in all material respects.

(m) The Company has been duly incorporated, is validly existing and is in good standing under the laws of State of Delaware, with corporate power and authority to own, lease and operate its properties and conduct its business as described in the Pricing Disclosure Package and the Offering Memorandum; the Company is duly qualified as a foreign corporation to transact business and is in good standing in each other jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure to qualify or to be in good standing would not have a material adverse effect on the business, properties, prospects, financial condition, stockholders' equity or results of operations of the Company and its subsidiaries taken as a whole (a "Material Adverse Effect"); each subsidiary of the Company other than those subsidiaries which would not, individually or in the aggregate, constitute a "significant subsidiary" as defined in Item 1-02(w) of Regulation S-X (each such "significant subsidiary," a "Subsidiary") is a corporation, partnership, limited liability company or business trust duly incorporated or organized, validly existing and in good standing under the laws of the jurisdiction of its incorporation or

organization, with the requisite entity power and authority to own, lease and operate its properties. The Company does not own or control, directly or indirectly, any corporation, association or other corporate entity that, individually or in the aggregate would constitute a Subsidiary, other than the subsidiaries listed on Schedule II hereof. On a consolidated basis, the Company and its subsidiaries conduct their business as described in the Preliminary Offering Memorandum and the Pricing Disclosure Package and each Subsidiary is duly qualified as a foreign corporation, partnership, limited liability company, business trust or other organization to transact business and is in good standing in each jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure to qualify or to be in good standing would not result in a Material Adverse Effect.

(n) The Company has the authorized equity capitalization as set forth in the Preliminary Offering Memorandum and the Pricing Disclosure Package, and all of the issued and outstanding shares of capital stock of the Company have been duly authorized and validly issued and are fully paid and non-assessable. Except as otherwise disclosed in the Preliminary Offering Memorandum and the Pricing Disclosure Package, all of the issued and outstanding capital stock or other ownership interests of each subsidiary of the Company (i) have been duly authorized and validly issued, (ii) are fully paid and non-assessable and (iii) are owned by the Company directly or through subsidiaries, free and clear of any security interest, mortgage, pledge, lien, encumbrance, claim or equity except as described in the Preliminary Offering Memorandum and the Pricing Disclosure Package and except for such security interests, mortgages, pledges, liens, encumbrances, claims or equities that would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

(o) The Company and each Guarantor has all requisite corporate power, partnership or limited liability company and authority, as applicable, to execute, deliver and perform its obligations under the Indenture. The Indenture has been duly and validly authorized by the Company and the Guarantors, and upon its execution and delivery and, assuming due authorization, execution and delivery by the Trustee, will constitute the valid and binding agreement of the Company and the Guarantors, enforceable against the Company and the Guarantors in accordance with its terms, except as such enforceability may be limited by bankruptcy, fraudulent conveyance, insolvency, reorganization, moratorium, and other laws relating to or affecting creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). No qualification of the Indenture under the Trust Indenture Act of 1939 (the "Trust Indenture Act") is required in connection with the offer and sale of the Notes contemplated hereby or in connection with the Exempt Resales. The Indenture will conform to the description thereof in each of the Pricing Disclosure Package and the Offering Memorandum.

(p) The Company has all requisite corporate power and authority to execute, issue, sell and perform its obligations under the Notes. The Notes have been duly authorized by the Company and, when duly executed by the Company in accordance with the terms of the Indenture, assuming due authentication of the Notes by the Trustee, upon delivery to the Initial Purchasers against payment therefor in accordance with the terms hereof, will be validly issued and delivered and will constitute valid and binding obligations of the Company entitled to the benefits of the Indenture, enforceable against the Company in accordance with their terms,



except as such enforceability may be limited by bankruptcy, fraudulent conveyance, insolvency, reorganization, moratorium, and other laws relating to or affecting creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). The Notes will conform in all material respects to the description thereof in each of the Pricing Disclosure Package and the Offering Memorandum.

(q) The Company has all requisite corporate power and authority to execute, issue and perform its obligations under the Exchange Notes. The Exchange Notes have been duly and validly authorized by the Company and if and when issued and authenticated in accordance with the terms of the Indenture and delivered in accordance with the Exchange Offer provided for in the Registration Rights Agreement, will be validly issued and delivered and will constitute valid and binding obligations of the Company entitled to the benefits of the Indenture, enforceable against the Company in accordance with their terms, except as such enforceability may be limited by bankruptcy, fraudulent conveyance, insolvency, reorganization, moratorium, and other laws relating to or affecting creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(r) Each Guarantor has all requisite corporate, partnership or limited liability company power and authority, as applicable, to execute, issue and perform its obligations under the Guarantees. The Guarantees have been duly and validly authorized by the Guarantors and when the Indenture is duly executed and delivered by the Guarantors in accordance with its terms and upon the due execution, authentication and delivery of the Notes in accordance with the Indenture and the issuance of the Notes in the sale to the Initial Purchasers contemplated by this Agreement, will constitute valid and binding obligations of the Guarantors, enforceable against the Guarantors in accordance with their terms, except as such enforceable may be limited by bankruptcy, fraudulent conveyance, insolvency, reorganization, moratorium, and other laws relating to or affecting creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). The Guarantees will conform in all material respects to the description thereof in each of the Pricing Disclosure Package and the Offering Memorandum.

(s) Each Guarantor has all requisite corporate, partnership or limited liability company power and authority, as applicable, to execute, issue and perform its obligations under the Exchange Guarantees. The Exchange Guarantees have been duly and validly authorized by the Guarantors and if and when executed and delivered by the Guarantors in accordance with the terms of the Indenture and upon the due execution and authentication of the Exchange Notes in accordance with the Indenture and the issuance and delivery of the Exchange Notes in the Exchange Offer contemplated by the Registration Rights Agreement, will be validly issued and delivered and will constitute valid and binding obligations of the Guarantors entitled to the benefits of the Indenture, enforceable against the Guarantors in accordance with their terms, except as such enforceable may be limited by bankruptcy, fraudulent conveyance, insolvency, reorganization, moratorium, and other laws relating to or affecting creditors' rights generally and by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(t) The Company and each Guarantor has all requisite corporate, partnership or limited liability company power and authority, as applicable, to execute, deliver and perform its obligations under the Registration Rights Agreement. The Registration Rights Agreement has been duly authorized by the Company and each Guarantor and, when executed and delivered by the Company and each Guarantor in accordance with the terms hereof and thereof, will be validly executed and delivered (assuming the due authorization, execution and delivery thereof by you) will be the legally valid and binding obligation of the Company and each Guarantor in accordance with the terms thereof, enforceable against the Company and each Guarantor in accordance with its terms, except as such enforceable may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditor's rights generally, by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law) and, as to rights of indemnification and contribution, by principles of public policy. The Registration Rights Agreement will conform in all material respects to the description thereof in each of the Pricing Disclosure Package and the Offering Memorandum.

(u) The Company has all requisite corporate, partnership or limited liability company power and authority, as applicable, to execute, deliver and perform its obligations under the Escrow Agreement. The Escrow Agreement has been duly authorized by the Company and, when executed and delivered by the Company in accordance with the terms hereof and thereof, will be validly executed and delivered and (assuming the due authorization, execution and delivery thereof by the Escrow Agent and the Trustee) will be the legally valid and binding obligation of the Company in accordance with the terms thereof, enforceable against the Company in accordance with its terms, except as such enforceable may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditor's rights generally, by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law). The Escrow Agreement will conform in all material respects to the description thereof in each of the Pricing Disclosure Package and the Offering Memorandum.

(v) Prior to or contemporaneously with the consummation of the GeoResources Merger, the Joinder Agreement will have been duly authorized, executed and delivered by each Acquired Guarantor and, when executed and delivered by such Acquired Guarantors, will be a valid and binding agreement of such Acquired Guarantors, enforceable in accordance with its terms, except as such enforceable may be limited by bankruptcy, insolvency, reorganization, moratorium and other similar laws relating to or affecting creditor's rights generally, by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law).

(w) The Company and each Guarantor has all requisite corporate power to execute, deliver and perform its obligations under this Agreement. This Agreement has been duly and validly authorized, executed and delivered by the Company and each of the Guarantors.

(x) The issue and sale of the Notes and the Guarantees, the execution, delivery and performance by the Company and the Guarantors of the Notes, the Guarantees, the Exchange Notes, the Exchange Guarantees, the Indenture, the Registration Rights Agreement, the Escrow Agreement, the Joinder Agreement and this Agreement, the application of the proceeds from the



sale of the Notes as described under “Use of Proceeds” in each of the Pricing Disclosure Package and the Offering Memorandum, the consummation of the transactions contemplated hereby and thereby and the execution, delivery and performance of the Merger Agreement (assuming the satisfaction of all conditions to closing set forth therein), will not (i) conflict with or result in a breach or violation of any of the terms or provisions of, impose any lien, charge or encumbrance upon any property or assets of the Company, the Guarantors or their respective subsidiaries, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement, license, lease or other agreement or instrument to which the Company, the Guarantors or any of their respective subsidiaries is a party or by which the Company, the Guarantors or any of their respective subsidiaries is bound or to which any of the property or assets of the Company, the Guarantors or any of their respective subsidiaries is subject, (ii) result in any violation of the provisions of the charter or by-laws (or similar organizational documents) of the Company, the Guarantors or any of their respective subsidiaries, or (iii) result in any violation of any statute or any judgment, order, decree, rule or regulation of any court or governmental agency or body having jurisdiction over the Company, the Guarantors or any of their respective subsidiaries or any of their properties or assets, except, with respect to clauses (i) and (iii), conflicts or violations that would not reasonably be expected to have a Material Adverse Effect.

(y) No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental agency or body, domestic or foreign, having jurisdiction over the Company is required for the offering and sale of the Notes or the consummation by the Company of the other transactions contemplated by this Agreement or the Registration Rights Agreement, except for the filing of the registration statement by the Company with the Commission pursuant to the Securities Act, as required by the Registration Rights Agreement, and such consents, approvals, authorizations, orders, registrations, filings or qualifications which shall have been obtained or made prior to the Closing Date as described in this Agreement or as may be required by the securities or blue sky laws of the various states, the Securities Act and the securities laws of any jurisdiction outside the United States in which the Notes are offered.

(z) Except for the Registration Rights Agreement and as disclosed in the Preliminary Offering Memorandum and the Pricing Disclosure Package, there are no contracts, agreements or understandings between the Company, any Guarantor and any person granting such person the right to require the Company or any Guarantor to file a registration statement under the Securities Act with respect to any securities of the Company or any Guarantor owned or to be owned by such person or to require the Company or any Guarantor to include such securities in the securities registered pursuant to the Registration Rights Agreement or in any securities being registered pursuant to any other registration statement filed by the Company or any Guarantor under the Securities Act.

(aa) To the knowledge of the Company, there is no condition under the Merger Agreement that is not expected to be satisfied prior to the Termination Date (as defined in the Merger Agreement).

(bb) To the knowledge of the Company, there is no material breach of any representation under the Merger Agreement by GeoResources.

(cc) Neither the Company, any Guarantor nor any other person acting on behalf of the Company or any Guarantor has sold or issued any securities that would be integrated with the offering of the Notes contemplated by this Agreement pursuant to the Securities Act, the rules and regulations thereunder or the interpretations thereof by the Commission.

(dd) Neither the Company, the Guarantors nor any of their respective subsidiaries has sustained, since the date of the latest audited financial statements included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum, any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, and, since such date, there has not been any change in the capital stock, partnership or limited liability interests, as applicable, or long-term debt, of the Company, the Guarantors or any of their respective subsidiaries or any adverse change, or any development involving a prospective adverse change, in or affecting the business, properties, prospects, financial condition, stockholders' equity or results of operations of the Company and its subsidiaries, taken as a whole, in each case except as could not, in the aggregate, reasonably be expected to have a Material Adverse Effect.

(e) The historical financial statements (including the related notes and supporting schedules) of each of the Company, GeoResources and the East Texas Assets included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum present fairly in all material respects the financial condition, results of operations and cash flows of the entities purported to be shown thereby, at the dates and for the periods indicated, and have been prepared in conformity with accounting principles generally accepted in the United States applied on a consistent basis throughout the periods involved.

(ff) The pro forma financial statements included in the Pricing Disclosure Package and the Offering Memorandum include assumptions that provide a reasonable basis for presenting the significant effects directly attributable to the transactions and events described therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma adjustments reflect the proper application of those adjustments to the historical financial statement amounts in the pro forma financial statements included in the Pricing Disclosure Package. The pro forma financial statements included in the Pricing Disclosure Package have been prepared in accordance with the Commission’s rules and guidance with respect to pro forma financial information. The pro forma financial statements included in the Pricing Disclosure Package and the Offering Memorandum have been prepared on the basis consistent with such historical financial statements, except for the pro forma adjustments specified therein, and include all material adjustments to the historical financial data required by Rule 11-02 of Regulation S-X to reflect the GeoResources Merger and the acquisition of the East Texas Assets (as defined in the Pricing Disclosure Package and the Offering Memorandum) and to give effect to the offering of the Notes, and give effect to assumptions made on a reasonable basis and in good faith and present fairly in all material respects the historical and proposed transactions reflected therein. The other financial information and data included and incorporated by reference in the Offering Memorandum, historical and pro forma, are, in all material respects, accurately presented and prepared on a basis consistent with such financial statements and the books and records of the Company.

(gg) Deloitte & Touche LLP, who have delivered the initial letter referred to in Section 7(f) hereof, are independent registered public accountants as required by the Securities Act and the rules and regulations thereunder and the rules and regulations of the Public Company Accounting



Oversight Board (the “PCAOB”) during the periods covered by the financial statements on which they reported contained in and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum.

(hh) UHY LLP, who have certified certain financial statements of the Company and the East Texas Assets, whose reports appear in the Pricing Disclosure Package and the Offering Memorandum or are incorporated by reference therein and who have delivered the initial letter referred to in Section 7(f) hereof, are independent registered public accountants as required by the Securities Act and the rules and regulations thereunder and the rules and regulations of the PCAOB during the periods covered by the financial statements on which they reported contained in and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum.

(ii) The Company and its subsidiaries have defensible title to all of their interests in oil and gas properties (other than interests earned under farm-out, participation or similar agreements in which an assignment or transfer is pending) and all their interests in other real property and good title to all other properties owned by them, in each case, free and clear of all mortgages, pledges, liens, security interests, claims, restrictions or encumbrances of any kind except such as (i) are described in the Preliminary Offering Memorandum and the Pricing Disclosure Package, (ii) liens and encumbrances under operating agreements, unitization and pooling agreements, production sales contracts, farm-out agreements and other oil and gas exploration participation and production agreements, in each case that secure payment of amounts not yet due and payable for the performance of other unamused obligations and are of a scope and nature customary in the oil and gas industry or arise in connection with drilling and production operations, or (iii) would not have a Material Adverse Effect; except as described in the Preliminary Offering Memorandum or the Pricing Disclosure Package or as would not have a Material Adverse Effect, all of the leases and subleases of real property of the Company or any of its subsidiaries and under which the Company or any of its subsidiaries holds properties described in the Preliminary Offering Memorandum and the Pricing Disclosure Package, are in full force and effect.

(jj) Forrest A. Garb & Associates (the “Company Reservoir Engineer), whose report dated February 7, 2012, is summarized or excerpted in reports incorporated by reference, or included, in the Preliminary Offering Memorandum and the Pricing Disclosure Package, was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to the Company. The written engineering report prepared by the Company Reservoir Engineer dated February 7, 2012 setting forth the proved reserves attributed to the oil and gas properties of the Company and its subsidiaries accurately reflects in all material respects the interests of the Company its subsidiaries in the properties thereon as of December 31, 2011 and was prepared in accordance with the SEC’s rules and regulations relating to the reporting of oil and natural gas reserves; the information furnished by the Company to the Company Reservoir Engineer for purposes of preparing its report, including, without limitation, production, costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true, correct and complete

in all material respects on the date supplied and was prepared in accordance with customary industry practices, as indicated in the letter of the Company Reservoir Engineer dated February 7, 2012. The estimates of proved reserves and related information relating to the East Texas Assets prepared by the Company’s internal reserve engineering staff as of April 1, 2012 accurately reflect in all material respects the interests that the Company expects to acquire therein following closing of such acquisition and were prepared in a manner consistent with the rules and regulations of the SEC relating to the reporting of oil and gas reserves; the information used by the Company’s internal reserve engineers for purposes of preparing such estimates of proved reserves, including, without limitation, production, costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true, correct and complete in all material respects as of the date of such reserves.

(kk) The Company and each of its subsidiaries have such permits, licenses, patents, franchises, certificates of need and other approvals or authorizations of governmental or regulatory authorities (“Permits”) as are necessary under applicable law to own their properties and conduct their businesses in the manner described in the Pricing Disclosure Package and the Offering Memorandum, except for any of the foregoing that could not, in the aggregate, reasonably be expected to have a Material Adverse Effect; each of the Company and its subsidiaries has fulfilled and performed all of its obligations with respect to the Permits, and no event has occurred that allows, or after notice or lapse of time would allow, revocation or termination thereof or results in any other impairment of the rights of the holder or any such Permits, except for any of the foregoing that could not reasonably be expected to have a Material Adverse Effect.

(ll) The Company and each of its subsidiaries own or possess adequate rights to use all material patents, patent applications, trademarks, service marks, trade names, trademark registrations, service mark registrations, copyrights, licenses, know-how, software, systems and technology (including trade secrets and other unpatented and/or unpatentable proprietary or confidential information, systems or procedures) necessary for the conduct of their respective businesses and have no reason to believe that the conduct of their respective businesses will conflict with, and have not received any notice of any claim of conflict with, any such rights of others.

(mm) Other than as set forth in the Preliminary Offering Memorandum and the Pricing Disclosure Package, there are no legal or governmental proceedings pending to which the Company or any of its subsidiaries is a party or of which any property of the Company or any of its subsidiaries is the subject which if determined adversely to the Company, or such subsidiary, would individually or in the aggregate, have a Material Adverse Effect or which would materially and adversely affect the consummation of the transactions contemplated under this Agreement, the Registration Rights Agreement, the Escrow Agreement, the Joinder Agreement, the Merger Agreement or the performance by the Company or any Guarantor of their obligations hereunder or thereunder; and, to the Company’s and the Guarantors’ knowledge, no such proceedings are threatened or contemplated by governmental authorities or threatened by others.

(mn) There are no contracts or other documents that would be required to be described in a registration statement filed under the Securities Act or filed as exhibits to a registration statement of the Company pursuant to Item 601(10) of Regulation S-K that have not

been described in the Pricing Disclosure Package and the Offering Memorandum. The statements made in the Pricing Disclosure Package and the Offering Memorandum, insofar as they purport to constitute summaries of the terms of the contracts and other documents that are so described, constitute accurate summaries of the terms of such contracts and documents in all material respects. Neither the Company, the Guarantors nor any of their respective subsidiaries has knowledge that any other party to any such contract or other document has any intention not to render full performance as contemplated by the terms



(oo) The statements made in the Pricing Disclosure Package and the Offering Memorandum under the captions “Business” (as incorporated by reference from the Company’s Exchange Act Reports), “Certain U.S. Federal Income Tax Considerations” and “Certain ERISA Considerations,” insofar as they purport to constitute summaries of the terms of statutes, rules or regulations, legal or governmental proceedings or contracts and other documents, constitute accurate summaries of the terms of such statutes, rules and regulations, legal and governmental proceedings and contracts and other documents in all material respects.

(pp) No relationship, direct or indirect, that would be required to be described in a registration statement of the Company pursuant to Item 404 of Regulation S-K, exists between or among the Company or any Guarantor and their respective subsidiaries, on the one hand, and the directors, officers, stockholders, customers or suppliers of the Company or any Guarantor and their respective subsidiaries, on the other hand, that has not been described in the Pricing Disclosure Package and the Offering Memorandum.

(qq) No labor disturbance by or dispute with the employees of the Company or any of its subsidiaries exists or, to the knowledge of the Company or any Guarantor, is imminent that could reasonably be expected to have a Material Adverse Effect.

(rt) (i) Each “employee benefit plan” (within the meaning of Section 3(3) of the Employee Retirement Security Act of 1974, as amended (“ERISA”)) for which the Company or any member of its “Controlled Group” (defined as any organization which is a member of a controlled group of corporations within the meaning of Section 414 of the Internal Revenue Code of 1986, as amended (the “Code”)) would have any liability (each a “Plan”) has been maintained in compliance with its terms and with the requirements of all applicable statutes, rules and regulations including ERISA and the Code; (ii) with respect to each Plan subject to Title IV of ERISA (a) no “reportable event” (within the meaning of Section 4043(c) of ERISA) has occurred or is reasonably expected to occur, (b) no “accumulated funding deficiency” (within the meaning of Section 302 of ERISA or Section 412 of the Code), whether or not waived, has occurred or is reasonably expected to occur, (c) the fair market value of the assets under each Plan exceeds the present value of all benefits accrued under such Plan (determined based on those assumptions used to fund such Plan) and (d) neither the Company or any member of its Controlled Group has incurred, or reasonably expects to incur, any liability under Title IV of ERISA (other than contributions to the Plan or premiums to the PBGC in the ordinary course and without default) in respect of a Plan (including a “multiemployer plan”, within the meaning of Section 4001(c)(3) of ERISA); and (iii) each Plan that is intended to be qualified under Section 401(a) of the Code is so qualified and nothing has occurred, whether by action or by failure to act, which would cause the loss of such qualification.

(ss) The Company and each of its subsidiaries has filed all federal, state, local and foreign income and franchise tax returns required to be filed through the date hereof, subject to permitted extensions, and paid all taxes due thereon, and (i) no tax deficiency has been determined adversely to the Company, the Guarantors or any of their respective subsidiaries, nor (ii) does the Company or any Guarantor have any knowledge of any tax deficiencies that could, in the case of clause (i) or (ii) in the aggregate, reasonably be expected to have a Material Adverse Effect.

(t) There are no transfer taxes or other similar fees or charges under Federal law or the laws of any state, or any political subdivision thereof, required to be paid in connection with the execution and delivery of this Agreement or the issuance by the Company or sale by the Company of the Notes.

(uu) Since the date as of which information is given in the Pricing Disclosure Package and the Offering Memorandum and except as may otherwise be described in the Pricing Disclosure Package and the Offering Memorandum, neither the Company nor any Guarantor has (i) incurred any liability or obligation, direct or contingent, other than liabilities and obligations that were incurred in the ordinary course of business, (ii) entered into any material transaction not in the ordinary course of business or (iii) declared or paid any dividend on its capital stock.

(vv) Neither the Company nor any of its subsidiaries (i) is in violation of its charter or by-laws (or similar organizational documents), (ii) is in default, and no event has occurred that, with notice or lapse of time or both, would constitute such a default, in the due performance or observance of any term, covenant, condition or other obligation contained in any indenture, mortgage, deed of trust, loan agreement, license or other agreement or instrument to which it is a party or by which it is bound or to which any of its properties or assets is subject, or (iii) is in violation of any statute or any order, rule or regulation of any court or governmental agency or body having jurisdiction over it or its property or assets or has failed to obtain any license, permit, certificate, franchise or other governmental authorization or permit necessary to the ownership of its property or to the conduct of its business, except in the case of clauses (ii) and (iii), to the extent any such conflict, breach, violation or default could not, in the aggregate, reasonably be expected to have a Material Adverse Effect or would not materially impair the ability of the Company or any Guarantor to perform their obligations under this Agreement or the transactions contemplated by the Merger Agreement.

(wv) Neither the Company nor any of its subsidiaries, nor, to the knowledge of the Company and the Guarantors, any director, officer, agent, employee or other person associated with or acting on behalf of the Company, the Guarantors or any of their respective subsidiaries, has (i) used any corporate funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity; (ii) made any direct or indirect unlawful payment to any foreign or domestic government official or employee from corporate funds; (iii) violated or is in violation of any provision of the Foreign Corrupt Practices Act of 1977; or (iv) made any bribe, rebate, payoff, influence payment, kickback or other unlawful payment.

(xx) The Company and each of its subsidiaries (i) are, and at all times prior hereto were, in compliance with all laws, regulations, ordinances, rules, orders, judgments, decrees, permits or other legal requirements of any governmental authority, including without



obligation concerning the presence, disposal or release of hazardous or toxic substances or wastes, pollutants or contaminants, except in the case of clause (i) or (ii) where such non-compliance, violation, liability, or other obligation could not, in the aggregate, reasonably be expected to have a Material Adverse Effect. Except as described in the Pricing Disclosure Package, (A) there are no proceedings that are pending, or known to be contemplated, against the Company or any of its subsidiaries under Environmental Laws in which a governmental authority is also a party, other than such proceedings regarding which it is reasonably believed no monetary sanctions of $100,000 or more will be imposed, (B) the Company, the Guarantors and their respective subsidiaries are not aware of any issues regarding compliance with Environmental Laws, or liabilities or other obligations under Environmental Laws or concerning hazardous or toxic substances or wastes, pollutants or contaminants, that could reasonably be expected to have a Material Adverse Effect, and (C) none of the Company, the Guarantors, GeoResources and their respective subsidiaries anticipates material capital expenditures other than in the ordinary course of business relating to Environmental Laws.

(yy) None of the transactions contemplated by this Agreement (including, without limitation, the use of the proceeds from the sale of the Notes), will violate or result in a violation of Section 7 of the Exchange Act, or any regulation promulgated thereunder, including, without limitation, Regulations T, U and X of the Board of Governors of the Federal Reserve System.

(zz) The statements contained in the Pricing Disclosure Package and the Preliminary Offering Memorandum under the caption “Description of the Notes,” insofar as they purport to constitute a summary of the terms of the Indenture, the Notes, the Registration Rights Agreement, the Escrow Agreement and the Guarantees and under the captions “Description of Other Indebtedness” and “Plan of Distribution” insofar as they purport to describe the provisions of the documents referred to therein, are accurate in all material respects.

(aaa) The Company and its affiliates have not taken, directly or indirectly, any action designed to or that has constituted or that could reasonably be expected to cause or result in the stabilization or manipulation of the price of any security of the Company or the Guarantors in connection with the offering of the Notes.

(bbb) The Company and each of its subsidiaries maintain a system of internal control over financial reporting (as such term is defined in Rule 13a-15(f) of the Exchange Act) that complies with the requirements of the Exchange Act and that has been designed by, or under the supervision of, the Company’s principal executive and principal financial officers, 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 in the United States. The Company and each of its subsidiaries maintains internal

accounting controls that are sufficient to provide reasonable assurance that (i) transactions are executed in accordance with management’s general or specific authorization, (ii) transactions are recorded as necessary to permit preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States and to maintain accountability for its assets, (iii) access to the Company’s assets is permitted only in accordance with management’s general or specific authorization, and (iv) the recorded accountability for the Company’s assets is compared with existing assets at reasonable intervals and appropriate action is taken with respect to any differences.

(ccc) (i) The Company and each of its subsidiaries have established and maintain disclosure controls and procedures (as such term is defined in Rule 13a-15 under the Exchange Act), (ii) such disclosure controls and procedures are designed to ensure that the information required to be disclosed by the Company in the reports they file or submit under the Exchange Act (assuming the Company was required to file or submit such reports under the Exchange Act) is accumulated and communicated to management of the Company and its subsidiaries, including their respective principal executive officers and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure to be made; and (iii) such disclosure controls and procedures are effective in all material respects to perform the functions for which they were established.

(ddd) Since the date of the most recent balance sheet of the Company and its consolidated subsidiaries audited by UHY LLC and reviewed by the audit committee of the board of directors of the Company, (i) the Company has not been advised of by its auditors, nor has it identified (A) any significant deficiencies in the design or operation of internal controls, that would adversely affect the ability of the Company or any of its subsidiaries to record, process, summarize and report financial data, or any material weaknesses in internal controls, and (B) any fraud, whether or not material, that involves management or other employees who have a significant role in the internal controls of the Company and each of its subsidiaries; and (ii) there have been no changes in internal controls or in other factors that have materially affected or are reasonably likely to materially affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

(eee) No subsidiary of the Company is currently prohibited, directly or indirectly, from paying any dividends to the Company, from making any other distribution on such subsidiary’s capital stock, from repaying to the Company any loans or advances to such subsidiary from the Company or from transferring any of such subsidiary’s property or assets to the Company or any other subsidiary of the Company, except as described in the Pricing Disclosure Package and the Offering Memorandum.

(fff) There is and has been no failure on the part of the Company and any of the Company’s directors or officers, in their capacities as such, to comply with the provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith.

(ggg) The section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” as incorporated by reference from the Company’s Exchange Act Reports in the Pricing Disclosure Package and the Offering Memorandum accurately and fully describes in all material respects

(A) the accounting policies that the Company believed as of the date thereof were the most important in the portrayal of the Company’s financial condition and results of operations and that required management’s most difficult, subjective or complex judgments; (B) the judgments and uncertainties affecting the application of critical accounting policies; and (C) the likelihood that materially different amounts would be reported under different conditions or using different assumptions and an explanation thereof.



(hhh) The operations of the Company and its subsidiaries are and have been conducted at all times in compliance with applicable financial recordkeeping and reporting requirements of the Currency and Foreign Transactions Reporting Act of 1970, as amended, the money laundering statutes of all jurisdictions, the rules and regulations thereunder and any related or similar rules, regulations or guidelines, issued, administered or enforced by any governmental agency (collectively, the "Money Laundering Laws") and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving the Company or any of its subsidiaries with respect to the Money Laundering Laws is pending or, to the knowledge of the Company or any Guarantor, threatened, except, in each case, as would not reasonably be expected to have a Material Adverse Effect.

(iii) Neither the Company nor any of its subsidiaries nor, to the knowledge of the Company or any Guarantor, any director, officer, agent, employee or affiliate of the Company or any of its subsidiaries is currently subject to any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department (“OFAC”); and the Company will not directly or indirectly use the proceeds of the offering, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other person or entity, for the purpose of financing the activities of any person currently subject to any U.S. sanctions administered by OFAC.

(jj) The Company has not taken any action or omitted to take any action (such as issuing any press release relating to any Notes without an appropriate legend) which may result in the loss by any of the Initial Purchasers of the ability to rely on any stabilization safe harbor provided by the Financial Services Authority under the Financial Services and Markets Act 2000 (the “FSMA”). The Company has been informed of the guidance relating to stabilization provided by the Financial Services Authority, in particular in Section MAR 2 Annex 2G of the Financial Services Handbook.

(kkk) Immediately after the consummation of the issuance and sale of the Notes in accordance with the terms of this Agreement and the consummation of the GeoResources Merger, each of the Company and each of the Guarantors will be Solvent. As used in this paragraph, the term “Solvent” means, with respect to a particular date, that on such date (i) the present fair market value (or present fair saleable value) of the assets of the Company and its subsidiaries and the Guarantors and their subsidiaries are not less than the total amount required to pay the probable liabilities of the Company and its subsidiaries and the Guarantors and their subsidiaries on their total existing debts and liabilities (including contingent liabilities) as they become absolute and matured, (ii) the Company and its subsidiaries and the Guarantors and their subsidiaries are able to realize upon their assets and pay their debts and other liabilities, contingent obligations and commitments as they mature and become due in the normal course of business, (iii) assuming the sale of the Notes as contemplated by this Agreement and the

consummation of the GeoResources Merger, the Pricing Disclosure Package and the Offering Memorandum, the Company and its subsidiaries and the Guarantors and their subsidiaries are not incurring debts or liabilities beyond their ability to pay as such debts and liabilities mature and (iv) the Company and its subsidiaries and the Guarantors and their subsidiaries are not engaged in any business or transaction, and are not about to engage in any business or transaction, for which their property would constitute unreasonably small capital after giving due consideration to the prevailing practice in the industry in which the Company and its subsidiaries and the Guarantors and their subsidiaries are engaged. In computing the amount of such contingent liabilities at any time, it is intended that such liabilities will be computed at the amount that, in the light of all the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability.

(III) As of the date hereof, (i) all royalties, rentals, deposits and other amounts owed under the oil and gas leases constituting the oil and gas properties of the Company, the Guarantors and their respective subsidiaries have been properly and timely paid (other than amounts held in suspense accounts pending routine payments or related to disputes about the proper identification of royalty owners), and no amount of proceeds from the sale or production attributable to the oil and gas properties of the Company, the Guarantors and their respective subsidiaries are currently being held in suspense by any purchaser thereof, except where such amounts due could not, individually or in the aggregate, have a Material Adverse Effect, and (ii) there are no claims under take-or-pay contracts pursuant to which natural gas purchasers have any make-up rights affecting the interests of the Company, the Guarantors or their respective subsidiaries in their oil and gas properties, except where such claims could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

(mmm) Neither the Company nor any of its subsidiaries is a party to any contract, agreement or understanding with any person (other than this Agreement) that could give rise to a valid claim against the Initial Purchasers for a brokerage commission, finder's fee or like payment in connection with the offering and sale of the Notes.

(nnn) Neither the Company nor any of its subsidiaries is in violation of or has received notice of any violation with respect to any federal or state law relating to discrimination in the hiring, promotion or pay of employees, nor any applicable federal or state wage and hour laws, the violation of any of which could reasonably be expected to have a Material Adverse Effect.

(ooo) Any certificate signed by any officer of the Company or any Guarantor and delivered to the Representatives or counsel for the Initial Purchasers in connection with the offering of the Notes shall be deemed a representation and warranty by the Company or any such Guarantor, jointly and severally, as to matters covered thereby, to each Initial Purchaser.

(B) Certain Representations, Warranties and Agreements of the Company and the Guarantors with Respect to GeoResources and its Subsidiaries. The Company and each of the Guarantors, jointly and severally, represent, warrant and agree, that to their knowledge after due inquiry of the executive officers of GeoResources:

(a) GeoResources’ Exchange Act Reports, when they were filed with the Commission, conformed in all material respects to the applicable requirements of the Exchange Act and the applicable rules and regulations of the Commission thereunder, and the GeoResources Exchange Act Reports did not, when filed with the Commission, contain an untrue statement of material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.



(b) The statistical and market-related data relating to GeoResources included in the Pricing Disclosure Package and the Offering Memorandum are based on or derived from sources that GeoResources believes to be reliable in all material respects, and the consolidated financial statements of GeoResources and its subsidiaries included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum are based on or derived from sources that GeoResources believes to be reliable in all material respects.

(c) GeoResources has been duly incorporated, is validly existing and is in good standing under the laws of State of Colorado, with corporate power and authority to own, lease and operate its properties and conduct its business as described in the Pricing Disclosure Package and the Offering Memorandum; GeoResources is duly qualified as a foreign corporation to transact business and is in good standing in each other jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure to qualify or to be in good standing would not have a material adverse effect on the business, properties, prospects, financial condition, stockholders' equity or results of operations of the Company and its subsidiaries and GeoResources and its subsidiaries taken as a whole (a "Pro Forma Material Adverse Effect"). Each subsidiary of GeoResources other than those subsidiaries which would not, individually or in the aggregate, constitute a "significant subsidiary" as defined in Item 1-02(w) of Regulation S-X (each such "significant subsidiary," a "GeoResources Subsidiary") is a corporation, partnership, limited liability company or business trust duly incorporated or organized, validly existing and in good standing under the laws of the jurisdiction of its incorporation or organization, with the requisite entity power and authority to own, lease and operate its properties, except where the failure to be duly incorporated or organized, validly existing or to be in good standing would not result in a Pro Forma Material Adverse Effect. GeoResources and its subsidiaries conduct their business as described in the Preliminary Offering Memorandum and the Pricing Disclosure Package and each GeoResources Subsidiary is duly qualified as a foreign corporation, partnership, limited liability company, business trust or other organization to transact business and is in good standing in each jurisdiction in which such qualification is required, whether by reason of the ownership or leasing of property or the conduct of business, except where the failure to qualify or to be in good standing would not result in a Pro Forma Material Adverse Effect.

(d) Grant Thornton LLP, who have certified certain financial statements of GeoResources, whose reports appear in the Pricing Disclosure Package and the Offering Memorandum or are incorporated by reference therein and who have delivered the initial letter referred to in Section 7(f) hereof, are independent registered public accountants of GeoResources as required by the Securities Act and the rules and regulations thereunder and the rules and regulations of the PCAOB during the periods covered by the financial statements on which they

reported contained in and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum

(e) GeoResources and its subsidiaries have defensible title to all of their interests in oil and gas properties (other than interests earned under farm-out, participation or similar agreements in which an assignment or transfer is pending) and all their interests in other real property and good title to all other properties owned by them, in each case, free and clear of all mortgages, pledges, liens, security interests, claims, restrictions or encumbrances of any kind except such as (i) are described in the Preliminary Offering Memorandum and the Pricing Disclosure Package, (ii) liens and encumbrances under operating agreements, unitization and pooling agreements, production sales contracts, farm-out agreements and other oil and gas exploration participation and production agreements, in each case that secure payment of amounts not yet due and payable for the performance of other unmatured obligations and are of a scope and nature customary in the oil and gas industry or arise in connection with drilling and production operations, or (iii) would not have a Pro Forma Material Adverse Effect; except as described in the Preliminary Offering Memorandum or the Pricing Disclosure Package or as would not have a Pro Forma Material Adverse Effect, all of the leases and subleases of real property of GeoResources or any of its subsidiaries and under which GeoResources or any of its subsidiaries holds properties described in the Preliminary Offering Memorandum and the Pricing Disclosure Package, are in full force and effect.

(f) Cawley, Gillespie & Associates, Inc. (the "GeoResources Reservoir Engineer"), whose report dated February 27, 2012, is summarized or excerpted in reports incorporated by reference, or included, in the Preliminary Offering Memorandum and the Pricing Disclosure Package, was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to GeoResources. The written engineering report prepared by the GeoResources Reservoir Engineer dated February 27, 2012, setting forth the proved reserves attributed to the oil and gas properties of GeoResources and its subsidiaries accurately reflects in all material respects the interests of GeoResources and its subsidiaries in the properties therein as of December 31, 2011 and was prepared in accordance with the SEC's rules and regulations relating to the reporting of oil and natural gas reserves; the information furnished by GeoResources to the GeoResources Reservoir Engineer for purposes of preparing its report, including, without limitation, production, costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true, correct and complete in all material respects on the date supplied and was prepared in accordance with customary industry practices, as indicated in the letter of the GeoResources Reservoir Engineer dated February 27, 2012. The estimates of proved reserves and related information relating to the Brookeland fields prepared by GeoResources' internal reserve engineering staff as of December 31, 2011 accurately reflect in all material respects the interests that GeoResources has therein and were prepared in a manner consistent with the rules and regulations of the SEC relating to the reporting of oil and gas reserves; the information used by GeoResources' internal reserve engineers for purposes of preparing such estimates of proved reserves, including, without limitation, production, costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true, correct and complete in all material respects as of the date of such reserves.

(g) GeoResources and each of its subsidiaries have such permits, licenses, patents, franchises, certificates of need and other approvals or authorizations of governmental or regulatory authorities ("GeoResources Permits") as are necessary under applicable law to own their properties and conduct their businesses in the manner described in the Pricing Disclosure Package and the Offering Memorandum, except for any of the foregoing that could not, in the aggregate, reasonably be expected to have a Pro Forma Material Adverse Effect; each of GeoResources and its subsidiaries has fulfilled and performed all of its obligations with respect to the GeoResources Permits, and no event has occurred that allows, or after notice or lapse of time would allow, revocation or termination thereof or results in any other impairment of the rights of the holder or any such GeoResources Permits, except for any of the foregoing that could not reasonably be expected to have a Pro Forma Material Adverse Effect.

(h) GeoResources and each of its subsidiaries own or possess adequate rights to use all material patents, patent applications, trademarks, service marks, trade names, trademark registrations, service mark registrations, copyrights, licenses, know-how, software, systems and technology (including trade secrets and other unpatented and/or unpatentable proprietary or confidential information, systems or procedures) necessary for the conduct of their respective businesses and have no reason to believe that the conduct of their respective businesses will conflict with, and have not received any notice of



any claim of conflict with, any such rights of others, except as could not reasonably be expected to have a Pro Forma Material Adverse Effect.

(i) Other than as set forth in the Preliminary Offering Memorandum and the Pricing Disclosure Package, there are no legal or governmental proceedings pending to which GeoResources or any of its subsidiaries is a party or of which any property of GeoResources or any of its subsidiaries is the subject which if determined adversely to GeoResources, or such subsidiary, would individually or in the aggregate, have a Pro Forma Material Adverse Effect or which would materially and adversely affect the consummation of the transactions contemplated under this Agreement, the Registration Rights Agreement, the Escrow Agreement, the Joinder Agreement, the Merger Agreement or the performance by the Company or any Guarantor or GeoResources or any of its subsidiaries of their obligations hereunder or thereunder; and, no such proceedings are threatened or contemplated by governmental authorities or threatened by others.

(j) The statements made in the Pricing Disclosure Package and the Offering Memorandum, insofar as they purport to constitute summaries of the terms of the contracts and other documents relating to GeoResources and its subsidiaries that are so described, constitute accurate summaries of the terms of such contracts and documents in all material respects. Neither GeoResources nor any of its subsidiaries has knowledge that any other party to any such contract or other document has any intention not to render full performance as contemplated by the terms thereof.

(k) No labor disturbance by or dispute with the employees of GeoResources or any of its subsidiaries exists or is imminent that would reasonably be expected to have a Pro Forma Material Adverse Effect.

(1) GeoResources and each of its subsidiaries has filed all federal, state, local and foreign income and franchise tax returns required to be filed through the date hereof, subject to permitted extensions, and paid all taxes due thereon, and (i) no tax deficiency has been determined adversely to the GeoResources or its subsidiaries, nor (ii) are there any tax deficiencies relating to GeoResources and its subsidiaries that would, in the case of clause (i) or (ii) in the aggregate, reasonably be expected to have a Pro Forma Material Adverse Effect.

(m) Since the date as of which information is given in the Pricing Disclosure Package and the Offering Memorandum and except as may otherwise be described in the Pricing Disclosure Package and the Offering Memorandum, neither GeoResources nor any of its subsidiaries has (i) issued or granted any material amount of securities, except (A) pursuant to the exercise of outstanding options described therein, (B) as permitted or contemplated by the Merger Agreement as of the date of this Agreement or (C) as would not reasonably be expected to have a Pro Forma Material Adverse Effect, (ii) incurred any material liability or obligation, direct or contingent, other than liabilities and obligations that were incurred in the ordinary course of business or (iii) entered into any material transaction not in the ordinary course of business. Since the date as of which information is given in the Pricing Disclosure Package and the Offering Memorandum and except as may otherwise be described in the Pricing Disclosure Package and the Offering Memorandum, GeoResources has not declared or paid any dividend on its capital stock.

(n) Neither GeoResources nor any GeoResources Subsidiary is in violation of its charter (or similar organizational documents). Neither GeoResources nor any of its subsidiaries (i) is in default, and no event has occurred that, with notice or lapse of time or both, would constitute such a default, in the due performance or observance of any term, covenant, condition or other obligation contained in any indenture, mortgage, deed of trust, loan agreement, license or other agreement or instrument to which it is a party or by which it is bound or to which any of its properties or assets is subject, or (ii) is in violation of any statute or any order, rule or regulation of any court or governmental agency or body having jurisdiction over it or its property or assets or has failed to obtain any license, permit, certificate, franchise or other governmental authorization or permit necessary to the ownership of its property or to the conduct of its business, except in the case of clauses (i) and (ii), to the extent any such conflict, breach, violation or default would not, in the aggregate, reasonably be expected to have a Pro Forma Material Adverse Effect or would not materially impair the ability of the Company or any Guarantor to perform their obligations under this Agreement or the transactions contemplated by the Merger Agreement.

(o) Neither GeoResources nor any of its subsidiaries, nor any director, officer, agent, employee or other person associated with or acting on behalf of GeoResources or any of its subsidiaries, has (i) used any corporate funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity; (ii) made any direct or indirect unlawful payment to any foreign or domestic government official or employee from corporate funds; (iii) violated or is in violation of any provision of the Foreign Corrupt Practices Act of 1977; or (iv) made any bribe, rebate, payoff, influence payment, kickback or other unlawful payment.

(p) GeoResources and each of its subsidiaries (i) are, and at all times prior hereto were, in compliance with all laws, regulations, ordinances, rules, orders, judgments, decrees, permits or other legal requirements of any governmental authority, including without limitation any international, national, state, provincial, regional, or local authority, relating to the protection of human health or safety, the environment, or natural resources, or to hazardous or toxic substances or wastes, pollutants or contaminants (“Environmental Laws”) applicable to such entity, which compliance includes, without limitation, obtaining, maintaining and complying with all permits and authorizations and approvals required by Environmental Laws to conduct their respective businesses, and (ii) have not received notice of any actual or alleged violation of Environmental Laws, or of any potential liability for or other obligation concerning the presence, disposal or release of hazardous or toxic substances or wastes, pollutants or contaminants, except in the case of clause (i) or (ii) where such non-compliance, violation, liability, or other obligation would not, in the aggregate, reasonably be expected to have a Pro Forma Material Adverse Effect. Except as described in the Pricing Disclosure Package, there are no issues regarding compliance with Environmental Laws, or liabilities or other obligations under Environmental Laws or concerning hazardous or toxic substances or wastes, pollutants or contaminants, that would reasonably be expected to have a Pro Forma Material Adverse Effect.

(q) GeoResources and each of its subsidiaries maintain a system of internal control over financial reporting (as such term is defined in Rule 13a-15(f) of the Exchange Act) that complies with the requirements of the Exchange Act and that has been designed by, or under the supervision of, GeoResources' principal executive and principal financial officers, 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 in the United States. GeoResources and each of its subsidiaries maintains internal accounting controls that are sufficient to provide reasonable assurance that (i) transactions are executed in accordance with management's general or specific authorization, (ii) transactions are recorded as necessary to permit preparation of GeoResources' financial



statements in conformity with accounting principles generally accepted in the United States and to maintain accountability for its assets, (iii) access to GeoResources' assets is permitted only in accordance with management's general or specific authorization, and (iv) the recorded accountability for GeoResources' assets is compared with existing assets at reasonable intervals and appropriate action is taken with respect to any differences.

(r) (i) GeoResources and each of its subsidiaries have established and maintain disclosure controls and procedures (as such term is defined in Rule 13a-15 under the Exchange Act), (ii) such disclosure controls and procedures are designed to ensure that the information required to be disclosed by the GeoResources in the reports they file or submit under the Exchange Act (assuming GeoResources was required to file or submit such reports under the Exchange Act) is accumulated and communicated to management of GeoResources and its subsidiaries, including their respective principal executive officers and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure to be made; and (iii) such disclosure controls and procedures are effective in all material respects to perform the functions for which they were established, except in each case as would not reasonably be expected to have a Pro Forma Material Adverse Effect.

(s) Since the date of the most recent balance sheet of GeoResources and its consolidated subsidiaries audited by Grant Thornton and reviewed by the audit committee of the board of directors of GeoResources, (i) GeoResources has not been advised of by its auditors nor has it identified (A) any material weaknesses in internal controls, and (B) any fraud, whether or not material, that involves management or other employees who have a significant role in the internal controls of GeoResources and each of its subsidiaries; and (ii) there have been no changes in internal controls or in other factors that have materially affected or are reasonably likely to materially affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses, except in each case as would not reasonably be expected to have a Pro Forma Material Adverse Effect.

(t) No subsidiary of GeoResources is currently prohibited, directly or indirectly, from paying any dividends to the GeoResources, from making any other distribution on such subsidiary's capital stock, from repaying to GeoResources any loans or advances to such subsidiary from GeoResources or from transferring any of such subsidiary's property or assets to GeoResources or any other subsidiary of GeoResources, except as described in the Pricing Disclosure Package and the Offering Memorandum.

(u) There is and has been no failure on the part of GeoResources and any of its directors or officers, in their capacities as such, to comply with the provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith.

(v) The operations of GeoResources and its subsidiaries are and have been conducted at all times in compliance with applicable financial recordkeeping and reporting requirements of the Currency and Foreign Transactions Reporting Act of 1970, as amended, the money laundering statutes of all jurisdictions, the rules and regulations thereunder and any related or similar rules, regulations or guidelines, issued, administered or enforced by any governmental agency (collectively, the "Money Laundering Laws") and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving GeoResources or any of its subsidiaries with respect to the Money Laundering Laws is pending or threatened, except, in each case, as would not reasonably be expected to have a Pro Forma Material Adverse Effect.

(w) Neither GeoResources nor any of its subsidiaries nor any director, officer, agent, employee or affiliate of the GeoResources or any of its subsidiaries is currently subject to any U.S. sanctions administered by OFAC.

(x) As of the date hereof, (i) all royalties, rentals, deposits and other amounts owed under the oil and gas leases constituting the oil and gas properties of GeoResources and its subsidiaries have been properly and timely paid (other than amounts held in suspense accounts pending routine payments or related to disputes about the proper identification of royalty owners), and no amount of proceeds from the sale or production attributable to the oil and gas properties of GeoResources and its subsidiaries are currently being held in suspense by any purchaser thereof, except where such amounts due would not, individually or in the aggregate, have a Pro Forma Material Adverse Effect, and (ii) there are no claims under take-or-pay contracts pursuant to which natural gas purchasers have any make-up rights affecting the interests of GeoResources or its subsidiaries in their oil and gas properties, except where such

claims would not, individually or in the aggregate, reasonably be expected to have a Pro Forma Material Adverse Effect.

(y) Neither GeoResources nor any of its subsidiaries is in violation of or has received notice of any violation with respect to any federal or state law relating to discrimination in the hiring, promotion or pay of employees, nor any applicable federal or state wage and hour laws, the violation of any of which would reasonably be expected to have a Pro Forma Material Adverse Effect.

3. Purchase of the Notes by the Initial Purchasers, Agreements to Sell, Purchase and Resell.

(a) The Company and the Guarantors, jointly and severally hereby agree, on the basis of the representations, warranties, covenants and agreements of the Initial Purchasers contained herein and subject to all the terms and conditions set forth herein, to issue and sell to the Initial Purchasers and, upon the basis of the representations, warranties and agreements of the Company and the Guarantors herein contained and subject to all the terms and conditions set forth herein, each Initial Purchaser agrees, severally and not jointly, to purchase from the Company, at a purchase price of 96.646% of the principal amount thereof, the total principal amount of Notes set forth opposite the name of such Initial Purchaser in Schedule I hereto. The Company and the Guarantors shall not be obligated to deliver any of the securities to be delivered hereunder except upon transfer of immediately available funds to the Escrow Account for all of the securities to be purchased as provided herein.

(b) Each of the Initial Purchasers, severally and not jointly hereby represents and warrants to the Company that it will offer the Notes for sale upon the terms and conditions set forth in this Agreement and in the Pricing Disclosure Package. Each of the Initial Purchasers, severally and not jointly, hereby represents and warrants to, and agrees with, the Company, on the basis of the representations, warranties and agreements of the Company and the Guarantors, that such Initial Purchaser: (i) is a QIB with such knowledge and experience in financial and business matters as are necessary in order to evaluate the merits and risks of an investment in the Notes; (ii) in connection with the Exempt Resales, will solicit offers to buy the Notes only from, and will offer to sell the Notes only to, the Eligible Purchasers in accordance with this Agreement and on the terms contemplated by the Pricing Disclosure Package;



and (iii) will not offer or sell the Notes, nor has it offered or sold the Notes by, or otherwise engaged in, any form of general solicitation or general advertising (within the meaning of Regulation D, including, but not limited to, advertisements, articles, notices or other communications published in any newspaper, magazine, or similar medium or broadcast over television or radio, or any seminar or meeting whose attendees have been invited by any general solicitation or general advertising) and will not engage in any directed selling efforts within the meaning of Rule 902 under the Securities Act, in connection with the offering of the Notes. The Initial Purchasers have advised the Company that they will offer the Notes to Eligible Purchasers at a price initially equal to 98.646% of the principal amount thereof, plus accrued interest, if any, from the date of issuance of the Notes. Such price may be changed by the Initial Purchasers at any time without notice.

(c) Each of the Initial Purchasers, severally and not jointly, represents and warrants to the Company that:

(i) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the Notes in, from or otherwise involving the United Kingdom, and it has only communicated or caused to be communicated and it will only communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of section 21 of the FSMA) received by it in connection with the issue or sale of any Notes, in circumstances in which section 21(1) of the FSMA does not apply to the Company; and

(ii) in relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a Relevant Member State), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), it has not made and will not make an offer of the Notes to the public in that Relevant Member State prior to the publication of a prospectus in relation to the Notes which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of the Notes to the public in that Relevant Member State at any time:

(A) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(B) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(C) to fewer than 100, or if the Relevant Member State has implemented the relevant provision of the 2010 Prospectus Directive Amending Directive 150, natural or legal persons (other than qualified investors) subject to obtaining the prior consent of the representatives for any offer; or

(D) in any other circumstances which do not require the publication by the issuer of a prospectus pursuant to Article 3 of the Prospectus Directive;

For the purposes of this representation, the expression an “offer of securities to the public” in any Relevant Member State means the

communication in any form and by any means of sufficient information on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe the Notes, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 Prospectus Directive Amendment Directive to the extent implemented in the Relevant Member State) and includes any relevant implementing measure in each Relevant Member State.

(d) The Initial Purchasers have not nor, prior to the later to occur of (A) the Closing Date and (B) completion of the distribution of the Notes, will not, use, authorize use of, refer to or distribute any material in connection with the offering and sale of the Notes other than (i) the Preliminary Offering Memorandum, the Pricing Disclosure Package, the Offering Memorandum, (ii) any written communication that contains no “issuer information” (as defined in Rule 433(h)(2) under the Act) that was not included (including through incorporation by reference) in the Preliminary Offering Memorandum or any Free Writing Offering Document listed on Schedule IV hereto, (iii) the Free Writing Offering Documents listed on Schedule IV hereto, (iv) any written communication prepared by such Initial Purchaser and approved by the Company in writing, or (v) any written communication relating to or that contains the terms of the Notes and/or other information that was included (including through incorporation by reference) in the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum.

Each of the Initial Purchasers understands that the Company and, for purposes of the opinions to be delivered to the Initial Purchasers pursuant to Sections 7(c) and 7(d) hereof, counsel to the Company and counsel to the Initial Purchasers, will rely upon the accuracy and truth of the foregoing representations, warranties and agreements, and the Initial Purchasers hereby consents to such reliance.

4. Delivery of the Notes and Payment Therefor. Delivery to the Initial Purchasers of and payment for the Notes shall be made at the office of Vinson & Elkins LLP, at 10:00 A.M., New York City time, on July 16, 2012 (the “Closing Date”). The place of closing for the Notes and the Closing Date may be varied by agreement between the Initial Purchasers and the Company.

The Notes will be delivered to the Initial Purchasers, or the Trustee as custodian for The Depository Trust Company (“DTC”), against payment by or on behalf of the Initial Purchasers of the purchase price therefor by wire transfer in immediately available funds in accordance with the terms of



the Escrow Agreement, by causing DTC to credit the Notes to the account of the Initial Purchasers at DTC. The Notes will be evidenced by one or more global securities in definitive form (the "Global Notes") and will be registered, in the case of the Global Notes, in the name of Cede & Co. as nominee of DTC, and in the other cases, in such names and in such denominations as the Initial Purchasers shall request prior to 10:00 A.M., New York City time, on the second business day preceding the Closing Date. The Notes to be delivered to the Initial Purchasers shall be made available to the Initial Purchasers in New York City for

inspection and packaging not later than 10:00 A.M., New York City time, on the business day next preceding the Closing Date.

5. Agreements of the Company and the Guarantors. The Company and the Guarantors (in the case of the Acquired Guarantors, upon execution of the Joinder Agreement), jointly and severally, agree with each of the Initial Purchasers as follows:

(a) The Company and the Guarantors will furnish to the Initial Purchasers, without charge, within one business day of the date of the Offering Memorandum, such number of copies of the Offering Memorandum as may then be amended or supplemented as they may reasonably request.

(b) The Company and the Guarantors will not make any amendment or supplement to the Pricing Disclosure Package or to the Offering Memorandum of which the Initial Purchasers shall not previously have been advised or to which they shall reasonably object after being so advised.

(c) The Company and each of the Guarantors consents to the use of the Pricing Disclosure Package and the Offering Memorandum in accordance with the securities or Blue Sky laws of the jurisdictions in which the Notes are offered by the Initial Purchasers and by all dealers to whom Notes may be sold, in connection with the offering and sale of the Notes.

(d) If, at any time prior to completion of the distribution of the Notes by the Initial Purchasers to Eligible Purchasers, any event occurs or information becomes known that, in the judgment of the Company or any of the Guarantors or in the opinion of counsel for the Initial Purchasers, should be set forth in the Pricing Disclosure Package or the Offering Memorandum so that the Pricing Disclosure Package or the Offering Memorandum, as then amended or supplemented, does not include any untrue statement of material fact or omit to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, or if it is necessary to supplement or amend the Pricing Disclosure Package or the Offering Memorandum in order to comply with any law, the Company and the Guarantors will forthwith prepare an appropriate supplement or amendment thereto, and will expeditiously furnish to the Initial Purchasers and dealers a reasonable number of copies thereof.

(e) None of the Company nor any Guarantor will make any offer to sell or solicitation of an offer to buy the Notes that would constitute a Free Writing Offering Document without the prior consent of the Representatives, which consent shall not be unreasonably withheld or delayed. If at any time following issuance of a Free Writing Offering Document any event occurred or occurs as a result of which such Free Writing Offering Document conflicts with the information in the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum or, when taken together with the information in the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum, includes an untrue statement of a material fact or omits to state any material fact necessary in order to make the statements therein, in the light of the circumstances then prevailing, not misleading, as promptly as practicable after becoming aware thereof, the Company will give notice thereof to the Initial Purchasers through the Representatives and, if requested by the Representatives, will

prepare and furnish without charge to each Initial Purchaser a Free Writing Offering Document or other document which will correct such conflict, statement or omission.

(f) Promptly from time to time to take such action as the Initial Purchasers may reasonably request to qualify the Notes for offering and sale under the securities or Blue Sky laws of such jurisdictions as the Initial Purchasers may request and to comply with such laws so as to permit the continuance of sales and dealings therein in such jurisdictions for as long as may be necessary to complete the distribution of the Notes; provided that in connection therewith the Company shall not be required to (i) qualify as a foreign corporation in any jurisdiction in which it would not otherwise be required to so qualify, (ii) file a general consent to service of process in any such jurisdiction, or (iii) subject itself to taxation in any jurisdiction in which it would not otherwise be subject.

(g) For a period commencing on the date hereof and ending on the 90 \( ^{th} \)  day after the date of the Offering Memorandum, the Company and the Guarantors agree not to, directly or indirectly, (i) offer for sale, sell, or otherwise dispose of (or enter into any transaction or device that is designed to, or would be expected to, result in the disposition by any person at any time in the future of) any debt securities of the Company substantially similar to the Notes or securities convertible into or exchangeable for such debt securities of the Company, or sell or grant options, rights or warrants with respect to such debt securities of the Company or securities convertible into or exchangeable for such debt securities of the Company, (ii) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such debt securities of the Company, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of debt securities of the Company or other securities, in cash or otherwise, (iii) file or cause to be filed a registration statement, including any amendments, with respect to the registration of debt securities of the Company substantially similar to the Notes or securities convertible, exercisable or exchangeable into debt securities of the Company substantially similar to the Notes, or (iv) publicly announce an offering of any debt securities of the Company substantially similar to the Notes or securities convertible or exchangeable into debt securities substantially similar to the Notes, in each case without the prior written consent of Barclays Capital Inc., on behalf of the Initial Purchasers, except in exchange for the Exchange Notes and the Exchange Guarantees in connection with the Exchange Offer.

(h) Upon request, so long as any of the Notes are outstanding, the Company and the Guarantors will, furnish at their expense to the Initial Purchasers and to the holders of the Notes the information required by Rule 144A(d)(4) under the Securities Act (if any).

(i) The Company and the Guarantors will apply the net proceeds from the sale of the Notes to be sold by it hereunder substantially in accordance with the description set forth in the Pricing Disclosure Package and the Offering Memorandum under the caption “Use of Proceeds.”



(j) The Company, the Guarantors and their respective affiliates will not take, directly or indirectly, any action designed to or that has constituted or that reasonably could be expected to cause or result in the stabilization or manipulation of the price of any security of the Company or the Guarantors in connection with the offering of the Notes.

(k) The Company and the Guarantors will use their best efforts to permit the Notes to be eligible for clearance and settlement through DTC.

(l) The Company and the Guarantors will not, and will not permit any of their respective affiliates (as defined in Rule 144 under the Securities Act) to, resell any of the Notes that have been acquired by any of them, except for Notes purchased by the Company, the Guarantors or any of their respective affiliates and resold in a transaction registered under the Securities Act.

(m) The Company and the Guarantors will take precautions designed to insure that any offer or sale, direct or indirect, in the United States or to any U.S. person (as defined in Rule 902 under the Securities Act), of any Notes or any substantially similar security issued by the Company or any Guarantor, within six months subsequent to the date on which the distribution of the Notes has been completed (as notified to the Company by the Initial Purchasers), is made under restrictions and other circumstances reasonably designed not to affect the status of the offer and sale of the Notes in the United States and to U.S. persons contemplated by this Agreement as transactions exempt from the registration provisions of the Securities Act, including any sales pursuant to Rule 144A under, or Regulations D or S of, the Securities Act.

(n) None of the Company or any of the Guarantors or any other person on its or their behalf (other than the Initial Purchasers, as to which no covenant is given) will (i) solicit offers for, or offer or sell, the Notes by means of any form of general solicitation or general advertising within the meaning of Rule 502(c) of Regulation D or in any manner involving a public offering within the meaning of Section 4(2) of the Securities Act or (ii) engage in any directed selling efforts within the meaning of Regulation S, and all such persons will comply with the offering restrictions requirement of Regulation S.

(o) The Company and the Guarantors agree to comply with all the terms and conditions of the Registration Rights Agreement and all agreements set forth in the representation letters of the Company and the Guarantors to DTC relating to the approval of the Notes by DTC for “book entry” transfer.

(p) Concurrent with the closing of the GeoResources Merger, the Company and the Guarantors shall cause the Acquired Guarantors to (i) execute and deliver the Joinder Agreement and (ii) execute and deliver supplemental indentures to the Indenture and/or take all necessary actions to become Guarantors under the Indenture.

(q) The Company and the Guarantors will use their best efforts to (i) do and perform all things required or necessary to be done and performed under this Agreement by them prior to the Closing Date, and (ii) satisfy all conditions precedent to the Initial Purchasers' obligations hereunder to purchase the Notes.

6. Expenses. Whether or not the transactions contemplated by this Agreement are consummated or this Agreement is terminated, the Company and the Guarantors, jointly and severally, agree, to pay all expenses, costs, fees and taxes incident to and in connection with: (a) the preparation, printing, filing and distribution of the Preliminary Offering Memorandum, the Pricing Disclosure Package and the Offering Memorandum (including, without limitation,

financial statements and exhibits) and all amendments and supplements thereto (including the fees, disbursements and expenses of the Company’s and the Guarantors’ accountants and counsel, but not, however, legal fees and expenses of the Initial Purchasers’ counsel incurred in connection therewith); (b) the preparation, printing (including, without limitation, word processing and duplication costs) and delivery of this Agreement, the Indenture, the Registration Rights Agreement, the Joinder Agreement, all Blue Sky memoranda and all other agreements, memoranda, correspondence and other documents printed and delivered in connection therewith and with the Exempt Resales (but not, however, legal fees and expenses of the Initial Purchasers’ counsel incurred in connection with any of the foregoing other than fees of such counsel plus reasonable disbursements incurred in connection with the preparation, printing and delivery of such Blue Sky memoranda); (c) the issuance and delivery by the Company of the Notes and by the Guarantors of the Guarantees and any taxes payable in connection therewith; (d) the qualification of the Notes and Exchange Notes for offer and sale under the securities or Blue Sky laws of the several states and any foreign jurisdictions as the Initial Purchasers may designate (including, without limitation, the reasonable fees and disbursements of the Initial Purchasers’ counsel relating to such registration or qualification); (e) the furnishing of such copies of the Preliminary Offering Memorandum, the Pricing Disclosure Package and the Offering Memorandum, and all amendments and supplements thereto, as may be reasonably requested for use in connection with the Exempt Resales; (f) the preparation of certificates for the Notes (including, without limitation, printing and engraving thereof); (g) the approval of the Notes by DTC for “book-entry” transfer (including fees and expenses of counsel for the Initial Purchasers reasonably incurred in connection therewith); (h) the rating of the Notes and the Exchange Notes; (i) the obligations of the Trustee, any agent of the Trustee and the counsel for the Trustee in connection with the Indenture, the Notes and the Guarantees, the Exchange Notes; and the Exchange Guarantees; (j) the performance by the Company and the Guarantors of their other obligations under this Agreement; and (k) all travel expenses (including expenses related to chartered aircraft) of each Initial Purchaser and the Company’s officers and employees and any other expenses of each Initial Purchaser and the Company in connection with attending or hosting meetings with prospective purchasers of the Notes, and expenses associated with any electronic road show.

7. Conditions to Initial Purchasers’ Obligations. The respective obligations of the Initial Purchasers hereunder are subject to the accuracy, when made and on and as of the Closing Date, of the representations and warranties of the Company and the Guarantors contained herein, to the performance by the Company and the Guarantors of their respective obligations hereunder, and to each of the following additional terms and conditions:

(a) The Initial Purchasers shall not have discovered and disclosed to the Company on or prior to the Closing Date that the Pricing Disclosure Package or the Offering Memorandum, or any amendment or supplement thereto, contains an untrue statement of a fact which, in the opinion of



Vinson & Elkins LLP, counsel to the Initial Purchasers, is material or omits to state a fact which, in the opinion of such counsel, is material and is necessary in order to make the statements therein, in the light of the circumstances then prevailing, not misleading.

(b) All corporate proceedings and other legal matters incident to the authorization, form and validity of this Agreement, the Notes, the Guarantees, the Exchange Notes, the Exchange Guarantees, the Registration Rights Agreement, the Escrow Agreement, the

Indenture, the Pricing Disclosure Package and the Offering Memorandum, and all other legal matters relating to this Agreement and the transactions contemplated hereby shall be reasonably satisfactory in all material respects to counsel for the Initial Purchasers, and the Company and the Guarantors shall have furnished to such counsel all documents and information that they may reasonably request to enable them to pass upon such matters.

(c) Thompson & Knight LLP shall have furnished to the Initial Purchasers its written opinion, as counsel to the Company and the Guarantors, addressed to the Initial Purchasers and dated the Closing Date, in form and substance reasonably satisfactory to the Initial Purchasers, substantially in the form of Exhibit B hereto.

(d) David Elkouri, General Counsel of the Company, shall have furnished to the Initial Purchasers his written opinion, as counsel to the Company and the Guarantors and dated the Closing Date, in form and substance reasonably satisfactory to the Initial Purchasers, substantially in the form of Exhibit C hereto.

(e) The Initial Purchasers shall have received from Vinson & Elkins LLP, counsel for the Initial Purchasers, such opinion or opinions, dated the Closing Date, with respect to the issuance and sale of the Notes, the Pricing Disclosure Package, the Offering Memorandum and other related matters as the Initial Purchasers may reasonably require, and the Company shall have furnished to such counsel such documents and information as such counsel reasonably requests for the purpose of enabling them to pass upon such matters.

(f) At the time of execution of this Agreement, the Initial Purchasers shall have received from each of (a) Deloitte & Touche LLP, (b) UHY LLC and (c) Grant Thornton LLP a letter, in form and substance satisfactory to the Initial Purchasers, addressed to the Initial Purchasers and dated the date hereof (i) confirming that they are independent public accountants within the meaning of the Securities Act and are in compliance with the applicable requirements relating to the qualification of accountants under Rule 2-01 of Regulation S-X of the Commission and (ii) stating, as of the date hereof (or, with respect to matters involving changes or developments since the respective dates as of which specified financial information is given in the Pricing Disclosure Package, as of a date not more than three days prior to the date hereof), the conclusions and findings of such firm with respect to the financial information and (iii) covering such other matters as are ordinarily covered by accountants' "comfort letters" to underwriters in connection with registered public offerings.

(g) With respect to the letters of each of (a) Deloitte & Touche LLP, (b) UHY LLC and (c) Grant Thornton LLP referred to in the preceding paragraph and delivered to the Initial Purchasers concurrently with the execution of this Agreement (the "initial letter"), the Company shall have furnished to the Initial Purchasers a "bring-down letter" of such accountants, addressed to the Initial Purchasers and dated the Closing Date (i) confirming that they are independent public accountants within the meaning of the Securities Act and are in compliance with the applicable requirements relating to the qualification of accountants under Rule 2-01 of Regulation S-X of the Commission, (ii) stating, as of the Closing Date (or, with respect to matters involving changes or developments since the respective dates as of which specified financial information is given in each of the Pricing Disclosure Package or the Offering Memorandum, as of a date not more than three days prior to the date of the Closing Date), the

conclusions and findings of such firm with respect to the financial information and other matters covered by the initial letter, and (iii) confirming in all material respects the conclusions and findings set forth in the initial letter.

(h) Except as described in the Pricing Disclosure Package and the Offering Memorandum, (i) neither the Company, any Guarantor nor any of their respective subsidiaries shall have sustained, since the date of the latest audited financial statements included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum, any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, or (ii) since such date, there shall not have been any change in the capital stock or long-term debt of the Company, any Guarantor or any of their respective subsidiaries or any change, or any development involving a prospective change, in or affecting the business, properties, prospects, financial condition, stockholders' equity or results of operations of the Company, the Guarantors and their respective subsidiaries, taken as a whole, the effect of which, in any such case described in clause (i) or (ii), is, individually or in the aggregate, in the judgment of the Representatives, so material and adverse as to make it impracticable or inadvisable to proceed with the offering or the delivery of the Notes being delivered on the Closing Date on the terms and in the manner contemplated in the Pricing Disclosure Package and the Offering Memorandum.

(i) Except as described in the Pricing Disclosure Package and the Offering Memorandum, (i) neither GeoResources nor any of its subsidiaries shall have sustained, since the date of the latest audited financial statements included and incorporated by reference in the Pricing Disclosure Package and the Offering Memorandum, any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, or (ii) since such date, there shall not have been any change in the capital stock or long-term debt of GeoResources or any of its subsidiaries or any change, or any development involving a prospective change, in or affecting the business, properties, prospects, financial condition, stockholders' equity or results of operations of the Company, GeoResources and their respective subsidiaries, taken as a whole, the effect of which, in any such case described in clause (i) or (ii), is, individually or in the aggregate, in the judgment of the Representatives, so material and adverse as it relates to the Company, GeoResources and their respective subsidiaries, taken as a whole, as to make it impracticable or inadvisable to proceed with the offering or the delivery of the Notes being delivered on the Closing Date on the terms and in the manner contemplated in the Pricing Disclosure Package and the Offering Memorandum.

(j) At the time of execution of this Agreement, the Initial Purchasers shall have received from each of (a) Forrest A. Garb & Associates and (b) Cawley Gillespie & Associates, Inc. an initial letter (the "initial expert letter"), in form and substance satisfactory to the Initial Purchasers,



addressed to the Initial Purchasers and dated the date hereof and a subsequent letter dated as of the Closing Date, which such letter shall cover the period from any initial expert letter to the Closing Date, confirming that they are independent with respect to the Company and stating the conclusions and findings of such firm with respect to matters pertaining to the Company’s use of the reports of proved reserves from Forrest A. Garb & Associates and

GeoResources’ use of the reports of proved reserves from Cawley Gillespie & Associates, Inc. as is customary to initial purchasers in connection with similar transactions.

(k) The Company and each Guarantor shall have furnished or caused to be furnished to the Initial Purchasers dated as of the Closing Date a certificate of the Chief Executive Officer and Chief Financial Officer of the Company and each Guarantor, or other officers satisfactory to the Initial Purchasers, as to such matters as the Representatives may reasonably request, including, without limitation, a statement that:

(i) The representations, warranties and agreements of the Company and the Guarantors in Section 2 are true and correct on and as of the Closing Date, and the Company and the Guarantors have complied with all its agreements contained herein and satisfied all the conditions on its part to be performed or satisfied hereunder at or prior to the Closing Date; and

(ii) They have examined the Pricing Disclosure Package and the Offering Memorandum, and, in their opinion, (A) the Pricing Disclosure Package, as of the Applicable Time and as of the Closing Date, and the Offering Memorandum, as of its date and as of the Closing Date, did not and do not contain any untrue statement of a material fact and did not and do not omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading and (B) since the date of the Pricing Disclosure Package and the Offering Memorandum, no event has occurred which should have been set forth in a supplement or amendment to the Pricing Disclosure Package and the Offering Memorandum.

(l) Subsequent to the earlier of the Applicable Time and the execution and delivery of this Agreement (i) no downgrading shall have occurred in the rating accorded the Company’s debt securities by any “nationally recognized statistical rating organization,” as such term is used in Section 15E of the Exchange Act, and (ii) no such organization shall have publicly announced that it has under surveillance or review, or has changed its outlook with respect to, its rating of the Notes or of any other debt securities issued or guaranteed by the Company or any of the Guarantors (in each case, other than an announcement with positive implications of a possible upgrading).

(m) The Notes shall be eligible for clearance and settlement through DTC.

(n) The Company and the Guarantors shall have executed and delivered the Registration Rights Agreement, and the Initial Purchasers shall have received an original copy thereof, duly executed by the Company and the Guarantors.

(o) The Company, the Escrow Agent and the Trustee shall have executed and delivered the Escrow Agreement, and the Initial Purchasers shall have received an original copy thereof, duly executed by the Company, the Escrow Agent and the Trustee.

(p) The Company, the Guarantors and the Trustee shall have executed and delivered the Indenture, and the Initial Purchasers shall have received an original copy thereof, duly executed by the Company, the Guarantors and the Trustee.

(q) Subsequent to the execution and delivery of this Agreement there shall not have occurred any of the following: (i) trading in securities generally on the New York Stock Exchange or the NYSE Amex Equities or in the over-the-counter market, or trading in any securities of the Company or GeoResources on any exchange or in the over-the-counter market, shall have been suspended or materially limited or the settlement of such trading generally shall have been materially disrupted or minimum prices shall have been established on any such exchange or such market by the Commission, by such exchange or by any other regulatory body or governmental authority having jurisdiction, (ii) a general moratorium on commercial banking activities shall have been declared by federal or state authorities, (iii) the United States shall have become engaged in hostilities, there shall have been an escalation in hostilities involving the United States or there shall have been a declaration of a national emergency or war by the United States, (iv) a material disruption in commercial banking or securities settlement or clearance services in the United States, or (v) there shall have occurred such a material adverse change in general economic, political or financial conditions, including, without limitation, as a result of terrorist activities after the date hereof (or the effect of international conditions on the financial markets in the United States shall be such), as to make it, in the judgment of the Representatives, impracticable or inadvisable to proceed with the offering or delivery of the Notes being delivered on the Closing Date on the terms and in the manner contemplated in the Offering Memorandum or that, in the judgment of the Representatives, could materially and adversely affect the financial markets or the markets for the Notes and other debt securities.

(r) There shall exist at and as of the Closing Date no condition that would constitute a default (or an event that with notice or the lapse of time, or both, would constitute a default) under the Indenture or a material breach under the Merger Agreement as in effect at the Closing Date (or an event that with notice or lapse of time, or both, would constitute such a default or material breach).

All opinions, letters, evidence and certificates mentioned above or elsewhere in this Agreement shall be deemed to be in compliance with the provisions hereof only if they are in form and substance reasonably satisfactory to counsel for the Initial Purchasers.

## 8. Indemnification and Contribution.

(a) The Company and each Guarantor (in the case of the Acquired Guarantors, upon execution and delivery of the Joinder Agreement), hereby agrees, jointly and severally, to indemnify and hold harmless each Initial Purchaser, its affiliates, directors, officers and employees and each person, if any, who controls any Initial Purchaser within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any loss, claim, damage or liability, joint or several, or any action in respect thereof (including, but not limited to, any loss, claim, damage, liability or action



relating to purchases and sales of Notes), to which that Initial Purchaser, affiliate, director, officer, employee or controlling person may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, (i) any untrue statement or alleged untrue statement of a material fact contained (A) in any Free Writing Offering Document, the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum or in any amendment or supplement thereto, (B) in any Blue Sky application or other document prepared or executed by the Company or any Guarantor (or based upon any

written information furnished by the Company or any Guarantor) specifically for the purpose of qualifying any or all of the Notes under the securities laws of any state or other jurisdiction (any such application, document or information being hereinafter called a "Blue Sky Application"), or (C) in any materials or information provided to investors by, or with the approval of, the Company or any Guarantor in connection with the marketing of the offering of the Notes ("Marketing Materials"), including any road show or investor presentations made to investors by the Company (whether in person or electronically) or any materials prepared for the purpose of compliance with the Canadian securities laws, or (ii) the omission or alleged omission to state in any Free Writing Offering Document, the Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum, or in any amendment or supplement thereto, or in any Blue Sky Application or in any Marketing Materials, any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, and shall reimburse each Initial Purchaser and each such affiliate, director, officer, employee or controlling person promptly upon demand for any legal or other expenses reasonably incurred by that Initial Purchaser, affiliate, director, officer, employee or controlling person in connection with investigating or defending or preparing to defend against any such loss, claim, damage, liability or action as such expenses are incurred; provided, however, that the Company and the Guarantors shall not be liable in any such case to the extent that any such loss, claim, damage, liability or action arises out of, or is based upon, any untrue statement or alleged untrue statement or omission or alleged omission made in any Preliminary Offering Memorandum, the Pricing Disclosure Package or Offering Memorandum, or in any such amendment or supplement thereto, or in any Blue Sky Application or in any Marketing Materials, in reliance upon and in conformity with written information concerning such Initial Purchaser furnished to the Company through the Representatives by or on behalf of any Initial Purchaser specifically for inclusion therein, which information consists solely of the information specified in Section 8(e). The foregoing indemnity agreement is in addition to any liability that the Company or the Guarantors may otherwise have to any Initial Purchaser or to any affiliate, director, officer, employee or controlling person of that Initial Purchaser.

(b) Each Initial Purchaser, severally and not jointly, hereby agrees to indemnify and hold harmless the Company, each Guarantor (in the case of the Acquired Guarantors, only upon execution and delivery of the Jonder Agreement), their respective officers and employees, each of their respective directors, and each person, if any, who controls the Company or any Guarantor within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any loss, claim, damage or liability, joint or several, or any action in respect thereof, to which the Company, any Guarantor or any such director, officer, employee or controlling person may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, (i) any untrue statement or alleged untrue statement of a material fact contained (A) in any Free Writing Offering Document, Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum or in any amendment or supplement thereto, (B) in any Blue Sky Application, or (C) in any Marketing Materials, or (ii) the omission or alleged omission to state in any Free Writing Offering Document, Preliminary Offering Memorandum, the Pricing Disclosure Package or the Offering Memorandum, or in any amendment or supplement thereto, or in any Blue Sky Application or in any Marketing Materials any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, but in each case only to the extent that the untrue statement or alleged

untrue statement or omission or alleged omission was made in reliance upon and in conformity with written information concerning such Initial Purchaser furnished to the Company through the Representatives by or on behalf of that Initial Purchaser specifically for inclusion therein, which information is limited to the information set forth in Section 8(e). The foregoing indemnity agreement is in addition to any liability that any Initial Purchaser may otherwise have to the Company, any Guarantor or any such director, officer, employee or controlling person.

(c) Promptly after receipt by an indemnified party under this Section 8 of notice of any claim or the commencement of any action, the indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party under this Section 8, notify the indemnifying party in writing of the claim or the commencement of that action; provided, however, that the failure to notify the indemnifying party shall not relieve it from any liability that it may have under this Section 8 except to the extent it has been materially prejudiced (through the forfeiture of substantive rights or defenses) by such failure and; provided, further, that the failure to notify the indemnifying party shall not relieve it from any liability that it may have to an indemnified party otherwise than under this paragraph (a) or (b) of this Section 8. If any such claim or action shall be brought against an indemnified party, and it shall notify the indemnifying party thereof, the indemnifying party shall be entitled to participate therein and, to the extent that it wishes, jointly with any other similarly notified indemnifying party, to assume the defense thereof with counsel reasonably satisfactory to the indemnified party. After notice from the indemnifying party to the indemnified party of its election to assume the defense of such claim or action, the indemnifying party shall not be liable to the indemnified party under this Section 8 for any legal or other expenses subsequently incurred by the indemnified party in connection with the defense thereof other than reasonable costs of investigation; provided, however, that the Initial Purchasers shall have the right to employ counsel to represent jointly the Initial Purchasers and their respective affiliates, directors, officers, employees and controlling persons who may be subject to liability arising out of any claim in respect of which indemnity may be sought by the Initial Purchasers against the Company or any Guarantor under this Section 8, if (i) the Company, the Guarantors and the Initial Purchasers shall have so mutually agreed; (ii) the Company and the Guarantors have failed within a reasonable time to retain counsel reasonably satisfactory to the Initial Purchasers; (iii) the Initial Purchasers and their respective affiliates, directors, officers, employees and controlling persons shall have reasonably concluded, based on the advice of counsel, that there may be legal defenses available to them that are different from or in addition to those available to the Company and the Guarantors; or (iv) the named parties in any such proceeding (including any impleaded parties) include both the Initial Purchasers or their respective affiliates, directors, officers, employees or controlling persons, on the one hand, and the Company and the Guarantors, on the other hand, and representation of both sets of parties by the same counsel would present a conflict due to actual or potential differing interests between them, and in any such event the fees and expenses of such separate counsel shall be paid by the Company and the Guarantors. No indemnifying party shall (x) without the prior written consent of the indemnified parties (which consent shall not be unreasonably withheld), settle or compromise or consent to the entry of any judgment with respect to any pending or threatened claim, action, suit or proceeding in respect of which indemnification or contribution may be sought hereunder (whether or not the indemnified parties are actual or potential parties to such claim or action) unless such settlement, compromise or consent includes an unconditional release of each indemnified party from all liability arising out of such claim, action, suit or proceeding and does not include a statement as to, or an admission



of fault, culpability or a failure to act by or on behalf of any indemnified party, or (y) be liable for any settlement of any such action effected without its written consent (which consent shall not be unreasonably withheld), but if settled with the consent of the indemnifying party or if there be a final judgment of the plaintiff in any such action, the indemnifying party agrees to indemnify and hold harmless any indemnified party from and against any loss or liability by reason of such settlement or judgment.

(d) If the indemnification provided for in this Section 8 shall for any reason be unavailable to or insufficient to hold harmless an indemnified party under Section 8(a) or 8(b) in respect of any loss, claim, damage or liability, or any action in respect thereof, referred to therein, then each indemnifying party shall, in lieu of indemnifying such indemnified party, contribute to the amount paid or payable by such indemnified party as a result of such loss, claim, damage or liability, or action in respect thereof, (i) in such proportion as shall be appropriate to reflect the relative benefits received by the Company and the Guarantors, on the one hand, and the Initial Purchasers, on the other, from the offering of the Notes, or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Company and the Guarantors, on the one hand, and the Initial Purchasers, on the other, with respect to the statements or omissions that resulted in such loss, claim, damage or liability, or action in respect thereof, as well as any other relevant equitable considerations. The relative benefits received by the Company and the Guarantors, on the one hand, and the Initial Purchasers, on the other, with respect to such offering shall be deemed to be in the same proportion as the total net proceeds from the offering of the Notes purchased under this Agreement (before deducting expenses) received by the Company and the Guarantors, on the one hand, and the total discounts and commissions received by the Initial Purchasers with respect to the Notes purchased under this Agreement, on the other hand, bear to the total gross proceeds from the offering of the Notes under this Agreement as set forth on the cover page of the Offering Memorandum. The relative fault shall be determined by reference to whether the untrue or alleged untrue statement of a material fact or omission or alleged omission to state a material fact relates to information supplied by the Company, the Guarantors, or the Initial Purchasers, the intent of the parties and their relative knowledge, access to information and opportunity to correct or prevent such statement or omission. For purposes of the preceding two sentences, the net proceeds deemed to be received by the Company shall be deemed to be also for the benefit of the Guarantors, and information supplied by the Company shall also be deemed to have been supplied by the Guarantors. The Company, the Guarantors, and the Initial Purchasers agree that it would not be just and equitable if contributions pursuant to this Section 8(d) were to be determined by pro rata allocation (even if the Initial Purchasers were treated as one entity for such purpose) or by any other method of allocation that does not take into account the equitable considerations referred to herein. The amount paid or payable by an indemnified party as a result of the loss, claim, damage or liability, or action in respect thereof, referred to above in this Section 8(d) shall be deemed to include, for purposes of this Section 8(d), any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 8(d), no Initial Purchaser shall be required to contribute any amount in excess of the amount by which the net proceeds from the sale to Eligible Purchasers of the Notes initially purchased by it exceeds the amount of any damages that such Initial Purchaser has otherwise paid or become liable to pay by reason of any untrue or alleged untrue statement or omission or alleged omission. No person

guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Initial Purchasers' obligations to contribute as provided in this Section 8(d) are several in proportion to their respective purchase obligations and not joint.

(e) The Initial Purchasers severally confirm and the Company and the Guarantors acknowledge and agree that the statements contained in the second sentence under the heading “Plan of Distribution—Rule 144A and Regulation S” in the Pricing Disclosure Package and the Offering Memorandum are correct and constitute the only information concerning such Initial Purchasers furnished in writing to the Company or any Guarantor by or on behalf of the Initial Purchasers specifically for inclusion in any Free Writing Offering Document, the Preliminary Offering Memorandum, the Pricing Disclosure Package, the Offering Memorandum, or in any amendment or supplement thereto or in any Blue Sky Application or in any Marketing Materials.

## 9. Defaulting Initial Purchasers.

(a) If, on the Closing Date, any Initial Purchaser defaults in its obligations to purchase the Notes that it has agreed to purchase under this Agreement, the remaining non-defaulting Initial Purchasers may in their discretion arrange for the purchase of such Notes by the non-defaulting Initial Purchasers or other persons satisfactory to the Company on the terms contained in this Agreement. If, within 36 hours after any such default by any Initial Purchaser, the non-defaulting Initial Purchasers do not arrange for the purchase of such Notes, then the Company shall be entitled to a further period of 36 hours within which to procure other persons satisfactory to the non-defaulting Initial Purchasers to purchase such Notes on such terms. In the event that within the respective prescribed periods, the non-defaulting Initial Purchasers notify the Company that they have so arranged for the purchase of such Notes, or the Company notifies the non-defaulting Initial Purchasers that it has so arranged for the purchase of such Notes, either the non-defaulting Initial Purchasers or the Company may postpone the Closing Date for up to seven full business days in order to effect any changes that in the opinion of counsel for the Company or counsel for the Initial Purchasers may be necessary in the Pricing Disclosure Package, the Offering Memorandum or in any other document or arrangement, and the Company agrees to promptly prepare any amendment or supplement to the Pricing Disclosure Package or the Offering Memorandum that effects any such changes. As used in this Agreement, the term “Initial Purchaser” includes, for all purposes of this Agreement unless the context requires otherwise, any party not listed in Schedule I hereto that, pursuant to this Section 9, purchases Notes that a defaulting Initial Purchaser agreed but failed to purchase.

(b) If, after giving effect to any arrangements for the purchase of the Notes of a defaulting Initial Purchaser or Initial Purchasers by the non-defaulting Initial Purchasers and the Company as provided in paragraph (a) above, the aggregate principal amount of such Notes that remains unpurchased does not exceed one-eleventh of the aggregate principal amount of all the Notes, then the Company shall have the right to require each non-defaulting Initial Purchaser to purchase the principal amount of Notes that such Initial Purchaser agreed to purchase hereunder plus such Initial Purchaser's pro rata share (based on the principal amount of Notes that such Initial Purchaser agreed to purchase hereunder) of the Notes of such defaulting Initial Purchaser or Initial Purchasers for which such arrangements have not been made; provided that



the non-defaulting Initial Purchasers shall not be obligated to purchase more than 110% of the aggregate principal amount of Notes that it agreed to purchase on the Closing Date pursuant to the terms of Section 3.

(c) If, after giving effect to any arrangements for the purchase of the Notes of a defaulting Initial Purchaser or Initial Purchasers by the non-defaulting Initial Purchasers and the Company as provided in paragraph (a) above, the aggregate principal amount of such Notes that remains unpurchased exceeds one-eleventh of the aggregate principal amount of all the Notes, or if the Company shall not exercise the right described in paragraph (b) above, then this Agreement shall terminate without liability on the part of the non-defaulting Initial Purchasers. Any termination of this Agreement pursuant to this Section 9 shall be without liability on the part of the Company or the Guarantors, except that the Company and each of the Guarantors will continue to be liable for the payment of expenses as set forth in Sections 6 and 11 to the non-defaulting Initial Purchasers and except that the provisions of Section 8 shall not terminate and shall remain in effect.

(d) Nothing contained herein shall relieve a defaulting Initial Purchaser of any liability it may have to the Company, the Guarantors or any non-defaulting Initial Purchaser for damages caused by its default.

10. Termination. The obligations of the Initial Purchasers hereunder may be terminated by the Initial Purchasers by notice given to and received by the Company prior to delivery of and payment for the Notes if, prior to that time, any of the events described in Sections 7(h), (i), (l) or (q) shall have occurred or if the Initial Purchasers shall decline to purchase the Notes for any reason permitted under this Agreement.

11. Reimbursement of Initial Purchasers' Expenses. If (a) the Company for any reason fails to tender the Notes for delivery to the Initial Purchasers, or (b) the Initial Purchasers shall decline to purchase the Notes for any reason permitted under this Agreement, the Company and the Guarantors shall jointly and severally reimburse the Initial Purchasers for all reasonable out-of-pocket expenses (including fees and disbursements of counsel for the Initial Purchasers) incurred by the Initial Purchasers in connection with this Agreement and the proposed purchase of the Notes, and upon demand the Company and the Guarantors shall pay the full amount thereof to the Initial Purchasers. If this Agreement is terminated pursuant to Section 9 by reason of the default of one or more Initial Purchasers, the Company and the Guarantors shall not be obligated to reimburse any defaulting Initial Purchaser on account of those expenses.

12. Notices, etc. All statements, requests, notices and agreements hereunder shall be in writing, and:

(a) if to any Initial Purchasers, shall be delivered or sent by hand delivery, mail, telex, overnight courier or facsimile transmission to Barclays Capital Inc., 745 Seventh Avenue, New York, New York 10019, Attention: Syndicate Registration with a copy to Vinson & Elkins LLP, 1001 Fannin Street, Suite 2500, Houston, Texas 77002, Attention: Kathryn Wilson (Fax: (713) 615-5792), and with a copy, in the case of any notice pursuant to Section 8(c), to the Director of Litigation, Office of the General Counsel, Barclays Capital Inc., 745 Seventh Ave., New York, New York 10019;

(b) if to the Company or any Guarantor, shall be delivered or sent by mail, telex, overnight courier or facsimile transmission to Halcón Resources Corporation, 1000 Louisiana Street, Suite 6700, Houston, Texas 77002, Attention: Floyd Wilson, with a copy to Thompson & Knight LLP, 333 Clay Street, Suite 3300, Houston, Texas 77002, Attention: William T. Heller IV;

provided, however, that any notice to an Initial Purchaser pursuant to Section 8(c) shall be delivered or sent by hand delivery, mail, telex or facsimile or electronic transmission to such Initial Purchaser at its address set forth in its acceptance telex to Barclays Capital Inc., which address will be supplied to any other party hereto by Barclays Capital Inc. upon request. Any such statements, requests, notices or agreements shall take effect at the time of receipt thereof. The Company shall be entitled to act and rely upon any request, consent, notice or agreement given or made on behalf of the Initial Purchasers by Barclays Capital Inc.

(c) In accordance with the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), the Initial Purchasers are required to obtain, verify and record information that identifies their respective clients, including the Company, which information may include the name and address of their respective clients, as well as other information that will allow the Initial Purchasers to properly identify their respective clients.

13. Persons Entitled to Benefit of Agreement. This Agreement shall inure to the benefit of and be binding upon the Initial Purchasers, the Company, the Guarantors and their respective successors. This Agreement and the terms and provisions hereof are for the sole benefit of only those persons, except that the representations, warranties, indemnities and agreements of the Company and the Guarantors contained in this Agreement shall also be deemed to be for the benefit of the affiliates, directors, officers and employees of the Initial Purchasers and each person or persons, if any, controlling any Initial Purchaser within the meaning of Section 15 of the Securities Act. Nothing in this Agreement is intended or shall be construed to give any person, other than the persons referred to in this Section 13, any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision contained herein.

14. Survival. The respective indemnities, rights of contribution, representations, warranties and agreements of the Company, the Guarantors and the Initial Purchasers contained in this Agreement or made by or on behalf of them, respectively, pursuant to this Agreement, shall survive the delivery of and payment for the Notes and shall remain in full force and effect, regardless of any termination of this Agreement or any investigation made by or on behalf of any of them or any person controlling any of them.

15. Definition of the Terms “Business Day”, “Affiliate”, and “Subsidiary”. For purposes of this Agreement, (a) “business day” means any day on which the New York Stock Exchange, Inc. is open for trading, and (b) “affiliate” and “subsidiary” have the meanings set forth in Rule 405 under the Securities Act.

16. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of New York.



applicable law, any and all right to trial by jury in any legal proceeding arising out of or relating to this Agreement or the transactions contemplated hereby.

18. No Fiduciary Duty. The Company and the Guarantors acknowledge and agree that in connection with this offering, or any other services the Initial Purchasers may be deemed to be providing hereunder, notwithstanding any preexisting relationship, advisory or otherwise, between the parties or any oral representations or assurances previously or subsequently made by the Initial Purchasers: (a) no fiduciary or agency relationship between the Company, any Guarantor and any other person, on the one hand, and the Initial Purchasers, on the other, exists; (b) the Initial Purchasers are not acting as advisors, expert or otherwise, to the Company or the Guarantors, including, without limitation, with respect to the determination of the purchase price of the Notes, and such relationship between the Company and the Guarantors, on the one hand, and the Initial Purchasers, on the other, is entirely and solely commercial, based on arms-length negotiations; (c) any duties and obligations that the Initial Purchasers may have to the Company and the Guarantors shall be limited to those duties and obligations specifically stated herein; (d) the Initial Purchasers and their respective affiliates may have interests that differ from those of the Company and the Guarantors; and (e) the Company and the Guarantors have consulted their own legal and financial advisors to the extent they deemed appropriate. The Company and the Guarantors hereby waive any claims that the Company and the Guarantors may have against the Initial Purchasers with respect to any breach of fiduciary duty in connection with the Notes.

19. Counterparts. This Agreement may be executed in one or more counterparts and, if executed in more than one counterpart, the executed counterparts shall each be deemed to be an original but all such counterparts shall together constitute one and the same instrument.

20. Headings. The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Agreement.

If the foregoing correctly sets forth the agreement between the Company, the Guarantors, and the Initial Purchasers, please indicate your acceptance in the space provided for that purpose below.

Very truly yours,

HALCÓN RESOURCES CORPORATION

By: /s/ Floyd C. Wilson
Name: Floyd C. Wilson
Title: Chief Executive Officer

GREAT PLAINS PIPELINE COMPANY
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 HLP GULF STATES, LLC,
its General Partner
HLP GULF STATES, LLC
HRC ENERGY HOLDINGS (LA), INC.
HRC ENERGY LOUISIANA, LLC
HRC ENERGY RESOURCES (LAFOURCHE), INC.
HRC ENERGY RESOURCES (WV), INC.
LEOPARD SUB I, INC.
LEOPARD SUB II, LLC
PONTOTOC PRODUCTION COMPANY, INC.

By: /s/ Floyd C. Wilson
Name: Floyd C. Wilson
Title: Chief Executive Officer

Accepted:

BARCLAYS CAPITAL INC.
For itself and as Representative of the several
Initial Purchasers named on Schedule I hereto.

By: /s/ Paul Cugano
Authorized Signatory



SCHEDULE I

<table><tr><td></td><td>Principal Amount of Notes to be Purchased</td></tr><tr><td>Initial Purchasers</td><td>$ 281,250,000</td></tr><tr><td>Barclays Capital Inc.</td><td>$ 105,000,000</td></tr><tr><td>Goldman, Sachs &amp; Co.</td><td>105,000,000</td></tr><tr><td>J.P. Morgan Securities LLC</td><td>75,000,000</td></tr><tr><td>Wells Fargo Securities, LLC</td><td>67,500,000</td></tr><tr><td>BMO Capital Markets Corp.</td><td>37,500,000</td></tr><tr><td>RBC Capital Markets, LLC</td><td>37,500,000</td></tr><tr><td>Capital One Southcoast, Inc.</td><td>37,500,000</td></tr><tr><td>SunTrust Robinson Humphrey, Inc.</td><td>33,750,000</td></tr><tr><td>Global Hunter Securities, LLC</td><td>7,500,000</td></tr><tr><td>Total</td><td>$ 750,000,000</td></tr></table>

SCHEDULE II

LIST OF GUARANTORS

<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 Holdings (LA), Inc.</td><td>Delaware</td></tr><tr><td>HRC Energy Resources (Lafourche), Inc.</td><td>Louisiana</td></tr><tr><td>HRC Energy Louisiana, LLC</td><td>Delaware</td></tr><tr><td>Pontotoc Production Company, Inc.</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>HLP Gulf States, LLC</td><td>Oklahoma</td></tr><tr><td>Great Plains Pipeline Company</td><td>Delaware</td></tr><tr><td>Leopard Sub I, Inc.</td><td>Colorado</td></tr><tr><td>Leopard Sub II, 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></table>

SCHEDULE III



## $750,000,000 9.75% Senior Notes due 2020

## June 29, 2012

## Pricing Supplement

Pricing Supplement dated June 29, 2012 to the Preliminary Offering Memorandum dated June 25, 2012 of Halcón Resources Corporation. This Pricing Supplement is qualified in its entirety by reference to the Preliminary Offering Memorandum. The information in this Pricing Supplement supplements the Preliminary Offering Memorandum and supersedes the information in the Preliminary Offering Memorandum to the extent it is inconsistent with the information in the Preliminary Offering Memorandum. Capitalized terms used in this Pricing Supplement but not defined have the meanings given them in the Preliminary Offering Memorandum.

<table><tr><td>Issuer</td><td>Halcón Resources Corporation</td></tr><tr><td>Guarantors</td><td>The notes will be guaranteed on a senior unsecured basis by the Issuer&#x27;s current subsidiaries and by any future restricted subsidiaries that guarantee the Issuer&#x27;s indebtedness under a credit facility.</td></tr><tr><td>Title of Securities</td><td>9.75% Senior Notes due 2020 (the &quot;Notes&quot;)</td></tr><tr><td>Aggregate Principal Amount</td><td>$750,000,000</td></tr><tr><td>Distribution</td><td>144A / Regulation S with Registration Rights</td></tr><tr><td>Maturity Date</td><td>July 15, 2020</td></tr><tr><td>Issue Price</td><td>98.646%</td></tr><tr><td>Coupon</td><td>9.75%</td></tr><tr><td>Yield to Maturity</td><td>10.00%</td></tr><tr><td>Interest Payment Dates</td><td>January 15 and July 15 of each year, beginning on January 15, 2013</td></tr><tr><td>Record Dates</td><td>January 1 and July 1 of each year</td></tr><tr><td>Ratings*</td><td>B3 (Moody&#x27;s) / CCC+ (S&amp;P)</td></tr><tr><td>Trade Date</td><td>June 29, 2012</td></tr><tr><td>Settlement Date</td><td>July 16, 2012 (T+10)</td></tr></table>

We expect that delivery of the Notes will be made against payment therefor on or about the 10 \( ^{th} \)  business day following the date of confirmation of orders with respect to the Notes (this settlement cycle being referred to as “T+10”). Under Rule 15c6-1 of the Commission under the Exchange Act, trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade the Notes on the trade date or the following six trading days will be required, by virtue of the fact that the Notes initially will settle in T+10, to specify an alternative settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of the Notes who wish to trade the Notes before their delivery should

consult their own advisor.

On or after July 15, 2016, at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest, if any, on the Notes redeemed during the twelve-month period indicated beginning on July 15 of the years indicated below:

<table><tr><td>Year</td><td>Price</td></tr><tr><td>2016</td><td>104.875%</td></tr><tr><td>2017</td><td>102.438%</td></tr><tr><td>2018 and thereafter</td><td>100.000%</td></tr></table>

Up to 35% at 109.750% prior to July 15, 2015

Make-whole redemption at Treasury Rate + 50 basis points prior to July 15, 2016

101% plus accrued and unpaid interest (following a Rating Decline)

Barclays Capital Inc. Goldman, Sachs & Co. J.P. Morgan Securities LLC Wells Fargo Securities, LLC BMO



Co-Managers Capital One Southcoast, Inc. SunTrust Robinson Humphrey, Inc. Global Hunter Securities, LLC

CUSIP Numbers Rule 144A: 40537Q AA8 Regulation S: U4057P AA3

ISIN Numbers Rule 144A: US40537QAA85 Regulation S: USU4057PAA31

Denominations Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof

 \( ^{*} \) Note: A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time.

Additional Changes to the Preliminary Offering Memorandum:

Covenant Changes

The following changes will be made to the covenants described under the heading “Description of the Notes” on the specified pages in the Preliminary Offering Memorandum:

- On page 63, deleting the third paragraph under “— Optional Redemption,” which provided for optional redemption of the notes at 110% of par plus accrued interest in the event of specified change of control events.

• On page 71, changing the ACNTA percentage in clause (1)(b) of the definition of Permitted Indebtedness from 25.0% to 30.0%.

• On page 72, changing the ACNTA percentage in clause (14) of the definition of Permitted Indebtedness from 1.5% to 2.0%.

• On page 73, changing the ACNTA percentage in clause (15) of the definition of Permitted Indebtedness from 1.5% to 2.0%.

• On page 100, changing the ACNTA percentage in clause (16) of the definition of Permitted Investments from 1.5% to 2.0%.

• On page 102, changing the ACNTA percentage in clause (17) of the definition of Permitted Liens from 0.5% to 1.0%.

## Use of Proceeds

We estimate the net proceeds of this offering will be approximately $725 million after deducting the initial purchasers' discounts and commissions and before estimated offering expenses. We intend to use the net proceeds from this offering to fund the cash consideration for the GeoResources Merger and for general corporate purposes, including to fund acquisitions and capital expenditures.

## Capitalization

The “Capitalization” table on page 42 of the Preliminary Offering Memorandum is amended to read as follows:

<table><tr><td rowspan="3"></td><td colspan="3">As of March 31, 2012</td></tr><tr><td>Historical</td><td colspan="2">Pro Forma</td></tr><tr><td colspan="3">(In millions)</td></tr><tr><td>Cash and cash equivalents (1)(2)</td><td>$</td><td>685.8</td><td>$</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td></tr><tr><td>Revolving credit facility (3)</td><td>$</td><td>—</td><td>$</td></tr><tr><td>8.0% senior unsecured convertible note due 2017 (4)</td><td></td><td>235.5</td><td></td></tr><tr><td>9.75% senior notes due 2020 offered hereby</td><td></td><td>—</td><td></td></tr><tr><td>Total long-term debt</td><td>$</td><td>235.5</td><td>$</td></tr><tr><td>Stockholders&#x27; Equity</td><td></td><td></td><td></td></tr><tr><td>Preferred stock (5)</td><td>$</td><td>298.2</td><td>$</td></tr><tr><td>Common stock, $0.0001 par value, 99.4 million shares outstanding actual and 171.6 million shares outstanding pro forma</td><td></td><td>—</td><td></td></tr><tr><td>Additional paid-in capital</td><td></td><td>633.6</td><td></td></tr><tr><td>Treasury stock</td><td></td><td>(9.3)</td><td></td></tr><tr><td>Accumulated deficit</td><td></td><td>(249.6)</td><td></td></tr><tr><td>Total stockholders&#x27; equity</td><td>$</td><td>672.9</td><td>$</td></tr><tr><td>Total capitalization</td><td>$</td><td>908.3</td><td>$</td></tr></table>



This material is strictly confidential and has been prepared by the Issuer solely for use in connection with the proposed offering of the securities described in the Preliminary Offering Memorandum. This material is personal to each of the issuer and does not constitute an offer to any other person or the public generally to subscribe for or otherwise acquire the securities. Please refer to the Preliminary Offering Memorandum for a complete description.

The securities have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), and are being offered only to (1) "qualified institutional buyers" as defined in Rule 144A under the Securities Act and (2) outside the United States to non-U.S. persons in compliance with Regulation S under the Securities Act, and this communication is only being distributed to such persons.

This communication is not an offer to sell the securities and it is not a solicitation of an offer to buy the securities in any jurisdiction to any person to whom it is unlawful to make such offer or solicitation in such jurisdiction.

Any disclaimers or notices that may appear on this Pricing Supple ment below the text of this legend are not applicable to this Pricing Supple ment and should be disregarded. Such disclaimers may have been electronically generated as a result of this Pricing Supple ment having been sent via, or posted on, Bloomberg or another electronic mail system.

## SCHEDULE IV

A. Insert list of each document provided as an amendment or supplement to the Preliminary Offering Memorandum.

B. Insert list of any “road show” materials that are Free Writing Offering Documents.



## Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends
(In thousands, except ratios)

<table><tr><td rowspan="2"></td><td colspan="6">Years Ended December 31,</td></tr><tr><td>2012</td><td>2011</td><td>2010</td><td>2009</td><td>2008</td><td></td></tr><tr><td>Earnings:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>(Loss) income before income taxes</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (67,066)</td><td>$ 5,399</td><td>$ 3,412</td><td>$ (74,730)</td><td>$ (221,636)</td><td></td></tr><tr><td>Adjustments:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity investment income</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>373</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Interest capitalized</td><td>53,492</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>(Loss) income before income taxes, as adjusted</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ (13,201)</td><td>$ 5,399</td><td>$ 3,412</td><td>$ (74,730)</td><td>$ (221,636)</td><td></td></tr><tr><td>Fixed charges</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>86,589</td><td>17,808</td><td>23,087</td><td>19,021</td><td>24,588</td><td></td></tr><tr><td>Total earnings</td><td>$ 73,388</td><td>$ 23,207</td><td>$ 26,499</td><td>$ (55,709)</td><td>$ (197,048)</td><td></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</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 85,372</td><td>$ 17,373</td><td>$ 22,655</td><td>$ 18,590</td><td>$ 24,182</td><td></td></tr><tr><td>Rental expense representative of interest</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>1,217</td><td>435</td><td>432</td><td>431</td><td>406</td><td></td></tr><tr><td>Total fixed charges</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 86,589</td><td>$ 17,808</td><td>$ 23,087</td><td>$ 19,021</td><td>$ 24,588</td><td></td></tr><tr><td>Ratio of earnings to fixed charges</td><td>—(1)</td><td>1.3</td><td>1.1</td><td>—(3)</td><td>—(4)</td><td></td></tr><tr><td>Total fixed charges</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pre-tax preferred dividend requirements</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>88,445</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total fixed charges plus preference dividends</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>$ 175,034</td><td>$ 17,808</td><td>$ 23,087</td><td>$ 19,021</td><td>$ 24,588</td><td></td></tr><tr><td>Ratio of earnings to combined fixed charges and preference dividends</td><td>—(2)</td><td>1.3</td><td>1.1</td><td>—(3)</td><td>—(4)</td><td></td></tr></table>

(1) Due to the Company's loss in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $13.2 million to achieve a coverage ratio of 1:1.

(2) Due to the Company's loss in 2012, the ratio coverage was less than 1:1. The Company must generate additional earnings of $101.6 million to achieve a coverage ratio of 1:1.

(3) Due to the Company's loss in 2009, the ratio coverage was less than 1:1. The Company must generate additional earnings of $74.7 million to achieve a coverage ratio of 1:1.

(4) Due to the Company's loss in 2008, the ratio coverage was less than 1:1. The Company must generate additional earnings of $221.6 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 Holdings (LA), Inc.</td><td>Delaware</td></tr><tr><td>HRC Energy Resources (Lafourche), Inc.</td><td>Louisiana</td></tr><tr><td>HRC Energy Louisiana, LLC</td><td>Delaware</td></tr><tr><td>Pontotoc Production Company, Inc.</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>HLP Gulf States, LLC</td><td>Oklahoma</td></tr><tr><td>Halcón Geo 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>G3 Energy, LLC</td><td>Colorado</td></tr><tr><td>G3 Operating, LLC</td><td>Colorado</td></tr><tr><td>Catena 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>Southern Bay Energy, LLC</td><td>Texas</td></tr><tr><td>Southern Bay Louisiana LLC</td><td>Texas</td></tr><tr><td>Southern Bay Operating, L.L.C.</td><td>Texas</td></tr><tr><td>AROC (Texas), Inc.</td><td>Texas</td></tr><tr><td>Great Plains Pipeline Company</td><td>Delaware</td></tr><tr><td>Western Star Drilling Company</td><td>North Dakota</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 Nos. 333-149319, 333-180243, 333-182996, 333-183560 and 333-183843 on Form S-3, Registration Statement Nos. 333-137311, 333-151428, 333-166893, 333-180099 and 333-183559 on Form S-8, and Registration Statement No. 333-181537 on Form S-4 of Halcón Resources Corporation of our report dated February 28, 2013, 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, 2012.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2013



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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



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Exhibit 23.2

## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-137311, 333-151428, 333-166893, 333-180099 and 333-183559); on Form S-3 (File Nos. 333-149319, 333-180243, 333-182996, 333-183560 and 333-183843); and on Form S-4 (File No. 333-181537), of Halcón Resources Corporation (formerly RAM Energy Resources, Inc., a Delaware corporation) of our report dated March 5, 2012 (except for effect of the restatement discussed in Note 2, as to which the date is February 28, 2013), with respect to the consolidated financial statements of Halcón Resources Corporation as of December 31, 2011, and for the two years in the period ended December 31, 2011 included in this Annual Report on Form 10-K for the year ended December 31, 2012.

/s/ UHY LLP

Houston, Texas
February 28, 2013



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Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



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Exhibit 23.3

## 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 January 31, 2013, included in the Annual Report on Form 10-K of Halcón Resources Corporation (the "Company") for the fiscal year ended December 31, 2012, 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 January 31, 2013, into the Registration Statements on Form S-3 (File Nos. 333-149319, 333-180243, 333-182996, 333-183560 and 333-183843), Form S-8 (File Nos. 333-137311, 333-151428, 333-166893, 333-180099, and 333-183559), and Form S-4 (File No. 333-181537) filed with the U.S. Securities and Exchange Commission.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ J. CARTER HENSON, JR.

J. Carter Henson, Jr., P.E.

Senior Vice President

Houston, Texas

February 28, 2013



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Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS



## CONSENT OF INDEPENDENT PIEROLEM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm and to the inclusion of information contained in our report dated February 7, 2012 in the Annual Report on Form 10-K of Halcón Resources Corporation (the "Company") for the year ended December 31, 2012. We also hereby consent to the incorporation by reference in the Registration Statements previously filed by the Company on Form S-8 (File Nos. 333-137311, 333-151428, 333-166893, 333-180099 and 333-183559), Form S-3 (File Nos. 333-149319, 333-180243, 333-182996, 333-183560 and 333-183843) and on Form S-4 (File No. 333-181537) of the references to our firm and to the inclusion of information contained in our report dated February 7, 2012.

FORREST A. GARB & ASSOCIATES, INC.

By: /s/ WILLIAM D. HARRIS III

William D. Harris III
CEO / President

Dallas, Texas
February 28, 2013



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Exhibit 23.4

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 Energy 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, 2013

By: /s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board and
Chief Executive Officer



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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, 2013

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 and Chief Executive Officer, 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, 2012 (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, 2013

/s/ FLOYD C. WILSON

Floyd C. Wilson
Chairman of the Board and Chief Executive Officer

February 28, 2013

/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, 2012, 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, 2012, to be:

<table><tr><td rowspan="2">Category</td><td colspan="3">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><td>Present Worth at 10%</td></tr><tr><td>Proved Developed Producing</td><td>33,472.6</td><td>2,878.2</td><td>53,285.5</td><td>2,080,783.7</td><td>1,312,770.3</td></tr><tr><td>Proved Developed Non-Producing</td><td>4,956.2</td><td>294.6</td><td>5,499.2</td><td>296,833.1</td><td>176,064.6</td></tr><tr><td>Proved Undeveloped</td><td>48,948.8</td><td>2,210.7</td><td>37,360.2</td><td>2,193,972.2</td><td>828,238.3</td></tr><tr><td>Total Proved</td><td>87,377.6</td><td>5,383.5</td><td>96,144.9</td><td>4,571,589.0</td><td>2,317,073.2</td></tr></table>

The oil reserves 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 2012. For oil and NGL volumes, the average Wall Street Journal West Texas Intermediate spot price of $94.71 per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price 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 $93.48 per barrel of oil, $39.19 per barrel of NGL, and $3.494 per MCF of gas.

Operating costs used in this report are based on operating expense records of Halcón. 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. Headquarters general and administrative overhead expenses of Halcón are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are held constant throughout the lives of the properties.

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 held constant to the date of expenditure.

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 gas 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 gas production.

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, 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, seismic data, 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 behind-pipe zones, non-producing zones, 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. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. 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

By: /s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

By: /s/ J. Carter Henson, Jr.
J. Carter Henson, Jr.
Texas P.E. 73964
Senior Vice President

Date Signed: January 31, 2013

By: /s/ Mike K. Norton
Mike K. Norton
Texas P.G. 441
Senior Vice President

Date Signed: January 31, 2013

By: /s/ John R. Cliver
John R. Cliver
Louisiana P.E. 37090
Petroleum Engineer

Date Signed: January 31, 2013

JCH:JLM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.



# 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.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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.

(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:

(1) 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.

(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.

(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) Reservoir. 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.

(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 producibility 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.