EDGAR 10-K Filing

Company CIK: 1326089
Filing Year: 2021
Filename: 1326089_10-K_2021_0001558370-21-003806.json

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ITEM 1. BUSINESS
Item 1. Business.
General
We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations consist primarily of drilling and production from unconventional horizontal wells targeting the Eagle Ford formation in South Texas.
Bankruptcy Proceedings under Chapter 11
Restructuring Support Agreement
On March 9, 2021, we entered into a Restructuring Support Agreement (the “RSA”) with (i) Toronto Dominion (Texas) LLC, as agent pursuant to the Revolving Facility (as defined below), (ii) the lenders party to that certain Credit Agreement, dated as of July 18, 2018 (as amended, modified, or supplemented), (the “Senior Lenders” and such facility, the “Revolving Facility”), (iii) Morgan Stanley Capital Administrators Inc. as agent pursuant to the Term Loan Facility (as defined below), and (iv) the lenders party to that certain Amended & Restated Term Loan Credit Agreement, dated as of April 23, 2018 (as amended, modified, or supplemented from time to time), (the “Term Lenders” and such facility, the “Term Loan Facility”).
The RSA contemplates, among other things:
• Funding of the Cases. The Chapter 11 Cases (as defined below) will be financed by a new up to $50 million junior priority debtor-in-possession credit facility (the “DIP Facility”) provided by certain of the Term Lenders (the “DIP Lenders”).
• Exit Facilities. On the effective date of the Prepackaged Plan (as defined below), we will enter into the following:
◾ Exit RBL Facility. Sundance and its subsidiaries and each Senior Lender that elects to participate in will enter into a new reserve-based lending revolving credit facility having a borrowing base of $107.5 million (inclusive of a $20.0 million letter of credit subfacility) (the “Exit RBL Facility”).
◾ Exit Second Out Term Loan Facility. Sundance and its subsidiaries and each Senior Lender that elects to participate in the Exit RBL Facility will enter into the Exit Second Out Term Loan Facility, which will be a new first lien second out term loan facility having a principal amount of $30.0 million.
• Prepetition Revolving Facility Claims.
◾ Each holder of a Prepetition Revolving Facility claim that votes to accept the Prepackaged Plan will receive: (i) its pro rata share of the loans under the Exit RBL Facility; (ii) its pro rata share of the loans under the Exit Second Out Term Loan Facility; and (iii) its pro rata share of the cash paydown.
• Prepetition Term Loan Claims. Each holder of a Prepetition Term Loan claim will receive its pro rata share of 100% of the new common equity interests of Sundance (subject to dilution by a 6% management incentive plan).
• General Unsecured Claims. The legal, equitable, and contractual rights of holders of general unsecured claims will be unaltered by the Prepackaged Plan. On or as soon as practicable after the earliest to occur of the Effective Date of the Prepackaged Plan and the date a general unsecured claim becomes due in the ordinary course of business, each holder of a general unsecured claim will receive payment in full in cash on account of its general unsecured claim or such other treatment as would render such claim unimpaired.
• All existing common stock in Sundance (the “Old Parent Interests”) will be cancelled, and each holder of an Old Parent Interest will not receive any distribution or retain any property on account of such Old Parent Interest.
Upon emergence from bankruptcy, we expect that we will no longer be a publicly traded company.
Voluntary Chapter 11 Bankruptcy Proceedings
On March 9, 2021 (the “Petition Date”), the Company and all of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, collectively, the “Chapter 11 Cases”) under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to pursue the Joint Prepackaged Plan of Reorganization for Sundance Energy Inc. and Its Affiliate Debtors Under Chapter 11 of the Bankruptcy Code (as amended, restated, supplemented or otherwise modified from time to time, the “Prepackaged Plan”). The Debtors are authorized to operate their businesses as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
The Bankruptcy Court has granted on a final basis all of the first day motions filed by the Debtors seeking relief that would minimize the impact of the Chapter 11 Cases on the Company’s operations, customers and employees. As a result, the Company is not only authorized to conduct business activities in the ordinary course and generally pay all associated obligations for the period following the Petition Date without further Bankruptcy Court approval, but it is also currently authorized to pay and has paid, subject to certain limitations, obligations that arose prior to the Petition Date related to taxes, insurance, surety bonds, employee wages and benefits, services and supplies provided by vendors in the ordinary course of business and mineral interests held by royalty holders and other partners. In general, during the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. As a result of the automatic stay under the Bankruptcy Code, which became effective upon the commencement of the Chapter 11 Cases, most judicial or administrative actions against the Company by its creditors to collect on or otherwise exercise rights or remedies with respect to claims that arose before the Petition Date are stayed during the pendency of the Chapter 11 Cases.
A hearing to consider confirmation of the Prepackaged Plan and final approval of the Debtors’ related disclosure statement is currently scheduled to begin on April 19, 2021.
For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with our Chapter 11 cases as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.
For a further description of these matters, see Note 15 - Subsequent Events.
Strategy
Our strategy is to acquire and/or develop assets where we are the operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. We also believe that serving as operator allows us to control the drilling, completion, operations and marketing of sold volumes. Upon emergence from bankruptcy, we plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory. Throughout 2020, we continued to realize cost improvement by reducing our operating costs and per well drilling and completion costs. Upon emergence from bankruptcy, we intend to manage our liquidity by scaling our 2021 capital program to remain within our operating cash flow.
Oil and Natural Gas Properties
Description of Properties
All of our operations and assets are located in the Eagle Ford formation in South Texas. Since entering the Eagle Ford play in 2014, we have built a strong assets base that includes over 38,000 net acres targeting the Eagle Ford, through a combination of property acquisitions and development of proved reserves. Our 2018 acquisition of approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texas has positioned us to compete more effectively in this market by offering economies of scale and positioning us to compete for further acquisition opportunities in this area. As of December 31, 2020, we operated 95% of our net producing wells and our average working interest in our operated wells was approximately 96%.
Estimated Proved Reserves
The following table presents summary information regarding our estimated net proved oil, natural gas and NGL reserves as of the dates indicated. The estimates of our net proved reserves as of December 31, 2020 and 2019 are based on the reserve reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineers, in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of December 31, 2020 and 2019, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report. All of the reserves were located in the Eagle Ford.
As of December 31,
Estimated proved reserves:
Oil (MBbls)
28,898
62,788
Natural gas (MMcf)
50,145
120,904
NGL (MBbls)
8,171
18,134
Total estimated proved reserves (MBoe)
45,427
101,072
Estimated proved developed reserves:
Oil (MBbls)
12,156
16,101
Natural gas (MMcf)
22,667
26,930
NGL (MBbls)
3,401
4,022
Total estimated proved developed reserves (MBoe)
19,335
24,611
Estimated proved undeveloped reserves:
Oil (MBbls)
16,742
46,687
Natural gas (MMcf)
27,478
93,974
NGL (MBbls)
4,770
14,112
Total estimated proved undeveloped reserves (MBoe)
26,092
76,461
PV-10 (in thousands)
$
231,094
$
752,593
Standardized Measure (in thousands)
$
230,804
$
675,099
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil, natural gas and NGLs 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. As a result, the estimates of different engineers may vary and are subject to change with additional data. Furthermore, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, operational changes, regulatory changes, environmental protection, prices and costs, and reservoir performance. Please read Part I, Item IA. “Risk Factors” of this annual report.
Additional information regarding our proved reserves can be found in our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report.
PV-10
Certain of our oil and natural gas reserve disclosures included in this annual report are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 may be considered a non-GAAP financial measure as defined by the SEC because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies. Investors should be cautioned that neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.
The following table provides a reconciliation of Standardized Measure to PV-10 (in thousands):
As of December 31,
Standardized Measure
$
230,804
$
675,099
Present value of future income tax discounted at 10% (1)
77,494
PV-10 of proved reserves
$
231,094
$
752,593
(1) As of December 31, 2020 the estimated taxable income to be generated from 2020 year-end reserves was expected to be almost fully offset by net operating loss carryforwards.
Proved Undeveloped Reserves
Annually, management develops a five-year development plan based on our best available data at the time the plan is developed. Our five-year plan incorporates a development plan for converting PUD reserves to proved developed. The development plan includes only PUD reserves that we are reasonably certain will be spud within five years of initial booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns, commodity prices and cost forecasts and recent drilling and well performance. Our five-year development plan generally does not contemplate a uniform conversion of our PUD reserves to proved developed. Since the beginning of the COVID-19 pandemic and at December 31, 2020, our strategy was to discontinue development, which would allow cash flow to accumulate to improve liquidity. Upon emergence from bankruptcy, we plan to use accumulated cash flow to fund an increased pace of development in later years, such that all remaining proved undeveloped locations would be developed within the five-year period.
Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating the factors noted above, as well as realized commodity prices, cost and availability of services and equipment, acquisition and divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, we reclassify those PUD reserve locations to unproved reserve categories. In addition, PUD locations and reserves may be removed from the development plan prior to their five-year expiration as a result of changes in our development plan related to factors discussed above.
The following table summarizes our changes in PUDs during the years ended December 31, 2020:
PUD Reserves
(MBOE)
As of December 31, 2019
76,461
Extensions and discoveries
3,945
Sales of reserves in place
-
Revisions of prior estimates
(51,207)
Conversion of proved undeveloped to proved developed
(3,107)
As of December 31, 2020
26,092
During the year ended December 31, 2020, we incurred capital expenditures of approximately $35.5 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our proved properties for the period were primarily related to infrastructure and installation of artificial lift on proved developed producing reserves.
As of December 31, 2020, our proved undeveloped reserves were approximately 26,092 MBoe, a decrease of 50,369 MBoe over our December 31, 2019 proved undeveloped reserves estimate of approximately 76,461 MBoe. The change primarily resulted from approximately 118 proved undeveloped locations being removed as we expect them to be drilled outside the 5-year window as a result of our slowed development pace. We scaled back our development program due to lower liquidity and operating cash flow, as a result of the lower price environment relative to December 31, 2019. These revisions do not represent the elimination of recoverable hydrocarbons physically in place, as they may be developed in the future.
Independent Reserve Engineers
Our reserve estimates are calculated by Ryder Scott as of December 31, 2020 in accordance with SEC guidelines. The reserve estimates are based on, and fairly represent, information and supporting documentation prepared by, or under supervision of Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado (Colorado No. 44720) and Texas (Texas No. 100578) with over 15 years of practical experience in estimation and evaluation of petroleum reserves. Mr. Gardner meets or exceeds 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. We believe that he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Mr. Gardner consents to the inclusion in this report of the information and context in which it appears.
Internal Controls over Reserves Estimation Process
The primary inputs into the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. Our technical team consists of an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates.
Our board of directors has also established a Reserves Committee to assist with monitoring (i) the integrity of our oil, natural gas, and NGL reserves, (ii) the independence, qualifications and performance of our independent reservoir engineers, and (iii) our compliance with legal and regulatory requirements. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by the Reserves Committee, our internal petroleum engineers and management.
Our senior reservoir engineer is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and year-end third-party report of our reserves estimates. He received his Masters of Science and Ph.D. in Petroleum Engineering from the Colorado School of Mines. He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers. The senior reservoir engineer currently reports directly to our Chief Operating Officer.
Technology Used to Establish Estimates of Proved Reserves
Under SEC rules, proved reserves are those quantities of oil and natural gas that 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, under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. 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.
To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed or reviewed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data, well test data, simulation, and statistical methods. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using both volumetric estimates and performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.
Acreage
We had the following developed, undeveloped and total acres as of December 31, 2020:
Developed
Undeveloped
Total
Gross
Net
Gross
Net
Gross
Net
Eagle Ford (1)
16,844
14,732
36,308
27,720
53,152
42,452
(1) Includes 7,617 gross (3,808 net) undeveloped acres located in Texas, targeting non-Eagle Ford formations.
Most of our undeveloped leasehold acreage is currently held by production and not subject to expiration. Approximately 4,500 net acres is currently held by production, but may be subject to future drilling obligations at certain oil prices.
Production and Pricing
The following tables set forth information regarding our total production and average daily production for the periods indicated from our operating areas:
Year ended December 31,
Net Sales Volumes:
Oil (MBbls)
2,104.8
3,076.6
2,256.0
Natural gas (MMcf)
3,969.0
5,767.8
4,533.6
NGL (MBbls)
539.8
797.8
496.6
Oil equivalent (MBoe)
3,306.1
4,835.7
3,508.2
Average daily volumes (Boe/d)
9,033
13,248
9,612
Average Sales Price
Oil (per Bbl)
$
36.36
$
57.81
$
62.16
Natural gas (per Mcf)
1.99
2.18
2.65
NGL (per MBbls)
13.69
16.51
25.51
Average equivalent price (per Boe)
27.77
42.10
47.01
Expenses (per Boe):
Lease operating and workover expense
$
7.62
$
6.96
$
9.68
Gathering, processing and transportation expense (1)
6.15
3.53
2.46
Production tax expense
1.65
2.37
2.64
Total operating expense
$
15.42
$
12.86
$
14.78
(1) Includes minimum revenue commitment deficiency fees of $2.42, $0.49, and $0.79 per Boe for the years ended December 31, 2020, 2019 and 2018, respectively.
Producing Wells
We had the following producing wells as of December 31, 2020:
Natural Gas
Oil Wells
Wells
Total Wells
Gross
Net
Gross
Net
Gross
Net
Eagle Ford
253.0
222.6
2.5
264.0
225.1
Drilling Activity
The following table summarizes our drilling activity for the fiscal years ended December 31, 2020, 2019 and 2018:
Year ended December 31,
Gross
Net
Gross
Net
Gross
Net
Development wells
Oil
8.2
22.3
23.0
Natural Gas
-
-
-
-
-
-
Dry
-
-
-
-
-
-
Total Wells
8.2
22.3
23.0
We did not drill any exploratory wells during the years ended December 31, 2020, 2019 and 2018.
Operations
General
We operated 95% of our production for the year ended December 31, 2020. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis.
Marketing and Customers
For the year ended December 31, 2020, purchases by two customers each accounted for over 10% of our total sales revenues. Our largest customer, a large midstream company and production purchaser accounted for approximately 66% of our 2020 revenue. We have a long-term contract in place with this customer, under which we are subject to minimum revenue commitments (“MRCs”) for gathering, processing, transportation and marketing services, with $32.2 million remaining through 2022 (described more below in Part I, Item 1. “Business” under “Delivery Commitments”). Our second largest customer, a large physical trading and logistics company, accounted for approximately 22% of our 2020 revenue. Our agreement with this purchaser ended on December 31, 2020, and was replaced by a marketing agreement with another large physical trading company.
The oil and natural gas that we sell are commodities for which there are a large number of potential buyers. Because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.
The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include global economic and political conditions, the level of demand for oil and natural gas, the price and quantity of imports of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions and natural disasters, the outbreak of pandemic or contagious disease, governmental regulations, oil and natural gas speculation, actions of the Organization of Petroleum Exporting Companies (“OPEC”), technological advances and the price and availability of alternative fuels. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months.
Delivery Commitments
In conjunction with our 2018 acquisition, we entered into contracts with a large midstream company to provide gathering, processing, transportation and marketing of hydrocarbon production for the acquired properties. The contracts contain MRCs that requires us to pay minimum annual fees related to gathering, processing, transportation and marketing. Volumetric fixed fees are expensed as incurred and settled with the midstream company on a monthly basis. The following table summarizes the remaining MRC (in thousands) by year:
Total
Hydrocarbon gathering and handling agreement
$
13,925
$
6,541
$
20,466
Crude oil and condensate purchase agreements
7,488
4,230
11,718
Total MRC
$
21,413
$
10,771
$
32,184
If, at the end of any calendar year during the term of the contract, we fail to satisfy our MRC with the monthly settlements paid during the year, we are required to pay a deficiency payment equal to the shortfall. If the volumes and associated fees exceed the MRC in any contractual year, the overage can be applied to reduce the future shortfalls, if any.
Current production from the producing wells dedicated under these agreements is not sufficient to meet the MRC for the hydrocarbon gathering and handling agreement and we have realized shortfalls under the hydrocarbon gathering and handling agreement in 2018, 2019 and 2020. Our ability to meet our commitments in future periods will depend on our pace of development through the term of the contract. Our development plan is subject to a number of risks, many of which are not within our control.
Competition
The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that have greater resources than we do. 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 and obtaining drilling rigs, completion crews and other services. Our competitors may be able to pay more for productive crude oil and natural gas properties and undeveloped prospects, or bid for and purchase a greater number of properties and prospects than our financial resources permit.
There is also competition between producers of oil and natural gas and other industries producing alternative 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 state, local and the U.S. government agencies. However, it is not possible to predict the nature of any such legislation or regulation that 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. Our larger competitors may be able to better absorb the burden of existing and changing federal, state or local laws and regulations than we can, which would adversely impact our competitive position.
Seasonality of Business
We do not believe that the pricing of our crude oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.
Title to Properties
Title to our properties are subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of our business.
As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which generally include a review of title records and the preparation of title opinions by outside legal counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Government Regulations
Nearly every aspect of our business is subject to expansive federal, state, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of doing business and consequently could affect our profitability. However, we do not believe that we are affected to a materially greater or lesser extent than others in our industry.
Regulation of Production
The State of Texas, the state where we conduct operations and own nearly all of our oil and gas assets, has adopted laws and regulations governing the exploration for and production of oil, gas, and NGLs, including laws and regulations requiring permits for the drilling of wells, imposing bond requirements in order to drill or operate wells, governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells. Our operations are also subject to Texas conservation laws and regulations, including regulations governing the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, and the unitization or pooling of oil and gas properties. In addition, Texas conservation laws establish maximum rates of production from oil and gas wells, generally limit or prohibit the venting or flaring of gas, and may impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC’s current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC regulations continue to affect the midstream and transportation segments of the industry, and thus can indirectly affect the sales prices we receive for gas production.
Environmental, Health and Safety Matters
Oil, natural gas and NGL exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, including requirements to:
● obtain permits to conduct regulated activities;
● limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
● restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;
● initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;
● apply specific health and safety criteria addressing worker protection; and
● impose substantial liabilities for pollution resulting from operations.
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, causing our operators to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
Uncertainty about the future course of regulation exists because of the recent change in U.S. presidential administrations. In January 2021, the current administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments may be modified or rescinded. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” Recommendations from the Working Group are due beginning June 1, 2021, and final recommendations no later than January 2022. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas. Also in January 2021, the current administration issued an executive order focused on addressing climate change. Among other things, that executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directs the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending.
Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities on our properties and, as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties are subject.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the Environmental Protection Agency (“EPA”) interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance. Comparable state statutes may include petroleum in the definition of hazardous substance.
Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA.
We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes under RCRA. RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.
Air Emissions
The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants, including greenhouse gases, from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, report emissions, or utilize specific equipment or technologies to control emissions. CAA rules may require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment and implementing additional emissions testing and monitoring. These requirements have the potential to delay or increase the cost of the development of oil and natural gas projects. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs or negatively impact our production and operations. For example, in 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (“ppb”) to 70 ppb. In December 2018 and again in December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS ozone standard. However, in January 2021, the Biden administration issued an executive order calling on the EPA to, among other things, propose a Federal Implementation Plan for ozone standards for California, Connecticut, New York, Pennsylvania and Texas by January 2022. If areas in which we operate are designated as nonattainment or if the EPA were to further reduce ozone standards, bringing areas in which we operate into nonattainment, states that contain any areas designated nonattainment, and any tribes that choose to do so, are required to develop state implementation plans demonstrating how the area will attain the standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. Similar initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels.
Additionally, the EPA has established new air emission control requirements for oil, natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012, if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves.
In 2012 and 2016, the EPA adopted various regulations specific to oil and gas exploration, production, gathering and processing, which impose air quality controls and work practices, and govern source determination and permitting requirements, as well as methane emissions. In September 2018, the EPA announced proposed revisions to the various regulations which may reduce compliance burdens on some facilities. In August 2020 EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. Several lawsuits were filed challenging these amendments, and the U.S. Court of Appeals for the D.C. Circuit ordered an administrative stay of these amendments shortly after they were finalized. Although the administrative stay was lifted in October 2020, which brought the amendments into effect, the amendments may still be subject to reversal under the current presidential administration. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021.
Similarly, in November 2016, the Bureau of Land Management (“BLM”) issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands, though many of these regulations were later rescinded by a final rule published by the BLM in September 2018. Compliance with these or other future changes to regulations regarding air emission may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Climate Change
The U.S. is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas (“GHG”) concentrations in the atmosphere at a level that would prevent serious damage to the climate system. In December 2015, the international community agreed upon a new climate change treaty, known as the Paris Agreement. The U.S. committed to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline. This new agreement, which was legally effective in November 2016, incorporates actions taken by individual countries to reduce GHG on the national level. U.S. involvement in developing the new agreement creates significant international pressure for the U.S. to take responsive action to reduce GHG emissions. In November 2019, during the Trump administration, the U.S. submitted formal notification of its withdrawal from the Paris Agreement to the United Nations, effective November 2020. However, the executive order issued by the Biden administration in January 2021 commenced the process for the U.S. reentering the Paris Climate Agreement, although the emissions pledges in connection with that effort have not yet been updated. In general, implementation of the Paris Agreement would encourage a shift away from higher GHG emitting power sources like coal-fired power plants.
In the absence of comprehensive climate change legislation, regulatory action to regulate GHG emissions under the federal Clean Air Act occurred under the Obama administration. The Trump administration was in the process of narrowing, revising or attempting to repeal nearly all of the Obama-era climate regulations. However, as mentioned above, in January 2021, the Biden administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, it is unclear the degree to which certain recent regulatory developments undertaken during the Trump administration may be modified or rescinded.
The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including GHG from petroleum and natural gas systems that emit more than 25,000 tons of GHG per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage.
In 2015, the EPA released the final Clean Power Plan, which is a regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants, including natural gas power plants. Upon finalization of the Clean Power Plan, over twenty states and industry groups challenged the rule in the D.C. Circuit court and requested a stay of the rule. In 2019, the EPA replaced the Clean Power Plan with the more narrowly-scoped Affordable Clean Energy rule. The rule was challenged by public health groups, certain states and environmental groups, and in January 2021, the D.C. Circuit Court of Appeals vacated the Affordable Clean Energy rule and its implied repeal of the Clean Power Plan, remanding to EPA for further proceedings. In the event the matter is not heard by the Supreme Court, it is not clear whether EPA will reinstate the Clean Power Plan or undertake new rulemaking.
In 2016, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule as applied to the oil and natural gas industry and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country. These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. In 2019, the EPA proposed to replace existing NSPS methane limits with a narrower rule and to amend the Federal Implementation Plan for oil and gas production activities in Indian Country. In August 2020, the EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. Accordingly, the EPA is currently reviewing rule and its future implementation is uncertain at this time.
In addition to activity at the federal level, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHG, including obligations on utilities to purchase renewable energy and participate in GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.
Climate change regulatory and legislative initiatives could have a material adverse effect on our business, results of operations and financial condition. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products could become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products could become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Such effects could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.
Water Discharges
The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the U.S. Pursuant to the CWA and analogous state laws, permits must be obtained from the EPA or analogous state agency to discharge pollutants into state waters or waters of the U.S. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
Endangered Species Act
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Employee Health and Safety
We are subject to a number of federal and state laws and regulations regulating employee health and safety, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes. In addition, the OSH Act’s hazard communication standard, the EPA’s “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and the public. The OSH Act regulates worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The key provisions of the rule are to: (i) reduce the permissible exposure limit (“PEL”) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8-hour shift; (ii) require employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provide medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provide flexibility to help employers protect workers from silica exposure. Workers at well sites may be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at well sites may lead to increased regulation and enforcement or related tort claims by our employees. Implementation of engineering and workplace controls to comply with the rule may require significant investment.
Hydraulic Fracturing
The Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other bills that have been introduced in recent years in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.
Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has promulgated pretreatment standards for oil and gas extraction category under the CWA that prohibit the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA also has been conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater. The EPA collected data and information related to the extent to which such wastewater is accepted, available treatment technologies, discharge characteristics and other information. The EPA is currently reviewing comments on the draft study report. The use of surface impoundments (i.e., pits or surface storage tanks) for the temporary storage of hydraulic fracturing fluids for re-use or prior to disposal may also be regulated. The EPA also completed a multi-year study about the effects of hydraulic fracturing on drinking water. Although the regulations for hydraulic fracturing on federal land that were promulgated by the U.S. Department of the Interior in 2015 were rescinded in 2017, that 2017 rulemaking is the subject of ongoing litigation. These regulatory developments have the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business.
Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, several states have implemented rules requiring hydraulic fracturing operators to sample ground and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.
At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.
Insurance Matters
As is common in the oil and gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.
Employees
As of December 31, 2020, we had 59 employees (all employed full-time). None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory. To date, our pending bankruptcy cases have not materially increased employee attrition.
We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting and other disciplines as needed.
Available Information
Our website address is www.sundanceenergy.net. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Nominating and Corporate Governance Committee, Compensation Committee and Reserves Committee, and our Code of Ethics and Business Conduct are available through our website, and we also intend to disclose any amendments to our Code of Ethics, or waivers to such code on behalf of our Chief Executive Officer or Chief Financial Officer, on our website. The contents of our website are not intended to be incorporated by reference into this annual report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. Information is also available on the SEC website at www.sec.gov.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. When considering an investment in our securities, you should carefully consider the risk factors included herein as well as those matters referenced in this report under “Cautionary Statement Regarding Forward-Looking Statements” and other information included and incorporated by reference into this annual report.
Summary Risk Factors
The following is a summary of the principal risks that could adversely affect our business, operations and financial results, which should be read in conjunction with the more detailed description of each risk factor contained below.
Risks Related to Our Bankruptcy
● We are subject to risks and uncertainties associated with our Chapter 11 cases and may not be able to obtain confirmation of a Chapter 11 plan of reorganization.
● Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern. Our financial results may be volatile and may not reflect historical trends.
● We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.
● Transfers of our equity, or issuances of equity in connection with our Chapter 11 cases, may impair our ability to utilize our federal income tax net operating loss carryforwards and depreciation, depletion and amortization deductions in future years.
● Our derivative activities will be materially limited upon emergence from bankruptcy and could result in financial losses or could reduce our income.
Risks Related to Our Business
● The current outbreak of COVID-19 has adversely impacted our business, financial condition, liquidity and results of operations and is likely to have a continuing adverse impact for a significant period of time.
● Oil, natural gas and NGL prices are volatile, and an extended decline in these prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
● Increased costs of capital and general economic conditions could adversely affect our business and future growth.
● Our future revenues are dependent on our ability to successfully replace our proved producing reserves.
● Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may not be ultimately developed or produced. SEC rules could limit our ability to book additional PUDs.
● There can be no assurance that we will be able to comply with the terms of our credit facilities.
● Any significant reduction in our borrowing base under our revolving credit facilities may negatively impact our ability to fund our operations.
● Our level of indebtedness and restrictions contained in our credit facilities may reduce our financial flexibility.
● Changes in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price our actual crude oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.
● Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
● We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production.
● We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts.
● Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling.
● The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
● 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.
● Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in limited geographic areas.
● Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these estimates could materially affect the actual quantities and present value of such reserves.
● Oil and natural gas price declines may require us to write-down the carrying values of our oil and natural gas properties.
● The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
● Our inability to market our crude oil and natural gas could adversely affect our business.
● Competition in the oil and natural gas industry is intense, many of our competitors have resources that are greater than ours and we may not be able to keep pace with technological developments in our industry.
● The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.
● We may incur losses as a result of title deficiencies.
● Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.
● Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.
● Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
● Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs while the physical effects of climate change could disrupt our production and cause us to incur significant costs.
● 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.
● Ineffective internal controls could impact our business and financial results.
● Our business could be negatively impacted by security threats, including cyber-security threats.
Risks Related to Our Common Stock
The shares of our existing common stock are expected to be canceled in our Chapter 11 proceedings.
Risks Related to Our Bankruptcy
We are subject to risks and uncertainties associated with our Chapter 11 cases.
On March 9, 2021, the Company along with its three subsidiaries, Sundance Energy, Inc., SEA Eagle Ford, LLC, and Armadillo E&P, Inc., filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code.
Our operations and ability to develop and execute our business plan, our financial condition, our liquidity and our continuation as a going concern, are subject to the risks and uncertainties associated with our bankruptcy. These risks include the following:
● our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 cases;
● the high costs of bankruptcy cases and related fees;
● our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
● our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
● our ability to maintain contracts that are critical to our operations;
● our ability to safely and efficiently re-start operations after a protracted period of minimal activity;
● our ability to execute competitive contracts with third party contractors while tainted with a bankruptcy legacy;
● our ability to execute our business plan in the current commodity price environment;
● our ability to attract, motivate and retain key employees;
● the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
● our ability to retain our current management team;
● the ability of third parties to seek and obtain court approval to convert the Chapter 11 cases to a Chapter 7 proceeding; and
● the actions and decisions of our shareholders, creditors and other third parties who have interests in our Chapter 11 cases that may be inconsistent with our plans.
Delays in our Chapter 11 cases increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.
These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our Chapter 11 cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Prepackaged Plan. Because of the risks and uncertainties associated with our Chapter 11 cases, we cannot accurately predict or quantify the ultimate impact of events that occur during our Chapter 11 cases will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.
We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.
To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. A confirmation hearing on the Prepackaged Plan has been scheduled to begin on April 19, 2021, but it is possible that hearing could be delayed. It is also possible that the Bankruptcy Court will not confirm the Prepackaged Plan. If the Prepackaged Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.
Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Prepackaged Plan or another Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.
Our proposed Prepackaged Plan contemplates that the up to $50 million DIP Facility being provided by the Term Lenders will be converted to equity at emergence. However, if this equitization is not approved by the Bankruptcy Court or otherwise does not occur, and even if our debts are reduced or discharged through the Prepackaged Plan or a different confirmed plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our Chapter 11 cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all. Our ability to continue as a going concern may be dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a plan is confirmed.
We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.
Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 cases. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the Chapter 11 cases, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.
In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.
Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.
We believe it is highly likely that the shares of our existing common stock will be canceled in our Chapter 11 cases and current shareholders will receive no consideration.
The Prepackaged Plan provides, among other things, that upon our emergence from bankruptcy, our existing common stock will be canceled, and the holders of our existing common stock will receive none of our post-emergence common stock. If the Prepackaged Plan is confirmed by the Bankruptcy Court, the existing shareholders receive nothing. Accordingly, any trading in shares of our common stock during the pendency of the Chapter 11 cases is exceptionally risky and highly speculative.
Our financial results may be volatile and may not reflect historical trends.
During the Chapter 11 cases, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.
In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We expect to be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.
Transfers of our equity, or issuances of equity in connection with our Chapter 11 cases, may impair our ability to utilize our federal income tax net operating loss carryforwards and depreciation, depletion and amortization deductions in future years.
Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have net operating loss carryforwards of approximately $406.7 million as of December 31, 2020. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards and amortizable tax basis in our properties may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Further, future deductions for depreciation, depletion and amortization could be limited if the fair value of our assets is determined to be less than the tax basis.
Risks Related to Our Business
The current outbreak of COVID-19 has adversely impacted our business, financial condition and results of operations and is likely to have a continuing adverse impact for a significant period of time.
The COVID-19 pandemic caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil prices will improve and stabilize.
The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow has affected our borrowing capacity and required us to shut-in production that has become uneconomic. These conditions also increased the difficulty in repaying, refinancing or restructuring our long-term debt.
The global COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand, all of which are beyond our control. These factors have had a material adverse impact on our business, financial condition and results of operations, and are likely to have a continuing adverse impact for a significant period of time.
The COVID-19 pandemic and the responses of governmental authorities and companies across the world has caused a rapid and precipitous drop in the demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020. While certain containment measures have been relaxed, the remaining risks and uncertainty surrounding resurgence and reinstitution of more severe containment measures continue to reduce demand for oil and natural gas. The duration and severity of the impact of COVID-19 on the oil and gas industry, including the reduced demand for oil and natural gas and its resulting impact on commodity prices, may continue until a vaccine or alternative treatment is made widely available across the globe. We are unable to predict when, and if, an effective vaccine or alternative treatment for COVID-19 will become available globally.
Additionally, in March 2020, OPEC and non-OPEC producers failed to agree to production cuts, resulting in a significant drop in crude oil prices. Saudi Arabia also reduced its export prices to certain markets, while increasing its prices in others. In April 2020, members of OPEC and certain non-OPEC producers agreed to production cuts through first quarter 2022. While these production cuts are expected to reduce excess global crude oil inventories in 2021, they are unlikely to be sufficient to offset the sharp demand decreases caused by COVID-19 in the near-term.
Substantially all of our oil production is sold to purchasers under contracts at market-based prices. The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since February 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. While we continue to flexibly manage our operations, including capital expenditure levels, based on existing and expected market conditions, our lower levels of cash flow has affected our borrowing capacity and required us to shut-in production that has become uneconomic. These conditions also increased the difficulty in repaying, refinancing or restructuring our long-term debt.
Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, results of operations or financial condition and our ability to meet our capital expenditure obligations and financial commitments.
Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. For example, in 2020 average daily prices for NYMEX-WTI crude oil ranged from a high of $63.27 per barrel to a low below zero for a short time in April 2020. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control.
These factors include:
● general worldwide and regional economic and political conditions;
● the domestic and global supply of, and demand for, oil, natural gas and NGLs;
● the actions of OPEC and the ability of OPEC and other producing nations, including Russia, to agree to and maintain production levels;
● the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;
● the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;
● the price and quantity of imports of foreign and exports of domestic oil, natural gas and NGLs;
● the level of global oil, natural gas and NGL exploration and production;
● the level of global oil, natural gas and NGL inventories;
● future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
● weather conditions and natural disasters;
● global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may reduce the demand for oil, gas and NGL because of reduced global or national economic activity;
● domestic and foreign governmental laws, regulations and taxes;
● volatile trading patterns in commodities futures markets;
● price and availability of competitors’ supplies of oil, natural gas and NGLs;
● shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas and related infrastructure;
● technological advances affecting energy consumption; and
● the price and availability of alternative fuels.
Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 64% and 18% of our estimated proved reserves as of December 31, 2020 were attributed to oil and NGLs, respectively, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under contracts at market-based prices.
Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. As of the date of this report, we have oil derivatives in place covering an average of 3,142 Bbls per day for remainder of 2021. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.
In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We might also elect during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, we could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, we may abandon any well if we reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.
There can be no assurance that we will be able to comply with the terms of our credit facilities.
Our credit facilities require us to maintain compliance with certain financial and other covenants. Our ability to comply with these covenants is uncertain and will be affected by our results of operations and financial condition, and events or circumstances beyond our control, including sustained low commodity prices. Absent a waiver or amendment, a breach of any of these covenants contained in our credit facilities could result in an event of default under these facilities.
Specifically, due to the sharp decline in commodity prices and expectations for commodity prices in the first quarter of 2020, beginning in the third quarter of 2020, we were not in compliance with certain of the financial covenants and ratios. Violation of these financial covenants and ratios, caused our indebtedness to become immediately due and payable, the interest rates under our credit facilities increased and the lenders’ commitment to make further loans to us was terminated. We did not have the funds to repay, or the ability to refinance, such outstanding amounts and we filed voluntary petitions seeking relief under Chapter 11 of the United States Bankruptcy Code with support of our lenders under the RSA. The DIP Facility requires that we comply with general affirmative and negative covenants such as prohibiting us from incurring or permitting debt, investments, liens or dispositions unless specifically permitted. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply or obtain a waiver in the event we cannot comply with a covenant could result in an event of default under the DIP Facility and permit the lenders thereunder to accelerate the loans and otherwise exercise remedies allowable by the agreements governing the DIP Facility. After we emerge from bankruptcy, while we expect to discharge a significant portion of our indebtedness, we expect to have the Exit RBL Facility and Exit Second Out Term Loan Facility (the “Exit Facilities”) that requires compliance with financial covenants and ratios the failure of which could cause the amounts outstanding to immediately become due and payable, the interest rates under the credit facility to increase and the lenders’ commitment to make further loans to be terminated. Any of these outcomes would have an adverse effect on our business and financial condition.
For more information on the covenants under our pre-Chapter 11 credit facilities and the impact of the explanatory paragraph in the audit report, see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.
Our future revenues are dependent on our ability to successfully replace our proved producing reserves.
Our business strategy is to generate profit through the acquisition, exploration, development and production of oil and natural gas reserves. Proved reserves generally decline as they are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.
Development and exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could materially and adversely affect our business, results of operations or financial condition. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
● lack of prospective acreage available on acceptable terms;
● unexpected or adverse drilling conditions;
● elevated pressure or irregularities in geologic formations;
● equipment failures or accidents;
● adverse weather conditions;
● title problems;
● limited availability of financing upon acceptable terms;
● reductions in oil, natural gas and NGL prices;
● compliance with governmental requirements; and
● shortages or delays in the availability of drilling rigs, equipment and personnel.
Even if our exploration, development and drilling efforts are successful, our wells, once completed, may not produce reserves of oil, natural gas or NGLs that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results described elsewhere in this annual report.
Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2020, approximately 57% of our total proved reserves were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Based on our December 31, 2020 reserve report, it will require an estimated $288.2 million of capital to develop approximately 26.1 MMBoe of our estimated proved undeveloped reserves over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves to unproved reserves.
Further, our reserve estimates assume that we can and will make these expenditures and that these operations will be conducted successfully. However, these assumptions may not prove correct. If our plans change and we choose not to spend the capital (or are unable to generate adequate cash flow or obtain the necessary capital under our credit facilities or from other sources) to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove these reserves from future reserve estimates. Any such removal of our existing reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.
Any significant reduction in our borrowing base under the Exit Facilities as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
On the effective date of the Prepackaged Plan, our existing Revolving Facility will be extinguished, and we will enter into the Exit Facilities, including a new reserve-based lending revolving credit facility having a borrowing base of $107.5 million (inclusive of a $20.0 million letter of credit subfacility). The borrowing base will be redetermined on a semi-annual basis and the next scheduled redetermination is anticipated to occur on or about March 1, 2022, subject to any interim unscheduled redeterminations as described in the Exit Facilities.
Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of the debt owed under our revolving credit facilities to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of our revolving credit facilities and an acceleration of the loans outstanding under any of our credit facilities. Failure to timely pay these debt obligations when due could cause us to lose our assets through mortgage foreclosure, which would materially and adversely affect our business, results of operations and financial condition.
In the future, we may not be able to access adequate funding under our revolving credit facilities as a result of a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under our credit facilities, which would materially and adversely affect our business, results of operations and financial condition.
In addition, the availability of borrowings under the Exit Facilities is subject to various financial and non-financial covenants and restrictions. As a result of these covenants, we may be unable to finance future operations or capital needs.
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under “Credit Facilities”.
Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.
The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.
Our level of indebtedness and restrictions contained in our debt agreements may reduce our financial flexibility.
We intend to fund our capital expenditures primarily through cash flow from operations and, if necessary borrowings under available credit facilities and alternative debt or equity financings. If we obtain alternative debt or equity financing for these or other purposes, the related risks that we now face could intensify. The Exit Facilities that we expect to be in effect upon effectiveness of the Prepackaged Plan will contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that impose operating and financial restrictions on us. Our level of debt and debt agreements could materially and adversely affect our business, results of operations and financial condition in several important ways, including the following:
● a portion of our cash flow from operations would be used to pay interest on borrowings;
● the covenants contained in available credit facilities may restrict our ability to incur additional debt, guarantee indebtedness or create liens on certain assets, pay dividends on or make distributions in respect of, or repurchase or redeem, our capital stock or make other restricted payments, dispose of assets or issue shares of preferred stock, prepay, redeem or repurchase certain debt, make loans or certain investments and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;
● a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;
● a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and
● the debt we currently hold, as well as any debt that we incur under our available credit facilities will be at variable rates which could make us vulnerable to an increase in interest rates.
The interest rates under our credit facilities may be impacted by the phase-out of LIBOR.
The London Interbank Offered Rate (“LIBOR”) is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rates on loans globally. We generally use LIBOR as a reference rate to calculate interest rates under our credit facilities. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time or if new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR ceases to exist or replaced with an alternative reference rate, we may need to renegotiate our credit agreements to replace LIBOR with an agreed upon replacement index, and certain of the interest rates under our credit agreements may change. The new rates may not be as favorable to us as those in effect prior to any LIBOR phase-out. We may also find it desirable to engage in more frequent interest rate hedging transactions.
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
The oil and natural gas business involves operating hazards such as:
● well blowouts;
● mechanical failures;
● fires and explosions;
● pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;
● uncontrollable flows of oil, natural gas or well fluids;
● geologic formations with abnormal pressures;
● handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
● pipeline ruptures or spills;
● inclement weather, including flooding, hurricanes or other severe weather events;
● releases of toxic gases; and
● other environmental hazards and risks (including groundwater contamination).
Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims, regulatory investigation, penalties and suspension of operation and other damage to our properties and the property of others.
We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.
In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
We depend upon several significant customers for the sale of most of our oil, natural gas and NGL production.
For the year ended December 31, 2020, purchases by two customers each accounted for over 10% of our total sales revenues. The loss of one or more of these customers or the inability or failure of either of these customers to meet their obligations to us or their insolvency or liquidation could adversely affect our revenues in the short term. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The availability of a ready market for any oil, natural gas or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil, natural gas and NGL production and federal regulation of oil, natural gas and NGL in interstate commerce.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic. Lower PV-10 value, resulting from fewer PUDs, may negatively impact our investor perception.
Our planned drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:
● landing our well bore in the desired formation;
● staying in the desired formation while drilling horizontally through the formation;
● running our casing the entire length of the well bore; and
● being able to run tools and other equipment consistently through the well bore.
Risks that we face while completing our wells include, but are not limited to:
● being able to fracture stimulate the planned number of stages;
● being able to run tools the entire length of the well bore during completion operations;
● successfully cleaning out the well bore after completion of the final fracture stimulation stage; and
● negatively impacting offset producing wells through subsurface communication during fracture stimulation.
The results of our drilling in new or emerging 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.
Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:
● ongoing review and analysis of geologic and engineering data;
● the availability of sufficient capital resources to us and the other participants for drilling and completing of the locations;
● the approval of the locations by other participants once additional data has been compiled;
● economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and personnel;
● the ability to maintain, extend or renew leases and permits on reasonable terms for the locations;
● additional due diligence;
● regulatory requirements and restrictions; and
● the opportunity to divert our drilling budget to preferred locations.
Although we have identified or budgeted for numerous drilling locations, we may not be able to lease or drill those locations within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a location rather than on analysis of seismic or other data in the location area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties, and our ability to produce oil, natural gas and NGLs may be significantly affected by the availability and prices of equipment and personnel.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing properties. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. We cannot predict the future availability or costs of these items. However, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities, could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.
We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.
In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
● recoverable reserves;
● future oil and natural gas prices and their appropriate differentials;
● timing of development;
● 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 often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
Significant acquisitions and other strategic transactions may involve other 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 those of our operations while carrying on our ongoing business;
● difficulty associated with coordinating geographically separate organizations; and
● the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. 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 effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.
Our producing properties are located primarily in the Eagle Ford, making us vulnerable to risks associated with operating in a limited number of geographic areas.
All of our producing properties are geographically concentrated in the Eagle Ford area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation (including any proration and production restrictions in light of the COVID-19 pandemic or otherwise), processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs, any of which could materially and adversely affect our business, results of operations and financial condition.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.
The reserve data in this annual report represent only estimates. There are uncertainties inherent in estimating oil and natural gas reserves and their estimated value, including many factors beyond our control. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report, which could materially and adversely affect our business, results of operations and financial condition.
Our derivative activities will be materially limited upon emergence from bankruptcy and could result in financial losses or could reduce our income.
Because oil and natural gas prices are subject to volatility, we have historically entered into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and natural gas prices. Following our emergence from bankruptcy, our derivative activities will be materially governed by loan agreements and we may be unable to sufficiently mitigate implication of price or production changes.
These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and natural gas or a sudden, unexpected event that materially impacts oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.
Oil and natural gas price declines may require us to write-down the carrying values of our oil and natural gas properties.
Accounting rules require that we periodically review the carrying value of our producing oil and gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews (which may include depressed oil, natural gas and NGL prices and the continuing evaluation of development plans, production data, economics, possible asset sales and other factors), we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. For example, we incurred impairment of proved oil and gas properties of $331.9 million during 2020 and impairment of oil and gas properties held for sale of $10.0 million during 2019.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. In accordance with SEC regulations, the estimated discounted future net cash flows from proved reserves are based on the average of the historical sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:
● the actual prices we receive for oil and natural gas;
● our actual operating costs in producing oil and natural gas;
● the amount and timing of actual production;
● supply and demand for oil and natural gas;
● increases or decreases in consumption of oil and natural gas; and
● changes in governmental regulations or taxation.
In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
Our inability to market our oil and natural gas could adversely affect our business.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could materially and adversely affect our business, results of operations and financial condition.
Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.
We generally deliver our oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.
A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of adverse weather conditions or natural disasters, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.
Our credit facilities have substantial restrictions and financial covenants that restrict our business and financing activities.
The Exit Facilities we expect to be in effect upon emergence from the Chapter 11 cases contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to, among other things:
● incur additional indebtedness or guarantee indebtedness;
● pay dividends or make other distributions or repurchase or redeem capital stock;
● enter into hedging agreements covering volumes above specified ceilings or below specified floors;
● prepay, redeem or repurchase certain debt;
● issue certain preferred stock or similar equity securities;
● make loans or certain investments;
● sell certain assets;
● create liens on certain assets;
● enter into certain transactions with affiliates;
● alter the businesses we conduct;
● enter into agreements restricting our subsidiaries’ ability to pay dividends;
● consolidate, amalgamate, merge or sell all or substantially all of our assets; and
● designate our subsidiaries as unrestricted subsidiaries.
In addition, the availability of borrowings under the DIP Facility and Exit Facilities is subject to various financial and non-financial covenants and restrictions. As a result of these covenants, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.
Failure to comply with the covenants under these facilities or any of our other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:
● will not be required to lend any additional amounts to us;
● could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable and terminate all commitments to extend further credit; or
● could require us to apply all of our available cash to repay these borrowings.
Such actions by the lenders could cause cross defaults under our other indebtedness. If we were unable to repay those amounts, the lenders or holders under these facilities and our other secured indebtedness could proceed against the collateral granted to them to secure that indebtedness and we could be forced into bankruptcy or liquidation.
Increased costs of capital could adversely affect our business.
Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.
Competition in the oil and natural gas industry is intense and many of our competitors have resources that are greater than ours.
The oil and natural gas industry is highly competitive. Public integrated and independent oil and natural gas
companies, private equity backed and private operators are all active bidders for desirable oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
The loss of any of our key personnel could adversely affect our business the results of operations, financial condition and future growth.
We are reliant on a number of key members of our executive management team. Loss of such personnel may have an adverse effect on our performance. We operate in a highly competitive environment and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to sustain current operations or manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow or operate our business profitably.
Our ability to manage growth will have an impact on our business, results of operations and financial condition.
Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:
● our ability to obtain leases or options on properties;
● our ability to identify and acquire new exploratory prospects;
● our ability to develop existing prospects;
● our ability to continue to retain and attract skilled personnel;
● our ability to maintain or enter into new relationships with project partners and independent contractors;
● the results of our drilling programs;
● commodity prices; and
● our access to capital.
We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.
We may incur losses as a result of title deficiencies.
We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.
The existence of title deficiencies with respect to our oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.
Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.
Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plugging and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting GHG emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.
There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to foreign ownership, access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing. For instance, in January 2021, the Biden administration issued a series of executive orders focused on environmental matters that could impact demand for oil and gas and, in turn, our financial performance. One of the executive orders directed all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with the administration’s policies. Another of the executive orders was focused on addressing climate change and, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the suspension have already been filed and are currently pending, so the ultimate effect of such orders is uncertain at this time.
The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially harmful working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. In March 2016, the Occupational Safety and Health Administration issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. Compliance with the rule may require significant investment in engineering and workplace controls. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.
We have entered into physical delivery contracts that will require further development in order to deliver all the oil required under such contracts.
We entered into midstream contracts with a large pipeline company and production purchaser to provide gathering, processing, transport and marketing of production for the Eagle Ford assets acquired in 2018. The contracts contain minimum revenue commitments, a portion of which is secured by letters of credit and performance bonds. If the planned development program is not executed to the extent projected, we may not produce sufficient quantities of hydrocarbons to meet the minimum revenue commitments and may be required to make cash deficiency payments. The deficiency payments would reduce liquidity to invest in growing the business and profitability. If we are unable to make the deficiency payments, the letters of credit and performance bonds may be drawn causing an increase in our level of indebtedness and potentially result in a default under our loan covenants.
Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.
Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the U.S. at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the U.S., including states in which we operate, have begun adopting more restrictive regulations, including measures such as:
● required disclosure of chemicals used during the hydraulic fracturing process;
● restrictions on wastewater disposal activities;
● required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;
● new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;
● financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and
● local moratoria or even bans on oil and natural gas development utilizing hydraulic fracturing in some communities.
In addition, the federal government has the authority to regulate hydraulic fracturing on federal and tribal lands. Under the Obama administration, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands that require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the U.S. Congress (“Congress”) has considered and may continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on-shore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature. Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.
Despite the existing regulatory exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the U.S. Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands. Under the current administration, many of these regulations are under review and may be repealed or revised.
These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.
Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Increasing trends of opposition to oil and gas development activity and negative public perception regarding us and/or our industry could have an adverse effect on our operations.
In recent years, we have seen significant growth in anti-oil and gas development activity both in the U.S. and globally. Companies in our industry can be the target of opposition to hydrocarbon development. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include efforts to reduce access to public and private lands, restriction of exploration and production activities within government-owned and other lands, delaying or canceling permits for drilling or pipeline construction, limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal, imposition of set-backs on oil and gas sites, delaying or denying air-quality or siting permits, advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity, and the use of social media channels to cause reputational harm.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, results of operations or financial condition.
Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions.
Our inability to timely secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other
“greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the U.S., including companies in the energy industry, to annually report those emissions. New major sources or significant modifications of existing sources of traditional air pollutants are required to obtain permits and to use best available control technology to control those emissions pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. In addition, sources subject to best available control technology for traditional air pollutants are now also required to use best available control technology to control significant greenhouse gas emissions. While these regulations have not to date materially affected us, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.
In May 2016, the EPA issued final regulations intended to reduce methane emissions from the oil and gas sector by 40% to 45% from 2012 levels by 2025. In October 2016, the EPA issued final Control Techniques Guidelines for reducing smog-forming VOC emissions from existing oil and natural gas equipment and processes in certain states and areas with smog problems. In August 2020, EPA adopted deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. In particular, the amendments removed the transmission and storage segments from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. In January 2021, the administration issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding the deregulatory amendments by September 2021. As a result, the future implementation of these standards is uncertain. However, such methane regulations could affect us indirectly by affecting our customer base or by directly regulating our operations.
In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. Energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.
Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.
Terrorist attacks aimed at energy operations could adversely affect our business.
The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack (in the form of physical attacks or cyber-attacks) on our facilities, customer facilities, and the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.
General economic conditions could adversely affect our business and future growth.
Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.
Also, market conditions could have an impact on our oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.
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.
The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the OTC derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions, and these rules may affect both the size of positions that we may enter or the ability and willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations. At this time, the impact of such regulations is not clear.
Our business could be adversely impacted by security threats, including cyber-security threats, and other disruptions.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.
We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and stockholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.
If we fail to establish and maintain proper internal controls, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.
We are subject to Section 404(a) of the Sarbanes-Oxley Act, which requires that our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting.
Our management has concluded that our internal controls over financial reporting were effective as of December 31, 2020. However, if we fail to maintain effective internal controls over financial reporting in the future, the presence of material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report.
In addition, if we are unable to conclude that we have effective internal controls over financial reporting, investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions.
We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.
Risks Related to Our Common Stock
The shares of our existing common stock are expected to be canceled in our Chapter 11 proceedings.
We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure. As a result, in accordance with our Prepackaged Plan, the existing shares of our common stock are expected to be canceled in our Chapter 11 proceedings and are not expected to be entitled to any recovery. Any trading in shares of our common and preferred stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock. Upon our emergence from bankruptcy, our existing common stock will be canceled and removed from further trading by the Financial Industry Regulatory Authority.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties.
Information regarding our oil and gas properties is included in Part I, Item 1. “Business” under “Oil and Natural Gas Properties”. We also lease approximately 19,000 square feet of office space at 1050 17th Street, Suite 700, Denver, Colorado 80265, where our principal offices are located. We also have various operating leases for rental of field office space, office and field equipment, and vehicles. See Note 5 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” for the future minimum rental payments. Such information is incorporated herein by reference.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on our financial position, cash flows or results of operations.
For discussion of our ongoing bankruptcy proceedings, see Part I, Item 1. Business subsection Bankruptcy Proceedings under Chapter 11.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market
Our common stock was previously listed and traded on the Nasdaq Global Market (the “Nasdaq”) under the symbol “SNDE”. As a consequence of the Chapter 11 Cases, beginning March 19, 2021, our ordinary shares were trading on the OTC Pink Open Market under the symbol SNDEQ. On March 22, 2021 there were 3,845 holders of record of our common stock.
Dividend Policy
We will not pay dividends during the pendency of our Chapter 11 proceedings. In accordance with our Prepackaged Plan, the existing shares of our common stock are expected to be canceled in our Chapter 11 proceedings and existing shareholders are not expected to be entitled to any recovery. Any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock. Upon our emergence from bankruptcy, our existing common stock will be canceled and removed from further trading by the Financial Industry Regulatory Authority.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data.
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Part I, Item 1A. “Risk Factors” along with “Cautionary Statement Regarding Forward-Looking Statements” on page 2 of this annual report for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.
Overview and Executive Summary
We are an onshore independent oil and natural gas company focused on the development, production and exploration of large, repeatable resource plays in North America. Our operations are located in the Eagle Ford formation in south Texas. Our strategy is to acquire and/or develop assets where we are operator and have high working interests, positioning us to efficiently control the pace and scope of our development and the allocation of our capital resources. Serving as operator allows us to control the drilling, completion, operations, and marketing of sold volumes. As a result of the sharp decline in commodity price s during the first quarter of 2020 and the impact on our financial position, we significantly decreased our level of capital spending. Upon emergence from bankruptcy (described below under Recent Events), we plan to continue to focus on developing high-return assets from our portfolio, while preserving an attractive oil-rich inventory.
Recent Events
On March 9, 2021, Sundance and its subsidiaries commenced the Chapter 11 Cases under Chapter 11 of the Bankruptcy Code.
On March 9, 2021, we entered into a RSA with (i) Toronto Dominion (Texas) LLC, as agent pursuant to the Revolving Facility, (ii) the lenders party to that certain Credit Agreement, dated as of July 18, 2018 (as amended, modified, or supplemented), (iii) Morgan Stanley Capital Administrators Inc. as agent pursuant to the Term Loan Facility, and (iv) the lenders party to that certain Amended & Restated Term Loan Credit Agreement, dated as of April 23, 2018 (as amended, modified, or supplemented from time to time) to support a reorganization in accordance with the terms set forth in the Plan.
Due to the Chapter 11 Cases, the Company’s common stock was delisted from NASDAQ on March 19, 2021 and began trading on the Pink Open market under the symbol “SNDEQ”.
We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions, including motions to obtain customary relief intended to minimize the impact of the Chapter 11 Cases on our operations, customers and employees. Upon emergence from bankruptcy, we expect that we will no longer be a publicly traded company. For more information on the Chapter 11 Cases and related matters, please see Note 15-Subsequent Events in Part II, Item 8. “Financial Statements and Supplementary Data”.
Business and Industry Outlook
During 2020, WTI oil spot prices ranged from a high of $63.27 in January and briefly dropped below zero in April 2020, primarily due to drastic price cutting and increased production by Saudi Arabia coupled with a demand reduction caused by the global COVID-19 pandemic. In the second half of 2020, WTI oil spot prices slowly rebounded and hovered near $40 per barrel. While market prices for crude oil, natural gas and NGLs are inherently volatile, the increase in supply and decrease in demand to historic extremes has impacted our entire industry. Given the dynamic nature of these macroeconomic conditions, we are unable to reasonably estimate the period of time that these market conditions will exist and the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery.
The sharp decline in commodity prices and lower expectations for near-term commodity prices, has reduced our revenue and cash flow from operations and slowed the pace at which we can develop our oil and natural gas assets. In addition, substantial and extended declines in oil, natural gas and NGL prices reduces the amount of oil and natural gas that we can produce economically, which has reduced our oil and gas reserve quantities and resulted, and may result, in impairment of our proved oil and gas properties (such as the impairment discussed under Results of Operations and Note 2). It has also impacted our ability to comply with certain financial covenants required by our credit facilities (as described further under Note 6).
Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019
Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2020 and 2019, as well as each period’s respective sales volumes:
Year ended
December 31,
Revenue (In $ ’000s):
Change in $
Change as %
Oil sales
$
76,533
$
177,853
$
(101,320)
(57)
Natural gas sales
7,887
12,553
(4,666)
(37)
NGL sales
7,392
13,174
(5,782)
(44)
Product revenue
$
91,812
$
203,580
$
(111,768)
(55)
Year ended
December 31,
Net sales volumes:
Change in Volume
Change as %
Oil (Bbls)
2,104,758
3,076,582
(971,824)
(32)
Natural gas (Mcf)
3,969,000
5,767,779
(1,798,779)
(31)
NGL (Bbls)
539,828
797,784
(257,956)
(32)
Oil equivalent (Boe)
3,306,086
4,835,663
(1,529,577)
(32)
Average daily sales volumes (Boe/d)
9,033
13,248
(4,215)
(32)
Boe and average net daily production. Due to the significant decline in oil prices in early 2020 and capital spending limitations included in our recent credit agreements amendments, we scaled back our 2020 drilling program as compared to the development programs in 2019 and 2018 (which was back-loaded). As a result, sales volumes decreased by 1,529,577 Boe (4,215 Boe/d) to 3,306,086 Boe (9,033 Boe/d) for the year ended December 31, 2020 compared to 4,835,663 Boe (13,248 Boe/d). Production was higher in 2019 due to more wells coming onto production in late 2018 and early 2019 (11.0 new wells coming online in the fourth quarter of 2018 and 22.0 new operated wells in 2019) compared to late 2019 and 2020 (2.0 wells coming online in the fourth quarter of 2019 and 8.0 operated wells came online in 2020). The 2019 period included approximately 1,153 Boe/d of sales volume from the Dimmit County assets, which were sold in October 2019.
Our sales volume is oil-weighted, with oil representing 64% of total sales volume and liquids (oil and NGLs) representing 80% for both the years ended December 31, 2020 and 2019.
Oil sales. Oil sales decreased by $101.3 million (57%) to $76.5 million for the year ended December 31, 2020 from $177.9 million for the prior year. The decrease in oil revenue was driven by lower sales volumes ($56.2 million), coupled with lower product pricing ($45.1 million). The average realized price on the sale of our oil decreased by 37% to $36.36 per Bbl for the year ended December 31, 2020 from $57.81 per Bbl for the prior year. Oil sales volumes decreased 32% to 2,104,758 Bbls for the year ended December 31, 2020 compared to 3,076,582 Bbls for the prior year.
Natural gas sales. Natural gas sales decreased by $4.7 million (37%) to $7.9 million for the year ended December 31, 2020 from $12.6 million for the prior year. The decrease in natural gas revenues was the result of lower sales volumes ($3.9 million), combined with lower product pricing ($0.8 million). Natural gas sales volumes decreased 31% to 3,969,000 Mcf for the year ended December 31, 2020 compared to 5,767,779 Mcf for the prior year. The average realized price on the sale of our natural gas decreased by 9% to $1.99 per Mcf (net of certain transportation and marketing costs) for the year ended December 31, 2020 from $2.18 per Mcf for the prior year.
NGL sales. NGL sales decreased by $5.8 million (44%) to $7.4 million for the year ended December 31, 2020 from $13.2 million for the prior year. The decrease in NGL revenues was the result of lower sales volumes ($4.3 million), combined with lower product pricing ($1.5 million). NGL sales volumes decreased 257,956 Bbls (32%) to 539,828 Bbls for the year ended December 31, 2020 compared to 797,784 Bbls for the prior year. The average realized price on the sale of our NGLs decreased by 17% to $13.69 per Bbl for the year ended December 31, 2020 from $16.51 per Bbl for the prior year.
The following table provides a summary of our operating expenses on a per BOE basis:
Year ended December 31,
Selected per Boe metrics
Change
Total oil, natural gas and NGL revenues (price received)
$
27.77
$
42.10
$
(14.33)
Effect of commodity derivatives on average price
15.25
2.29
12.96
Total oil, natural gas and NGL revenues (price realized)
$
43.02
$
44.39
$
(1.37)
Lease operating expense (1)
$
(6.80)
$
(5.85)
$
(0.95)
Workover expense (1)
$
(0.82)
$
(1.11)
$
0.29
Gathering, processing and transportation expense
$
(6.15)
$
(3.53)
$
(2.62)
Production taxes
$
(1.65)
$
(2.37)
$
0.72
Depreciation, depletion and amortization (2)
$
(23.83)
$
(18.96)
$
(4.87)
General and administrative expense
$
(6.70)
$
(4.61)
$
(2.09)
(1) Lease operating expense and workover expense are included together in lease operating and workover expenses on the consolidated statement of operations.
(2) Excludes depreciation related to corporate assets.
Lease operating expense. Our LOE decreased by $5.8 million (21%) to $22.5 million for the year ended December 31, 2020 from $28.3 million in the prior year, but increased $0.95 per Boe to $6.80 per Boe from $5.85 per Boe. In March 2020, we made field operating changes and renegotiated pricing with a number of our vendors due to the material drop in market oil prices, which reduced our costs on an absolute basis. However, a significant portion of our costs are fixed, and the per Boe rate was negatively impacted by our lower production volumes.
Workover expense. Our workover expenses decreased $2.7 million to $2.7 million for the year ended December 31, 2020, as compared to $5.4 million for the year ended December 31, 2019. Workover expense per Boe decreased $0.29 per Boe to $0.82 per Boe for the year ended December 31, 2020 as compared to the prior year. We have reduced workover expense through conversion of rod pumps to gas lift and redesign of certain rod pump wells to reduce our well failure rates and the associated workover expense going forward. In addition, as a result of the material drop in oil prices, beginning April 2020 through July 2020, we deferred workovers for low producing wells as it was not economic to service the wells which drove down absolute and per Boe workover expense for the year ended December 31, 2020.
Gathering, processing and transportation expense (“GP&T”). GP&T increased by $3.3 million ($2.62 per Boe) to $20.3 million ($6.15 per Boe) for the year ended December 31, 2020 as compared to $17.1 million ($3.53 per Boe) for the year ended December 31, 2019. GP&T fees are primarily incurred on production from the properties we acquired in April 2018. Approximately $12.4 million and $14.7 million of the GP&T expense was incurred in normal course under various midstream agreements for the years ended December 31, 2020 and 2019, respectively, and the remainder of the expense was related to MRC shortfalls, as discussed below. Sales volumes from the acquired assets subject to these midstream agreements decreased 20% in 2020 as compared to 2019.
Certain of our midstream agreements contain MRCs related to fees due on oil, natural gas and NGL volumes gathered, processed and/or transported. Under the terms of the contracts, if we fail to pay fees equal to or greater than the MRC under any of the contracts, we are required to pay a deficiency payment equal to the shortfall. Our MRC commitment totaled $21.8 million and $15.8 million for the years ended December 31, 2020 and 2019, respectively. The shortfall totaled $8.0 million ($2.42 per Boe) and $2.3 million ($0.49 per Boe) for the years ended December 31, 2020 and 2019, respectively. The increase in the shortfall year over year was the result of the lower production volumes due largely to the scaled-back development program.
Production taxes. Our production taxes decreased by $6.0 million (53%) to $5.4 million for the year ended December 31, 2020 from $11.5 million for the prior year, which was driven by our overall decrease in revenue. Production taxes were 5.9% and 5.6% of total revenue for the year ended December 31, 2020 and 2019. During 2020, we recorded a severance tax refund related to prior periods of $1.1 million that the Company expects to receive in 2021. This was offset by higher ad valorem taxes. Ad valorem tax assessments are calculated by the taxing authorities using January 1 commodity pricing. The significant decline in pricing from the beginning of 2020, resulted in the ad valorem as a percentage of revenue for 2020 being higher than the statutory rates applied in the assessment of taxable value at the beginning of the year.
Depletion, depreciation and amortization expense (“DD&A”). Our DD&A expense related to proved oil and natural gas properties decreased by $12.9 million (14%) to $78.8 million for the year ended December 31, 2020 from $91.7 million for the prior year. On a per Boe basis, DD&A increased to $23.83 per Boe for the year ended December 31, 2020 compared to $18.96 per Boe in 2019 primarily due to downward revisions to our proved developed reserves as a result of lower pricing and lower proved undeveloped reserves resulting from changes to our development program. This was partially offset by lower fourth quarter of 2020 DD&A due to the significant impairment in the third quarter 2020, which reduced the carrying value of proved oil and gas properties.
Impairment expense. We recorded impairment expense of $331.9 million and $10.0 million for the years ended December 31, 2020 and 2019, In the third quarter of 2020, we identified an impairment triggering event for our proved oil and gas properties due to the adverse change to our business climate resulting from oil and gas prices declining in 2020 and the resulting changes in our future development plan. As such, we performed a quantitative assessment as of September 30, 2020, and the estimated undiscounted cash flows from our proved properties were less than the carrying value of our oil and gas properties, which required us to record an impairment.
During the year ended December 31, 2019, we recorded impairment expense of $10.0 million related to our Dimmit County oil and gas properties, which were divested in October 2019.
General & Administrative expense (“G&A”). G&A decreased by $0.1 million (1%) to $22.1 million for the year ended December 31, 2020 as compared to $22.3 million for the prior year. During the year ended December 31, 2020 we incurred legal and advisory fees of $7.7 million ($2.32 per Boe) related to credit facility amendments and debt restructuring described previously, and $0.5 million ($0.14 per Boe) of restructuring costs associated with our workforce reduction in the second quarter. During 2019, we incurred one-time costs, primarily legal and accounting fees, to complete our redomiciliation to the U.S of $2.7 million ($0.55 per Boe). G&A, excluding the costs associated with these discrete transactions, decreased on an absolute basis as compared to prior year primarily due to lower salaries and wages as a result of the expected PPP loan forgiveness of $1.9 million and our workforce and salary reductions.
As described under Credit Facilities, our G&A for the second and third quarter of 2020, was limited to $3 million per quarter and the fourth quarter was limited to $3.6 million (as defined in the agreements). After the adjustments provided for in the agreements, we were in compliance with the covenant for these periods.
Gain/loss on commodity derivative financial instruments. Our commodity derivative contracts are marked to market at the end of each reporting period with the changes in fair value being recognized as gain (loss) on commodity derivative financial instruments, net. Cash flow, however, is only impacted by the monthly settlements paid to or received by the counterparty, which are also recorded as gain(loss) on commodity derivative financial instruments, net. The components of gain (loss) on commodity derivative financial instruments was as follows (in thousands):
Year Ended December 31,
Gain (loss) on commodity derivative financial instruments, net
$ Change
Unrealized gains (losses)
$
1,803
$
(31,637)
$
33,440
Realized gains (1)
50,429
11,095
39,334
Total
$
52,232
$
(20,542)
$
72,774
(1) The realized gains for the years ended December 31, 2020 and 2019, included proceeds of $7.0 million and $3.6 million from unwinding derivative positions before their contractual maturity.
Interest expenses, net of amounts capitalized. The components of interest expense, net of amounts capitalized was as follows (in thousands):
Year ended December 31,
Interest Expense
Change in $
Change as %
Interest expense on Term Loan, Revolving Facility and other
$
31,990
$
32,720
$
(730)
(2)
Amortization of debt issuance costs
3,707
3,351
Expense incurred with debt modification
1,199
-
1,199
Loss on interest rate swap
3,324
4,270
(946)
(22)
Capitalized interest
(711)
(2,283)
1,572
(69)
Total
$
39,509
$
38,058
$
1,451
The decrease in interest expense on our Term Loan, Revolving Facility and other for the year ended December 31, 2020 was driven by the decrease in the average market interest rates, partially offset by an increase in the amount of outstanding debt and additional 2% of paid-in-kind (“PIK”) interest, which is added to the principal of the Term Loan. The PIK interest, effective May 30, 2020, was added as part of the third amendment to the Term Loan in June 2020, and totaled $3.0 million for year ended December 31, 2020, respectively. Our weighted average debt outstanding during 2020 was $371 million (excluding the impact of PIK) versus $347 million for 2019. At December 31, 2020, the stated weighted average interest rates on the Revolving Facility and the Term Loan were 7.40% (including default interest of 2%) and 11.00% (including 2% PIK interest added to the principal at each reporting period), respectively, as compared to 4.75% and 10.11%, at December 31, 2019. Default interest of 2% was added to the Term Loan interest rate beginning in January 2021.
As described in Note 6 to our Conslidated Financial Statements, we entered into the fourth amendment to our Revolving Facility in January 2020, which among other things, appointed Toronto Dominion (Texas) LLC, as the administrative agent (replacing Natixis). As a result of the former administrative agent exiting the facility and terminating its commitments, we wrote-off previously capitalized deferred debt issuance costs of $1.1 million during 2020 in accordance with Accounting Standards Codification 470 - Debt. We capitalized new financing and legal fees of $1.0 million, which will be amortized over the remaining loan term. In June 2020, we entered into the fifth amendment to our Revolving Facility, which among other things, reduced our borrowing base from $210 million to $170 million. As a result, we wrote-off deferred debt issuance costs in proportion to the decrease in borrowing base of $0.1 million.
We recognized a loss on our interest rate swap of $3.3 million and $4.3 million for the years ended December 31, 2020 and 2019, respectively. Our interest rate swaps are marked to market at the end of each reporting period, with the changes in fair value being recognized as interest expense. Cash settlements paid to or received by our counterparty are also recorded as interest expense. In 2020, the loss on the interest rate swap consisted of $5.8 million of unrealized gains and $9.1 million of realized cash settlements, which included payments to unwind all of the outstanding swap positions in December 2020. In 2019, the loss on the interest rate swap consisted of $3.6 million of unrealized losses and $0.6 million of realized cash settlements.
Income Tax Benefit. The components of our provision for income tax benefit and our effective income tax rates were as follows (in thousands):
Year ended December 31,
Income tax benefit
Change in $
Current tax benefit
$
(85)
$
-
$
(85)
Deferred tax benefit
(6,916)
(4,518)
(2,398)
Total income tax benefit
$
(7,001)
$
(4,518)
$
(2,483)
Effective tax rate
1.9%
10.2%
Our effective income tax rate, as shown above, differs from the statutory rate (21%) primarily due to our valuation allowance. See Note 8 Part II, Item 8. “Financial Statements and Supplementary Data”to the consolidate financial statements for more information.
Other income (expense). During the year ended December 31, 2020, we conveyed our non-core interest in the petroleum exploration license 570 located in the Cooper Basin in Australia (“PEL570”) to the property’s operator. At the time of the conveyance, we had accrued expenses related to exploratory drilling of approximately $3.7 million. As consideration for the property, the operator settled our outstanding liability for $0.9 million. The property had previously been fully impaired, and therefore we recognized a gain on the conveyance of $2.7 million. As a result of the conveyance, we were also relieved of our commitment to fund any further exploratory drilling for PEL570. In 2019 other income (expense) was primarily comprised of expense of $0.7 million for a litigation settlement related to a historical sale of non-operated North Dakota properties in 2013 and expense of $0.9 million for early termination of our drilling rig.
Adjusted EBITDAX. Management has historically used both GAAP and certain non-GAAP measures to assess our performance. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and certain external users of our consolidated financial statements, such as investors, industry analysts and lenders.
We define “Adjusted EBITDAX” as earnings before interest expense, income taxes, DD&A, property impairments, gain/(loss) on sale of non-current assets, exploration expense, stock-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items.
Our management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance, identify operating trends (which may otherwise be masked by the excluded items) and compare the results of our operations from period to period without regard to our financing policies and capital structure. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity.
Year Ended December 31,
Reconciliation of Net Loss to Adjusted EBITDAX
Net loss
$
(370,462)
$
(39,590)
Add back:
Current and deferred income tax benefit
(7,001)
(4,518)
Interest expense
39,509
38,058
(Gain) loss on commodity derivative financial instruments, net
(52,232)
20,542
Settlement of commodity derivatives financial instruments
50,428
11,094
DD&A
79,582
92,334
Impairment expense
331,877
9,990
Exploration expense
Noncash stock-based compensation expense
Transaction-related expenses included in G&A expense (1)
7,852
2,677
Reduction-in-force related expenses included in G&A expense
-
Other expense (income), net (2)
(2,739)
Adjusted EBITDAX
$
77,763
$
132,197
(1) In 2019 and early 2020, we incurred one-time costs, primarily legal and accounting fees, to complete our Redomiciliation to U.S. Additionally, in 2020, we incurred costs to amend our credit facilities, explore transactions to reduce our leverage (as required by the third, fourth and fifth amendments to the Term Loan) and complete the RSA.
(2) In 2020, other expense (income), net included a $2.7 million gain on the conveyance of PEL570 to the operator. In 2019, other items of expense, net was primarily related to litigation settlement expense of $0.8 million.
Liquidity and Capital Resources
Overview
On December 31, 2020, our cash balance totaled $5.3 million and we had a working capital deficit of $21.5 million (exclusive of the current classification of debt).
Our liquidity is highly dependent on prices we receive for the sale of oil, gas, and NGLs we produce. Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, ability to comply with financial and other covenants in our credit facilities, access to capital and future rate of growth. We maintain a portfolio of derivative positions to help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. At times, we may choose to liquidate derivative positions before the contract ends in order realize the current value of our existing positions, to the extent permitted by our credit facilities. As of the date of this report, we had had oil derivatives in place covering an average of 3,142 Bbls per day for remainder of 2021 at a weighted average floor price of $48.16. Please see Note 9 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a summary of our outstanding derivative positions as of December 31, 2020.
Chapter 11 Cases and Effect of Automatic Stay
On March 9, 2021, we field for relief under Chapter 11 of the Bankruptcy Code. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under our Revolving Facility and Term Loan, resulting in the automatic and immediate acceleration of all of our debt outstanding. Any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Also on March 9, 2021, we entered into a RSA with the Revolving Facility and Term Loan lenders to support a reorganization in accordance with the term set forth therein. As more fully described in Note 15 Subsequent Events, the Plan and the RSA contemplate a reorganization which would provide for the treatment of holders of certain claims and existing equity interests.
We expect to continue operations in the normal course for the duration of the Chapter 11 Cases. To ensure ordinary course operations, we have obtained approval from the Bankruptcy Court for certain “first day” motions to continue our ordinary course operations after the filing date. In addition, we have obtained a new up to $50 million DIP Facility to fund operations during bankruptcy proceedings. For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with our Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our Lenders. The significant risks and uncertainties related to our liquidity and Chapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will confirm and consummate the Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Cases. As a result, we have concluded that our plans do not alleviate substantial doubt about our ability to continue as a going concern.
Sources of Liquidity and Capital Resources
Historically, our primary sources of liquidity have been borrowings under our credit facilities, cash flow from operations, and strategic dispositions of non-core oil and gas properties. From time to time, we have also raised additional equity from investors. Our primary use of capital has been for the acquisition and development of oil and natural gas properties. At December 31, 2020, we had outstanding borrowings on our Term Loan of $253.0 million (including PIK) and $130.6 million on the Revolving Facility. We were not in compliance with certain of the covenants of the Term Loan and Revolving Facility our credit facilities at December 31, 2020. As described above, the commencement of the Chapter 11 Cases subsequent to yearend, resulted in an automatic and immediate acceleration of all of our debt outstanding. We also have other contractual commitments, which are described in Note 14-Commitments and Contingencies in Part II, Item 8 Financial Statements.
With cash on hand and cash flow from operations combined with the up to $50 million DIP Facility, we expect to have sufficient liquidity to fund anticipated cash requirements through the Chapter 11 Cases.
Cash Flows
Our cash flows for the years ended December 31, 2020 and 2019 are as follows:
Year ended December 31,
(In $ ’000s)
Net cash provided by operating activities
$
33,051
$
111,229
Net cash used in investing activities
$
(54,461)
$
(149,989)
Net cash provided by financing activities
$
14,277
$
49,581
Cash flows provided by operating activities. Cash provided by operating activities for the year ended December 31, 2020 was $33.1 million, a decrease of $78.2 million compared to the prior year ($111.2 million). Including the effect of derivative settlements, including unwound positions, (as shown on page 50), our realized price per Boe decreased 3% to $43.02 per Boe as compared to $44.39 per Boe. During 2020, we had cash settlements from our derivative contracts of $49.84 million. Despite the relatively small decrease in realized price, our sales volume decreased by 32%, resulting in a significant decrease in operating cash flow. In addition, we had higher cash flows for G&A expenses due to costs incurred to restructure our debt. This was partially offset by the receipt of $1.9 million of PPP proceeds, which we expect to be forgiven. Due to payment timing, our cash flows from operations for the year ended December 31, 2019 included three quarterly interest payments on our Term Loan, whereas the year ended December 31, 2020 included four quarterly interest payments, which resulted in higher cash flows in 2019 of $6.5 million. In addition, we paid $6.3 million to unwind our interest rate swaps in December 2020.
Cash flows used in investing activities. Cash used in investing activities for the year ended December 31, 2020 decreased to $54.5 million as compared to $150.0 million in prior year. In 2020 and 2019, net cash flows used in investing activities was primarily for development of proved properties ($54.2 million and $166.7 million, respectively). In 2019, this was partially offset by the sale of our Dimmit County, Texas, oil and gas assets in October 2019 ($17.3 million). See Capital Expenditures below for additional information regarding our investment in oil and gas properties.
Cash flows provided by financing activities. Cash provided by financing activities for the year ended December 31, 2020 decreased to $14.3 million as compared to $49.6 million for the year ended December 31, 2020. We drew $17.0 million on the Revolver in the third quarter of 2020 to meet our working capital needs. This was partially offset by a $1.4 million required repayment made in early July 2020 after we unwound a derivative position. In January 2020, we paid lender and legal fees totaling $1.0 million to amend our Revolving Facility to increase the borrowing base to $210 million (which was subsequently reduced to $170 million following the industry downturn). During 2019, we borrowed $50.0 million on our Revolving Facility to fund a portion of our 2019 drilling program.
Capital Expenditures
The following table summarizes our capital expenditures incurred (excluding changes related to our asset retirement obligation) for the years ending December 31, 2020 and 2019.
Year ending December 31
(In $ ’000s)
Change in $
Change in %
Unproved
$
(15)
$
(192)
(108)
Proved
40,925
149,766
(108,841)
(73)
Total
$
40,910
$
149,943
(109,033)
(73)
Our capital expenditures for proved properties for the year ended December 31, 2020 decreased 73% to $40.9 million, as compared to $149.8 million in the prior year as a result of our scaled back development plan in light of commodity prices and our financial condition. In addition, the third, fourth and fifth amendments to the Term Loan and fifth amendment to the Revolving Facility limited our capital expenditures (as defined in the agreements) to $5 million for the period May 1, 2020 through September 30, 2020, and to $11.1 million for the period May 1, 2020 through December 31, 2020. We were in compliance with these limits.
In 2020, our drilling and completion costs totaled $34.8 million, which included costs to add 8.2 net producing wells, which were turned to sales in February 2020 (2.0 net operated wells) late June 2020 (4.0 net operated wells) and December (2.0 net operated wells). We also invested $2.2 million into shared facility projects and $2.2 million for artificial lift and other well enhancements on existing wells.
In 2019, our drilling and completion costs totaled $125.0 million, which included costs to add 22.3 net producing wells and there were 2.0 additional net operated wells waiting on completion and 0.3 non operated wells in the process of being drilled. In addition, we invested $13.6 million into shared facility projects during the year ended December 31, 2019.
Credit Facilities
We and our wholly owned subsidiary, SEI, are parties to the Term Loan, which is a syndicated $250.0 million second lien term loan with Morgan Stanley Capital Administrators Inc., as administrative agent, and the Revolving Facility, which is a syndicated reserve-based revolver with Toronto Dominion (Texas) LLC, as administrative agent. As of December 31, 2020, we had a borrowing base of $190.0 million, elected commitment of $170 million, $130.6 million of borrowings outstanding and $16.4 million of letters of credit in place under the Revolving Facility. As a result of the commencement of the Chapter 11 Cases, the lender’s commitments under the Revolving Facility have been terminated. We are therefore unable to make additional borrowings or issue additional letters of credit under the Revolving Facility.
Effective January 2021, interest on the Revolving Facility accrued at a rate equal to Prime plus a margin, ranging from 1.50% to 2.50%, depending on the level of funds borrowed, plus post-default interest of 2%. The default interest rate was in place from December 18, 2020 through March 9, 2021. Interest on the Term Loan accrues at LIBOR (with a LIBOR floor of 1.0%) plus 10.0%, of which 2% of the applicable margin is payable-in-kind (effective May 30, 2020). Beginning January 2021, an additional post-default interest rate of 2% began to accrue on the Term Loan.
During the Chapter 11 Cases, we expect the DIP Facility will fund a portion of our cash requirements. Interest on the DIP Facility will accrue at a rate equal to LIBOR (with a LIBOR floor of 1.0%) plus 8%.
The DIP Facility agreement includes conditions precedent, representations and warranties, affirmative and negative covenants, and events of default customary for financings of this type and size. The DIP Facility will mature on the date which is the earliest of (a) June 14, 2021, (b) the effective date of the Prepackaged Plan or (c) the date all DIP Facility loans become due and payable, whether by acceleration or otherwise.
We made an initial draw of $10 million under the DIP Facility in March 2021. We may make additional draws of up to $35 million during the Chapter 11 Cases. An additional $5 million in DIP Facility loans is available with consent of the DIP Facility lenders.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on our financial statements, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
Our 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 GAAP. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements. Actual results could differ from our estimates and assumptions, and these differences could result in material changes to our financial statements. The following discussion presents information about our most critical accounting policies and estimates. Our significant accounting policies are further described in Note 1 to our audited consolidated financial statements included in “Item 8. Financial Statements and Supplemental Data” of this annual report.
Estimates of Oil and Gas Reserve Quantities. The estimated quantities of oil, natural gas and NGL reserves are integral to the calculation of DD&A and to assessments of possible impairment of assets. Discounted future net cash flows derived from our reserve estimates were also utilized in calculating the fair value of our oil and natural gas for the write-down of proved properties in the third quarter of 2020. 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. These estimates require significant judgements to be made regarding future development and production costs, development plans and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period and as additional geological data is generated during the course of operations. Ryder Scott prepared 100% of our proved reserve estimates as of December 31, 2020 and 2019. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (i) technical support data, (ii) technical analysis of geologic and engineering support information, (iii) economic and production data and (iv) our well ownership interests and (v) expected future development plans.
Depreciation, Depletion and Amortization. The quantities of estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserve quantities were revised upward or downward, net income would increase or decrease, respectively.
DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for proved leasehold acquisition costs is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. We have one unit-of-production field, the Eagle Ford formation. This method considers the geographic concentration, operating similarities within the area, geologic considerations and common cost environments in this area.
Proved Property Impairment. We assess our proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted cash flows to the carrying value of the oil and gas properties to determine if the carrying value is recoverable. We may apply an additional risk-adjustment factor to the undiscounted cash flows from proved undeveloped reserves. If the carrying value exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows.
Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may incur impairment expense. For 2020, the pricing used in our internal estimate of future cash flows was based on WTI strip prices for the first 24 months, with the price escalating up to a terminal price of $50 in year five and forward. As a result of lower commodity prices at September 30, 2020 and the resulting impact on our estimated future cash flows, the carrying costs of our proved property exceeded our estimated cash flows and we recognized impairment expense of $331.8 million. Following the September 30, 2020 impairment and largely due to the increase in WTI strip pricing at December 31, 2020, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties.
Unproved Property Impairment. Unproved properties consist of costs incurred to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are initially capitalized, and when successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, or future plans to develop acreage.
Derivative Financial Instruments. We use derivative financial instruments to mitigate our exposure to changes in commodity prices arising in the normal course of business. We primarily utilize commodity price swap, option and costless collar contracts. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes, and as a result, all of our derivative contracts are recorded in the consolidated financial statements at fair value, with changes in derivative fair value being recognized currently in earnings.
We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists, who utilize industry-standard models that consider various assumptions, including quoted forward prices for commodities, time to maturity, volatility and credit risk. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources. We also utilize counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas forward prices) or other factors, many of which are beyond our control.
Income Taxes. We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year ended December 31, 2020, we did not recognize tax assets of $139.7 million as the recovery was not determined to be more likely than not. Some or all of these deferred tax assets could be recognized in future periods against future taxable income.
Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. Revisions to our estimated effective tax rate could increase or decrease our reported income tax expense or benefit.
Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily oil and gas properties, is reflected in deferred income taxes. At December 31, 2020 and 2019, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions.
Revenue Recognition. Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the month the product is delivered to the purchaser, while payment is received up to 60 days after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. Historically the differences have not been material.
Transfer of control drives the statement of operations classification of transportation, gathering, processing, and marketing expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of revenue.
Recently Issued Accounting Pronouncements. See Note 1 to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for discussion of the recent accounting pronouncements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Not applicable.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary information required by this Item appears on pages 77 through 117 of this annual report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2020, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.
Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2020 to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act are (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of the year ended December 31, 2020. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on management’s assessment and those criteria, our management believes that we maintained effective internal control over financial reporting as of December 31, 2020.
This annual report does not include an attestation report of our registered independent public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only the management's report in this annual report.
Changes in internal control over financial reporting
There was no change in our internal control over financial reporting that occurred during the fourth quarter of 2020, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance.
The Company’s Board of Directors (the “Board”) and the executive officers of the Company are:
Name
Age
Title and Position
Stephen J. McDaniel(1)
Chairman of the Board & Director
Eric P. McCrady
Director, President & Chief Executive Officer
Judith D. Buie(2)(3)
Director
Damien A. Hannes(2)(4)
Director
H. Weldon Holcombe(3)(4)
Director
Neville W. Martin(1)(3)
Director
Thomas L. Mitchell(2)(4)
Director
Cathy L. Anderson
Executive Vice President, Chief Financial Officer & Treasurer
Christopher I. Humber
Executive Vice President, General Counsel & Secretary
James R. Redfearn
Executive Vice President, Chief Operating Officer
(1) Member of Nominating and Corporate Governance Committee
(2) Member of Audit Committee
(3) Member of Reserves Committee
(4) Member of Compensation Committee
Set forth below is biographical information about each of the Company’s executive officers and directors.
Stephen J. McDaniel was appointed to the Board in December 2019, and is our current Chairman. Mr. McDaniel also has served as an independent director of Ultra Petroleum Corporation from 2006 to 2020 and is presently serving on the Board of Directors of Encino Energy, a $2 billion private exploration and production company, and Bazean Corporation, an oil and gas focused technology company. Mr. McDaniel previously served as a director of Midstates Petroleum Company, where he was previously President and Chief Executive Officer and, later, non-executive Chairman. Since 2013, Mr. McDaniel has served on the Executive Board of the Lone Star Chapter of Big Brothers Big Sisters. His previous experience included approximately ten years of oil and gas investment banking, the majority of which was with Merrill Lynch where he held the position of Managing Director. He began his career with Conoco in 1983 where he held a variety of engineering, operations, and business development positions.
The Board believes that Mr. McDaniel possesses specific attributes that qualify him to serve as a director of the Company, including his significant oil and gas managerial and operational experience, his energy investment banking background, and his financial expertise.
Eric P. McCrady has served as our President & Chief Executive Officer since April 2011, and as a member of the Board since November 2011. He also served as our Chief Financial Officer from June 2010 until becoming President & Chief Executive Officer in 2011. Mr. McCrady also serves as a director, President & Chief Executive Officer of Sundance Energy, Inc., a Colorado corporation, which is our primary operating subsidiary. Mr. McCrady has over 20 years of entrepreneurial experience and he continues to lead the Sundance team that built a 47,000 net acre position in the Eagle Ford through asset acquisitions and direct leasing, including the 2018 acquisition of approximately 22,000 net acres from Pioneer Energy, Inc. and its partners. Previously, Mr. McCrady and the Sundance team built and successfully monetized positions in the Williston, DJ and Anadarko basins. Prior to Sundance Energy, McCrady had over 6 years focused on corporate finance, acquisitions, divestitures, and merger and acquisition arena specific to the energy sector, while at The Broe Group, a Denver-based private investment firm, as well as being a founder and member of Trilogy Resources, a DJ Basin startup that was successfully sold in 2013.
Judith D. Buie was appointed to the Board in February 2019. Ms. Buie has spent over 30 years in the upstream oil and gas business tailoring investment strategies to capture upside and mitigate risk, leading business development initiatives; and managing oil and gas fields through different commodity and life cycles. Ms. Buie currently serves on the Board of Directors for Enerplus Corporation (NYSE: ERF), an independent North American oil and gas exploration and production company, and FlowStream Vintage I Ltd, an international company which owns oil and gas revenue streams. From 2012-2017, Ms. Buie was Co-President and SVP Engineering for RPM Energy Management LLC, a private company which works exclusively with KKR to evaluate and manage oil and gas investments, including multiple joint ventures in the Eagle Ford. Prior to RPM, she held a variety of leadership and technical positions with Newfield Exploration, BP, Vastar Resources, and ARCO. Ms. Buie received a B.S. in Chemical Engineering from Texas A&M University.
The Board believes that Ms. Buie’s extensive upstream and executive management experience makes her qualified to serve as a director of the Company.
Damien A. Hannes has been a Director since August 2009. Mr. Hannes has over 25 years of finance, operations, sales and management experience. He has most recently served over 15 years as a managing director and a member of the operating committee, among other senior management positions, for Credit Suisse’s listed derivatives business in equities, commodities and fixed income in its Asia and Pacific region. From 1986 to 1993, Mr. Hannes was a director for Fay Richwhite Australia, a New Zealand merchant bank. Prior to his tenure with Fay Richwhite, Mr. Hannes was the director of operations and chief financial officer of Donaldson, Lufkin and Jenrette Futures Ltd, a U.S. investment bank. He has successfully raised capital and developed and managed mining, commodities trading and manufacturing businesses in the global market. He holds a Bachelor of Business degree from the NSW University of Technology in Australia and subsequently completed the Institute of Chartered Accounts Professional Year before being seconded into the commercial sector.
The Board believes that Mr. Hannes’ extensive finance background specific to the oil and gas industry makes him qualified to serve as a director of the Company, as well as an audit committee financial expert under the SEC guidelines.
H. Weldon Holcombe has been a director since December 2012. Mr. Holcombe has over 30 years of onshore and offshore U.S. oil and gas industry experience, including technology, reservoir engineering, drilling and completions, production operations, construction, field development and optimization, Health, Safety and Environmental (“HSE”), and management of office, field and contract personnel. Most recently, Mr. Holcombe served as the Executive Vice President, Mid Continental Region, for Petrohawk Energy Corporation from 2006 until its acquisition by BHP Billiton in 2011, after which Mr. Holcombe served as Vice President of New Technology Development for BHP Billiton’s Petroleum Division. In his capacity as Executive Vice President for Petrohawk Energy Corporation, Mr. Holcombe managed development of leading unconventional resource plays, including the Haynesville, Fayetteville and Permian areas. In addition, Mr. Holcombe served as President of Big Hawk LLC, a subsidiary of Petrohawk Energy Corporation, a provider of basic oil and gas construction, logistics and rental services. Mr. Holcombe also served as corporate HSE officer for Petrohawk and joint chairperson of the steering committee that managed construction and operation of a gathering system in Petrohawk’s Haynesville field with one billion cubic feet of natural gas production per day capacity. Prior to Petrohawk, Mr. Holcombe served in a variety of senior level management, operations and engineering roles for KCS Energy and Exxon. Mr. Holcombe has also provided managerial, operational and technical consulting to various companies operating in the Haynesville, Eagle Ford and Permian basins. Mr. Holcombe holds a Bachelor of Science degree in civil engineering from the University of Auburn.
The Board believes that Mr. Holcomb’s extensive experience and knowledge of oil and gas exploration, geology, reservoir engineering, operations and management makes him qualified to serve as a director of the Company.
Neville W. Martin has been a Director since January 2012. Prior to his election, he was an alternate director on our board of directors. Mr. Martin has over 40 years of experience as a lawyer specializing in corporate law and mining, oil and gas law. He was formerly a consultant to the Australian law firm, Minter Ellison. Mr. Martin has served as a director on the boards of several Australian companies listed on the Australian Securities Exchange, including Stuart Petroleum Ltd from 1999 to 2002, Austin Exploration Ltd. from 2005 to 2008 and Adelaide Energy Ltd from 2005 to 2011. Mr. Martin is the former state president of the Australian Resource and Energy Law Association. Mr. Martin holds a Bachelor of Laws degree from Adelaide University.
The Board believes that Mr. Martin’s extensive experience in the oil and gas industry, and his legal experience representing a diverse set of industry clients, makes him qualified to serve as a director of the Company.
Thomas L. Mitchell has been a director since October 2018. Mr. Mitchell is a strategic finance leader with a record of driving growth in energy business models as the CFO of both large and small companies in the Oil and Gas Industry. He has had a career of strong Fortune 500 experience with exploration and production companies, and broad energy exposure with offshore drilling and midstream gathering and marketing companies. In his last position as EVP and Chief Financial Officer of Devon Energy Corporation from 2014 to 2017, Mr. Mitchell lead the finance and business development organizations, and also helped the company successfully strengthen its asset quality through strategic acquisitions. Previously, Mr. Mitchell served as EVP and Chief Financial Officer and a member of the board of directors of Midstates Petroleum Company, a private equity-funded exploration and production company. While there, Mr. Mitchell led the initial public offering listing of the company on the New York Stock Exchange in April 2012. From November 2006 to September 2011, Mr. Mitchell was the Senior Vice President, Chief Financial Officer of Noble Corporation, a publicly-held offshore drilling contractor for the oil and gas industry. Following his formal education, Mr. Mitchell began his career in public accounting with Arthur Andersen & Co. where he practiced as a CPA (currently inactive), then, in 1989 entered the oil and gas industry at Apache Corporation where he spent eighteen years in various finance and commercial roles the last being Vice President and Controller. Mr. Mitchell currently serves on the boards of Ring Energy, Inc. (NYSEAMERICAN: REI), a public exploration and production company, and EPIC Midstream Holdings GP, LLC, a private midstream crude and NGL infrastructure company. He also serves on the board of Hines Global REIT, Inc., a public real estate investment trust which is in its final liquidation phase after a successful eleven-year investment life. He previously served on the board of directors of EnLink Midstream Partners, LP and EnLink Midstream, LLC. Mr. Mitchell graduated from Bob Jones University with a B.S. in Accounting.
The Board believes that Mr. Mitchell’s extensive finance, accounting and executive management experience makes him qualified to serve as a director of the Company, as well as an audit committee financial expert under the SEC guidelines.
Cathy L. Anderson has been our Executive Vice President, Chief Financial Officer & Treasurer since December 2011 and also serves as Executive Vice President, Chief Financial Officer & Treasurer and a director of Sundance Energy, Inc., a Colorado corporation, which is our primary operating subsidiary. Ms. Anderson has over 35 years of experience, primarily in the oil and gas industry, and has extensive experience in budgeting and forecasting, regulatory reporting, corporate controls, and financial analysis and reporting. Prior to joining us in 2011, Ms. Anderson had been a consultant to companies in the oil and gas industry since 2006. Ms. Anderson held various positions, including Chief Financial Officer of Optigas, Inc., a natural gas gathering, processing, and marketing company, from 2005 to 2006 and Vice President of Internal Audit and Consulting for TeleTech Holdings, Inc., a Nasdaq-listed global service firm providing outsourced customer management, from 2002 to 2004. From 1993 to 1999, Ms. Anderson was the Controller and Chief Accounting Officer of NYSE-listed Key Production Company, Inc. (predecessor to Cimarex Energy). She began her career in 1985 with Arthur Andersen, LLP. Ms. Anderson hold a Bachelor of Science in Business Administration with High Honors, emphasis in Accounting, from the University of Montana. She is a certified public accountant.
Christopher I. Humber was appointed our and our operating subsidiary, Sundance Energy, Inc.’s, Executive Vice President, General Counsel & Secretary in July 2020. Previously, Mr. Humber served as Jagged Peak Energy Inc.’s Executive Vice President, General Counsel & Secretary from August 2016 through the company’s February 2017 initial public offering until the company’s merger with Parsley Energy, Inc. in January 2020. Prior to that, he served as the Executive Vice President, General Counsel & Secretary of Bonanza Creek Energy, Inc. from its initial public offering in December 2011 until March 2016. Prior to that, Mr. Humber was a practicing attorney focusing on mergers and acquisitions, corporate finance, and securities matters for public and private companies as a partner with the law firm Kendall, Koenig & Oelsner PC in Denver, Colorado and an associate with the law firms Hogan & Hartson LLP (now Hogan Lovells US LLP) in Denver, Colorado and Arnold & Porter LLP in Washington, D.C. and McLean, Virginia. Mr. Humber graduated with high honors from Emory University School of Law, where he was Editor-in-Chief of the Emory Law Journal, and holds a Bachelor of Arts in Biology from the University of Colorado at Boulder.
James R. Redfearn was appointed as our and our operating subsidiary, Sundance Energy, Inc.’s, Executive Vice President and Chief Operating Officer in September 2020. Mr. Redfearn brings over 18 years of diverse experience in upstream oil and gas operations to the Sundance team. Previous to joining Sundance he was the founder and Chief Executive Officer of 3Fearns LLC, a private exploration and production company formed in 2018 to drill and acquire conventional assets in the Arkoma basin. Prior to that, from 2014 to 2018, he was the Chief Executive Officer of Wagon Wheel Exploration, a private equity backed exploration and production company focused on the Arkoma and ArkLaTex basins. From 2005 until 2012, Mr. Redfearn served as the Vice President of Drilling and Completions for Petrohawk Energy overseeing operations in the Cotton Valley, Haynesville, Fayetteville, Permian and various other Mid-Continent areas until the acquisition by BHP Billiton. He began his career as a Drilling Engineer at Phillips Petroleum Company where he had multiple assignments, including international, deep water, and US Land. Mr. Redfearn holds a B.S. in Petroleum Engineering from the University of Oklahoma.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires the Company’s executive officers, directors and persons who own more than 10% of the Company’s Common Stock to file initial reports of ownership and changes in ownership with the SEC.
Additionally, SEC regulations require that the Company identify any individuals for whom one of the referenced reports was not filed on a timely basis during the most recent fiscal year. Based solely on the Company’s review of Forms 3, 4 and 5 furnished to the Company and any amendments thereto, the Company believes that all persons subject to Section 16(a) of the Exchange Act timely filed all reports required pursuant to such section relating to the Company’s Common Stock in 2020.
CORPORATE GOVERNANCE
General
The Board has adopted a Code of Ethics and Business Conduct and charters for our Audit Committee, Compensation Committee, Nominating and Corporate Governance Committee, and Reserves Committee to assist the Board in the exercise of its responsibilities and to serve as a framework for the effective governance of the Company. You can access our current committee charters and our Code of Ethics and Business Conduct in the “Corporate Governance” section of the “About” page of our website located at www.sundanceenergy.net, or by writing to Investor Relations at our offices at 1050 17th Street, Suite 700, Denver, Colorado 80265.
The Board holds regular and special meetings and spends such time on the affairs of the Company as its duties require. During 2020, the Board held 28 meetings. The Board also meets regularly in non-management executive sessions in accordance with Nasdaq listing rules. Our Chairman provides input to our President & Chief Executive Officer and is responsible for presiding over the meetings of the Board and executive sessions of the independent directors. During 2020, all incumbent directors of the Company attended at least 75% of the meetings of the Board and the committees on which they served. We do not maintain a formal policy regarding director attendance at the Annual Meeting. Absent compelling circumstances, all directors are expected to attend annual meetings in person or online (as applicable) or telephonically.
Board Composition
Our Board consists of seven members: Stephen J. McDaniel, Eric P. McCrady, Judith D. Buie, Damien A. Hannes, H. Weldon Holcombe, Neville W. Martin, and Thomas L. Mitchell. As set forth in our bylaws, each of our directors is elected to serve from the time of election and qualification until the next annual meeting following such election and until his or her successor is duly elected and qualified or until his or her earlier death, resignation or removal. Any vacancies or newly created directorships on the Board may be filled only by a majority vote of the remaining directors on the Board.
Director Independence
Our Board makes all determinations with respect to director independence in accordance with Nasdaq listing rules and the rules and regulations promulgated by the SEC. The actual determination of whether a director is independent is made by the Board on a case-by-case basis. In preparation for the filing of this Annual Report on Form 10-K, the Board undertook its annual review of director independence and considered transactions and relationships between each director or any member of his or her immediate family and the Company and its subsidiaries and affiliates, and has determined that, except for Mr. Eric P. McCrady, our current President & Chief Executive Officer, none of our current directors, specifically, Stephen J. McDaniel, Judith D. Buie, Damien A. Hannes, H. Weldon Holcombe, Neville W. Martin, and Thomas L. Mitchell, have a material relationship with our Company (either directly or as a partner, stockholder or officer of an organization that has a relationship with us) and each of these directors is independent. In making its determination, the Board applied Nasdaq listing standards and SEC rules and regulations.
Director Qualifications
The Nominating and Corporate Governance Committee is responsible for identifying and reviewing the qualifications of potential director candidates and recommending to the Board those candidates to be nominated for election to the Board. To facilitate the search process for director candidates, the Nominating and Corporate Governance Committee may solicit our current directors and executives for the names of potentially qualified candidates or may ask directors and executives to pursue their own business contacts for the names of potentially qualified candidates. The Nominating and Corporate Governance Committee may also consult with outside advisors or retain search firms to assist in the search for qualified candidates or consider director candidates recommended by our stockholders. Although we do not maintain a formal policy for the consideration of director candidates recommended by our stockholders, in such circumstances, the Nominating and Corporate Governance Committee will evaluate individuals recommended by stockholders in the same manner as nominees recommended from other sources. Stockholders who wish to recommend an individual for nomination should send that person’s name and supporting information to the Nominating and Corporate Governance Committee: c/o General Counsel, Sundance Energy Inc., 1050 17th Street, Suite 700, Denver, Colorado 80265.
When identifying prospective director nominees, or reevaluating our current directors, our Board, with assistance from the Nominating and Corporate Governance Committee, considers minimum individual qualifications, including a high level of personal and professional integrity, strong ethics and values and the ability to make mature business judgments and all other factors it considers appropriate, which may include experience in corporate management, experience as a board member of other public companies, relevant professional or academic experience, leadership skills, financial and accounting background, executive compensation background and whether the candidate has the time required to fully participate as a director of the Company.
Additionally, although we do not have a formal policy for the consideration of diversity in identifying director nominees, the Nominating and Corporate Governance Committee believes that the backgrounds and qualifications of the directors, considered as a group, should provide a diverse mix of skills, knowledge, attributes and experiences that cover the spectrum of areas that affect our business. The Nominating and Corporate Governance Committee assesses whether the mix of skills, experience and background of our Board as a whole is appropriate for us. Our Board periodically reviews and assesses the effectiveness of its practices, including with respect to board diversity, used in considering potential director candidates.
Majority Vote in Director Elections
Pursuant to our bylaws, in an election of directors at a meeting of stockholders at which a quorum is present, (i) if the number of nominees exceeds the number of directors to be elected (a “contested election”), directors shall be elected by a plurality of the votes cast by the holders of shares present or represented by proxy and entitled to vote on the election of directors at such meeting and (ii) in an election of directors that is not a contested election (an “uncontested election”), directors shall be elected by a majority of the votes cast by the holders of shares present or represented by proxy and entitled to vote on the election of directors at such meeting. For purposes of the bylaws, in an uncontested election, a “majority of the votes cast” means that the number of shares voted “for” a director must exceed the number of votes cast “against” that director.
Pursuant to our bylaws, in an uncontested election, any nominee for director who is serving as a director (an incumbent) who receives a greater number of votes “against” his or her election than votes “for” such election (a “majority against vote”) shall tender his or her resignation. Within 90 days, the Board is required to decide whether to accept or reject the resignation, and publicly disclose its rationale for the decision.
Board Leadership Structure and Risk Oversight
Our Board has separated the Chairman and Chief Executive Officer roles. We believe that this leadership structure permits the Chief Executive Officer to focus his attention on managing our business and allows the Chairman to function as an important liaison between management and the Board, enhancing the ability of the Board to provide oversight of the Company’s management and affairs. Our Chairman provides input to our Chief Executive Officer and is responsible for presiding over the meetings of the Board and executive sessions of the independent directors. Our Chief Executive Officer is responsible for setting the Company’s strategic direction and for the day-to-day leadership performance of the Company. Based on current circumstances, the direction of the Company and the experienced membership of our Board, our Board believes that separate roles for our Chairman and our Chief Executive Officer, coupled with a majority of independent directors and strong corporate governance guidelines, is the most appropriate leadership structure for our Company and its stockholders at this time.
Our independent directors are involved in the leadership structure of our Board by serving on our Audit Committee, Compensation Committee, Nominating and Corporate Governance Committee, and Reserves Committee, each having a separate independent chairperson. Each committee chair provides independent leadership for purposes of many important functions delegated by our Board of directors to such committee. Our Nominating and Corporate Governance Committee oversees the periodic assessment of the Board and its committees.
Our management is responsible for our day-to-day risk management activities. Our Board oversees the implementation of risk mitigation strategies by management and encourages management to promote a culture that incorporates risk management into our corporate strategy and day-to-day business operations. Management discusses strategic and operational risks, including cybersecurity risks, at management meetings and conducts specific strategic planning and review sessions during the year that include a focused discussion and analysis of the risks facing us. Throughout the year, senior management reviews these risks with the Board at regular board meetings as part of management presentations that focus on particular business functions, operations or strategies, and presents the steps taken by management to mitigate or eliminate such risks. Our Board is apprised of particular risk management matters in connection with its general oversight and approval of corporate matters and significant transactions. Our Board administers this oversight function directly through the Board as a whole, as well as through various standing committees of the Board that address risks inherent in their respective areas of oversight. For example, our Audit Committee is responsible for the oversight of risks relating to our financial statements, auditing and financial reporting processes, key credit risks, liquidity risks and market risks. The Board does not believe that its role in the oversight of our risks affects the Board’s leadership structure. With regard to cybersecurity, we seek to maintain the security of computers, computer networks and data storage resources, and regularly review and discuss best practices with regard to cybersecurity.
Board Committees
The standing committees of the Board are the Audit Committee, Compensation Committee, Nominating and Corporate Governance Committee, and Reserves Committee. Each of the standing committees is governed by a charter, and a copy of the charters of each of these committees is available on the Company’s website at www.sundanceenergy.net under the heading “About-Corporate Governance.” Director membership of all of our standing committees for 2020 is set forth below. The following table identifies the current members of each committee:
Name
Audit
Compensation
Nominating and Corporate Governance
Reserves
Stephen J. McDaniel
Chair
Judith D. Buie
X
X
Damien A. Hannes
X
Chair
H. Weldon Holcombe
X
Chair
Neville W. Martin
X
X
Thomas L. Mitchell
Chair
X
Audit Committee
The Audit Committee assists the Board in monitoring:
• our accounting and financial reporting processes and the integrity of our financial statements;
• audits of our financial statements and the appointment, compensation, qualifications, independence and performance of any independent registered public accounting firm;
• compliance with legal and regulatory requirements; and
• our internal audit function, internal accounting controls, disclosure controls and procedures and internal control over financial reporting.
As of March 31, 2021, the Audit Committee consisted of Thomas L. Mitchell, Judith D. Buie, and Damien A. Hannes, each of whom is independent under the rules of the SEC and Nasdaq listing rules. Mr. Mitchell is the chair of the Audit Committee. Our Board has determined that each of the members of the Audit Committee is financially literate and each of Messrs. Mitchell and Hannes is an “audit committee financial expert” as defined by applicable SEC rules and regulations. During 2020, the Audit Committee met seven times.
Compensation Committee
The Compensation Committee has the following responsibilities:
• determine or make recommendations to the Board regarding the compensation of the CEO and the other executive officers;
• make recommendations to the Board with respect to incentive compensation plans and equity-based plans that are subject to Board approval;
• exercise oversight with respect to the Company’s compensation philosophy, incentive compensation plans, equity-based plans covering executive officers and senior management; and
• review and discuss with management our compensation disclosures if required by SEC rules.
As of March 31, 2021, the Compensation Committee consisted of Damien A. Hannes, H. Weldon Holcombe and Thomas L. Mitchell, each of whom is independent under the rules of the SEC and Nasdaq listing rules. Mr. Hannes is the chair of the Compensation Committee. The Compensation Committee has sole authority to retain and dismiss compensation consultants and other advisors that provide objective advice, information and analysis regarding executive and director compensation. These consultants report directly to and may meet separately with the Compensation Committee and may consult with the Compensation Committee chair between meetings. Meetings may, at the discretion of the Compensation Committee, include members of the Company’s management, other members of the Board, consultants or advisors, and such other persons as the Compensation Committee or its chair may determine.
The Compensation Committee has selected Meridian Compensation Partners, LLC to serve as a consultant to the Compensation Committee on compensation-related issues. During 2020, the Compensation Committee met two times.
Nominating and Corporate Governance Committee
The Nominating and Corporate Governance Committee has the following responsibilities:
• identifies individuals qualified to become members of our Board, consistent with criteria approved by our Board;
• develops, recommends to the Board, and assesses corporate governance policies for the Company; and
• oversees the periodic self-evaluations of management and the Board and its committees.
As of March 31, 2021, the Nominating and Corporate Governance Committee consisted of Stephen J. McDaniel and Neville W. Martin, each of whom is independent under the rules of the SEC and Nasdaq listing rules. Mr. McDaniel is the chair of the Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee has the authority to consult with outside advisors or retain search firms to assist in the search for qualified candidates or consider director candidates recommended by our stockholders. During 2020, the Nominating and Corporate Governance Committee met two times.
Reserves Committee
The Reserves Committee is responsible for monitoring the integrity of the Company’s oil, natural gas, and natural gas liquid reserves, the independence and qualifications of the Company’s independent reserve evaluators, the performance of the Company’s independent reserve evaluators, and our compliance with legal and regulatory requirements. As of [March 31, 2020], the Reserves Committee consisted of H. Weldon Holcombe, Judith D. Buie, and Neville W. Martin. Mr. Holcombe is the chair of the Reserves Committee. During 2020, the Reserves Committee met three times.
Environmental, Social and Governance
We believe that it is of the utmost importance to conduct our business in a way that is consistent with our reputation of operating in a responsible and ethical manner that will serve to protect our employees and contractors, and the lands on which we operate, while supporting the communities in which we live and work. Consistent with this mission the Board, along with management, oversees the Company’s environmental, social and governance programs with a focus on long-term, sustainable investments in our operations, team member development, and protecting the environment in the best interests of all of our stakeholders. The Board is also committed to effective and sustainable corporate governance, which we believe strengthens Board and management accountability, promotes the long-term interests of our shareholders, and helps build public trust in our Company.
Communications with Directors
The Board has established a process to receive communications from stockholders and other interested parties by mail. Shareholders and other interested parties may contact any member of the Board, any Board committee or the entire Board. Our General Counsel is primarily responsible for monitoring communications from stockholders and for providing copies or summaries to the directors as she considers appropriate. To communicate with the Board, any individual director or any committee of directors, correspondence should be addressed to the Board. All such correspondence should be sent to: c/o General Counsel, Sundance Energy Inc., 1050 17th Street, Suite 700, Denver, Colorado 80265.
Any communications to the Company from one of the Company’s officers or directors will not be considered “shareholder communications.” Communications to the Company from one of the Company’s employees or agents will only be considered “shareholder communications” if they are made solely in such employee’s or agent’s capacity as a shareholder. Any shareholder proposal submitted pursuant to Rule 14a-8 promulgated under the Exchange Act will not be viewed as “shareholder communications.”

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
We are a “smaller reporting company,” as such term is defined in Item 10(f) of Regulation S-K). As such, we have opted to comply with the executive compensation disclosure rules in Item 402 (l)-(r) of Regulation S-K applicable to “smaller reporting companies”, which require compensation disclosure for our principal executive officer and the two most highly compensated executive officers other than our principal executive officer. For the fiscal year ending December 31, 2020, these three officers are referred to as our “Named Executive Officers” or “NEOs” as set forth below:
Name
Title and Position
Eric P. McCrady
President & Chief Executive Officer
Cathy L. Anderson
Executive Vice President, Chief Financial Officer & Treasurer
Christopher I. Humber
Executive Vice President, General Counsel & Secretary
Please see page 61 for the biographies and ages of our executive officers.
Overview and Highlights
Our Compensation Committee strives to develop an executive compensation program designed to attract and retain talented executives, reward and encourage maximum corporate and individual performance, and ensure that our executives’ interests are aligned with the interests of our stockholders. In evaluating, designing and implementing our executive compensation program, our Compensation Committee considers the latest industry trends and compensation best practices. The highlights of our executive compensation program include the following:
● We entered into new employment agreements, (i) in January 2020, with respect to Eric McCrady, our President & Chief Executive Officer, and Cathy Anderson, our Executive Vice President, Chief Financial Officer & Treasurer, and (ii) July 2020 with respect to Chris Humber, our Executive Vice President, General Counsel & Secretary. These employment agreements each include a “double trigger” change of control provision with respect to the vesting of equity awards granted to our NEOs. The material terms of these employment agreements are summarized below under “Employment Agreements” and “Potential Payments upon Termination or Change in Control.”
● To support our liquidity in light of the COVID-19 pandemic, we elected to defer both 2019 and 2020 short-term incentive plan (“STI Plan”) payments to our NEOs.
● In May 2020, in response to the impact of the COVID-19 pandemic on the Company and the oil and gas industry generally, Mr. McCrady and Ms. Anderson each voluntarily elected to temporarily reduce their base salaries, with Mr. McCrady reducing his base salary by 25%, and Ms. Anderson reducing her base salary by 20%. Mr. Humber voluntarily elected to reduce his base salary by 20% upon joining us in July 2020.
● We also deferred all 2019 and 2020 equity awards.
Summary Compensation Table
The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for 2020 and 2019:
Name and Principal Position
Year
Salary
($)
Stock Awards
($)
Bonus
($)(1)
Non-Equity Incentive Plan Compensation
($)(1)
All Other Compensation
($)
Total
($)
Eric P. McCrady
408,053
-
-
291,412
43,580
(2)
743,045
President & Chief Executive Officer
485,000
-
-
-
41,285
526,285
Cathy L. Anderson
337,202
-
-
163,940
36,113
(3)
537,255
Chief Financial Officer
377,500
-
-
-
34,346
411,846
Christopher I. Humber
General Counsel
(4)
130,308
-
-
23,380
14,568
(5)
168,256
(1) At December 31, 2019, Mr. McCrady and Ms. Anderson had accrued but unpaid bonus amounts for 2019 of $232,410 and $125,789, respectively. On December 9, 2021, the Board approved a Key Employee Retention Plan (“KERP”) in order to retain the NEOs during the pendency of the Company’s restructuring, into which these amounts were subsumed along with 2020 bonus amounts of $392,745 for Mr. McCrady, $249,205 for Ms. Anderson and $141,718 for Mr. Humber. Additionally, the Board approved Key Employee Incentive Plan (“KEIP”) payments in the amounts of $187,733 for Mr. McCrady, $117,902 for Ms. Anderson and $58,282 for Mr. Humber to incentivize performance during the Company’s restructuring. Amounts listed reflect amounts recognized for 2020; the remainder of the KEIP and KERP payments approved will be recognized in 2021. The KERP and KERP payments have not been made. See Annual Cash Bonuses under STI Plan.
(2) For 2020, includes $23,680 for medical and disability coverage and life insurance, $17,100 for Company 401(k) contributions, and $2,800 for parking.
(3) For 2020, includes $16,253 for medical and disability coverage and life insurance, $17,100 for Company 401(k) contributions, and $2,760 for parking.
(4)Partial Year. Mr. Humber became our General Counsel in July 2020.
(5)Includes $5,330 for medical and disability coverage and life insurance, $7,818 for Company 401(k) contributions, and $1,420 for parking.
Narrative Disclosure to Summary Compensation Table
For 2020, the principal elements of compensation provided to the Named Executive Officers were base salaries and retirement, health, welfare, and additional benefits. Each of our Named Executive Officers are party to an employment agreement, as described below.
Employment Agreements
On January 24, 2020, the Company and its wholly-owned subsidiary Sundance Energy, Inc., a Colorado corporation, entered into employment agreements with each of Eric P. McCrady and Cathy L. Anderson pursuant to which they would serve as the Company’s Chief Executive Officer and Chief Financial Officer, respectively. Each of these employment agreements provide for a three-year term, expiring on January 23, 2023. On July 8, 2020, the Company and its wholly-owned subsidiary Sundance Energy, Inc., a Colorado corporation, entered into an employment agreement with Christopher I. Humber to serve as our Executive Vice President, General Counsel & Secretary for a term of three years, expiring July 20, 2023.
Mr. McCrady’s employment agreement entitles him to receive the following: (i) an annual base salary of $485,000; (ii) an annual cash performance bonus having a target of 100% of his annual base salary, to be based on such criteria and achievements as determined by the Company’s Compensation Committee; (iii) cash or equity awards that may be awarded by the Company’s Compensation Committee in accordance with any long-term incentive plans or equity incentive plans that may be adopted by the Company’s Board from time to time; and (iv) such other benefits, including health insurance and vacation, to the same extent as such benefits are available to the Company’s other executive officers.
Ms. Anderson’s employment agreement entitles her to receive the following: (i) an annual base salary of $400,000; (ii) an annual cash performance bonus having a target of 75% of her annual base salary, to be based on such criteria and achievements as determined by the Company’s Compensation Committee; (iii) cash or equity awards that may be awarded by the Company’s Compensation Committee in accordance with any long-term incentive plans or equity incentive plans that may be adopted by the Company’s Board from time to time; and (iv) such other benefits, including health insurance and vacation, to the same extent as such benefits are available to the Company’s other executive officers.
Mr. Humber’s employment agreement entitles him to receive the following: (i) an annual base salary of $385,000; (ii) an annual cash performance bonus having a target of 75% of his annual base salary, to be based on such criteria and achievements as determined by the Company’s Compensation Committee; (iii) cash or equity awards that may be awarded by the Company’s Compensation Committee in accordance with any long-term incentive plans or equity incentive plans that may be adopted by the Company’s Board from time to time with a target value of 200% of base salary; and (iv) such other benefits, including health insurance and vacation, to the same extent as such benefits are available to the Company’s other executive officers.
Each NEO’s employment agreement provides that such NEO’s respective agreement can be terminated at any time during the term, provided that the Company’s right to terminate is subject to its obligation to make certain severance payments and provide certain other benefits, depending upon the circumstances under which the employment relationship is terminated. The Company is generally not obligated under the employment agreements to provide any severance payments or benefits if any of the NEOs is terminated for good cause, or if any of the NEOs resign without good reason. If an NEO’s employment agreement is terminated by the Company without good cause, or they resign for good reason, in each case other than in connection with a change of control (as defined in the applicable employment agreement), they will be entitled to receive: (i) a lump sum cash payment equal to the greater of (a) base salary for (1) 24 months for Mr. McCrady or (2) 18 months for Ms. Anderson and Mr. Humber and (b) the amount of base salary that would have been payable for the remaining portion of the employment term; (ii) the average annual bonus for the two fiscal years prior to the termination; (iii) the target annual bonus for the year in which the termination occurred; and (iv) continued coverage under the Company’s health and welfare benefits programs for the shorter of (a) 12 months following termination (or the end of the original employment term under the employment agreement, whichever is later) and (b) the date on which comparable coverage is obtained under a subsequent employer plan. If an NEO’s employment is terminated by the Company without good cause, or they resign for good reason, in each case within 24 months following a change in control, then they will be entitled to receive the same severance amounts described above, except that they will instead be entitled to receive continued coverage under the Company’s health and welfare benefits programs for the shorter of (a) 18 months following termination (or the end of the original employment term under the employment agreement, whichever is later) and (b) the date on which comparable coverage is obtained under a subsequent employer plan, as well as the accelerated vesting of any outstanding long term incentive awards, with any such awards that are subject to performance-based vesting becoming payable at the target level and in an amount that is pro-rated to reflect the portion of the applicable performance or vesting period prior to termination.
Annual Cash Bonuses under STI Plan
The available bonus pool under our STI Plan is based on a percentage of each employee’s annual base salary. As described under “Employment Agreements” above, the target bonus for Mr. McCrady is 100% of base salary, and for Ms. Anderson and Mr. Humber is 75% of base salary.
Historically, on an annual basis, targets are established and agreed by our Compensation Committee, subject to approval by our Board. Bonuses earned under the STI are typically paid in cash. In 2020, to support our liquidity in light of the ongoing COVID-19 pandemic, we elected to defer 2019 STI Plan payments to our NEOS. Accordingly, all bonuses under the STI Plan relative to the Company’s 2019 performance and have not been awarded. At December 31, 2019, Mr. McCrady and Ms. Anderson had accrued but unpaid bonus amounts for 2019 of $232,410 and $125,789, respectively. On December 9, 2020, the Board approved a Key Employee Retention Plan (“KERP”) in order to retain the Named Executive Officers during the pendency of the Company’s restructuring, into which these amounts were subsumed.
For 2020, in light of the continuing COVID-19 pandemic, historic decline in commodity prices and the unprecedented level of market volatility affecting the oil and gas industry, the Company determined that its historic compensation structure and any performance metrics would be ineffective in motivating and incentivizing the Company’s workforce. With the advice of a compensation consultant and legal advisors, the Company elected to make any cash bonus for 2020, 100% discretionary. The Board approved KERP amounts of $392,745 for Mr. McCrady, $249,205 for Ms. Anderson and $141,718 for Mr. Humber for 2020 in lieu of 2020 cash bonus payments. Additionally, the Board approved Key Employe Incentive Plan (“KEIP”) payments in the amounts of $187,733 for Mr. McCrady, $117,902 for Ms. Anderson and $58,282 for Mr. Humber to incentivize performance during the Company’s restructuring. However, because the Company was in the process of negotiating the RSA and the transactions contemplated thereby, neither the KEIP nor the KERP payments have been made.
Long-Term Incentive Plan
Historically, our predecessor, SEAL, issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “SEAL LTI Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals. In connection with our Redomiciliation, the Company agreed to assume SEAL’s obligations under the SEAL LTI Plan to issue shares upon the vesting of the RSUs. RSUs awarded in 2019 will be settled in shares of our Common Stock. In July 2020, our stockholders approved our 2020 Equity Incentive Plan, which provides for up to 750,000 new grants by the Company of stock options, stock appreciation rights, restricted stock or units, bonus stock and other stock-based awards. The Company has yet to issue any awards under the 2020 Equity Incentive Plan.
Outstanding Equity Awards at Fiscal Year End
The following table reflects information regarding outstanding RSU awards held by our NEOs as of December 31, 2020:
Stock Awards
Number of Shares or
Units of Stock That
Have Not Vested
Market Value of Shares
or Units of Stock That
Have Not Vested
Eric P. McCrady
-
-
Cathy L. Anderson
-
-
Christopher I. Humber
-
-
Other Benefits
In addition to the compensation discussed above, our executives receive health and welfare plan benefits. The Company provides a 401(k) plan to all eligible full-time employees, which allows for pre-tax employee contributions up to the maximum allowed by the Internal Revenue Code of 1986, as amended (the “Code”). The Company supplements the employee’s contribution by providing 6% of the employee’s eligible contribution. This contribution is deposited on each bi-weekly payroll and is 100% vested to the employee’s account.
Potential Payments Upon Termination or a Change in Control
Our Named Executive Officers are parties to employment agreements that provide them with post-termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of voluntary termination, involuntary termination without good cause, termination following a change of control and in the event of disability or death of the executive. The following are general definitions have been summarized and are qualified in their entirety by the full text of the applicable agreements to which our NEOs are parties. For a description of these employment agreements, see “Narrative Disclosure to the Summary Compensation Table ⸺ Employment Agreements” above.
The employment agreements for our NEOs each provide for the payment of severance and benefits if their agreements are terminated without “good cause” or if our NEOs resign for “good reason”. For purposes of the agreements, “good cause” means (i) willful misconduct which results in a material breach or substantial failure by the executive to comply with or perform a material term of the employment agreement, (ii) the executive’s gross negligence in the performance of the executive’s duties, (iii) executive’s commitment of fraud on the Company or (iv) any conviction of, or plea of nolo contendere to, any felony involving a crime of moral turpitude, in each case provided that the executive has received written notice of a termination for good cause, and executive fails to cure the event constituting good cause within 15 days (or such reasonable period as is required to cure the event constituting good cause, as determined by the Board) following the receipt of notice.
“Good reason” under the agreements means (i) a material diminution in executive’s status as an executive officer of the Company, (ii) a material reduction in base salary or bonus target without the executive’s consent and (iii) the relocation of the offices at which the executive is principally employed to a location more than 50 miles from such office (unless such change does not materially increase the commuting distance from the executive’s then current principal residence). In each case, the executive must provide advance notice of the existence of an action giving rise to a termination for good reason, after which the Company will have 30 days to cure such action or event.
In addition to the severance and benefits payable to our NEOs following a termination without good cause, or resignation for good reason, if the termination occurs within 24 months following a change of control, they will also be entitled to receive accelerated vesting of any outstanding long-term incentive awards, with any such awards that are subject to performance-based vesting becoming payable at the target level and in an amount that is pro-rated to reflect the portion of the applicable performance or vesting period prior to termination.
Under the agreements, a “change of control” means the occurrence of any of the following: (i) the acquisition by a person of 50% or more of the voting equity of the Company, unless after the transaction the stockholders of the Company continue to retain the same proportion as their ownership of our voting stock immediately prior to such acquisition; (ii) a majority of members of the existing board of directors is replaced during any 12 month period by directors whose appointment or election is not endorsed by a majority of the members of the board of directors prior to the date of the appointment or election; and (iii) a change in the ownership of a substantial portion of the Company’s assets which occurs on the date that any person acquires (or has acquired during the 12 month period ending on the date of the most recent acquisition by such person or persons) assets from the Company that have a total gross fair market value equal to or more than 50% of the total gross fair market value of all of the assets of the Company immediately prior to such acquisition or acquisitions. In no event will a change in control occur as a result of a transaction that is effected for the purpose of changing the place of incorporation or form of organization of the Company, where all or substantially all of the holders of the Company’s voting stock prior to the transaction continue to beneficially own all or substantially all of the combined voting power of the Company in substantially the same proportions of their ownership after the transaction. We expect that once we emerge from the Chapter 11 Cases as a private company, a “change of control” will be triggered under the employment agreements, but would require the second trigger of a termination for good cause or resignation for good reason to result in severance payments.
Director Compensation
The following table sets forth the compensation earned by each non-employee Director during our fiscal year ended December 31, 2020.
Name
Paid in Cash
($) (1)
Stock Awards
($)
All Other Compensation
($)
Total
($)
Stephen J. McDaniel
135,333
-
-
135,333
Michael D. Hannell(2)
28,583
-
-
28,583
Judith D. Buie
78,000
-
-
78,000
Damien A. Hannes
90,000
-
-
90,000
H. Weldon Holcombe
84,000
-
-
84,000
Neville W. Martin
75,333
-
-
75,333
Thomas L. Mitchell
97,000
-
-
97,000
(1)
Represents annual board and chair retainers.
(2)
Mr. Hannell retired on April 8, 2020.
Narrative Disclosure to the Director Compensation Table
The Board has primary responsibility for establishing non-employee director compensation arrangements, which have been designed to provide competitive compensation necessary to attract and retain high quality non-employee directors and to further align the interests of our directors with those of our stockholders. Arrangements in effect for 2020 provided each non-employee director compensation with a fixed retainer and service fees. In addition, we reimburse our directors for travel, lodging and related expenses incurred in attending Board and committee meetings.
In April 2020, in response to the impact of the COVID-19 pandemic on the Company and the oil and gas industry generally, each Board member voluntarily elected to temporarily reduce their retainer fees by 20%.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Securities Authorized for Issuance under Equity Compensation Plans
The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2020.
Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)(2)
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column
(a)(3) (c )
Equity compensation plans approved by security holders
-
-
750,000
Equity compensation plans not approved by security holders
7,596
(1)
-
(2)
-
Total
7,596
-
750,000
(1)
Represents shares of Common Stock subject to outstanding RSU awards that were issued under the SEAL LTI Plan.
(2)
The RSUs issued under the SEAL LTI Plan do not have an exercise price.
(3)
In connection with our Redomiciliation, the Company agreed to assume SEAL’s obligations under the SEAL LTI Plan to issue shares upon the vesting of the RSUs issued under the SEAL LTI Plan. Following the Redomiciliation, no new awards or grants have been or will be made pursuant to the SEAL LTI Plan.
Security ownership of certain beneficial owners and management.
The following table presents the beneficial ownership of our Common Stock as of March 31, 2021 for (i) each person beneficially owning more than 5% of the outstanding shares of our Common Stock, (ii) each director of the Company, (iii) each executive officer of the Company listed in the Summary Compensation Table and (iv) all of our directors and executive officers as a group.
Except pursuant to applicable community property laws and except as otherwise indicated, each stockholder possesses sole voting and investment power with respect to its, his or her shares. The business address of each of our directors and executive officers is c/o Sundance Energy Inc., 1050 17th Street, Suite 700 Denver, Colorado 80265. The applicable percentage ownership is based on 6,876,422 shares of our Common Stock issued and outstanding as of March 31, 2021, plus, on an individual basis, the right of that individual to (i) obtain Common Stock upon the vesting or delivery of restricted stock units, in each case within 60 days of March 31, 2021. The information is based on Form 3s, Form 4s, Schedule 13Ds, Schedule 13Gs and Schedule 13G/As filed through March 31, 2021.
Amount and Nature of
Percent
Name
Ownership of Common Stock
of Class
Directors and Named Executive Officers:
Stephen J. McDaniel
⸺
*
Judith D. Buie
1,970
*
Damien A. Hannes(1)
14,397
*
H. Weldon Holcombe
1,854
*
Neville W. Martin(2)
1,688
*
Thomas L. Mitchell
1,085
*
Eric P. McCrady
7,889
*
Cathy L. Anderson
2,077
*
Christopher I. Humber
⸺
*
All Directors and Executive Officers as a Group (9 persons)
30,960
*
(1)
Includes 9,411 shares of Common Stock held of record by a trust of which Mr. Hannes serves as a director and shares voting and investment power.
(2)
Includes (i) 1,496 shares of Common Stock held of record by a trust of which Mr. Martin serves as a trustee and is a beneficiary and (ii) 8 shares of Common Stock owned by Mr. Martin’s spouse.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Transactions with Related Persons
During 2019 and 2020 there was not, nor was there proposed as of December 31, 2020, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 or 1% of our total assets at year end and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in Item 11 “Executive Compensation” above.
Director Independence
Our Board makes all determinations with respect to director independence in accordance with Nasdaq listing rules and the rules and regulations promulgated by the SEC. The actual determination of whether a director is independent is made by the Board on a case-by-case basis.
In connection with the filing of this Annual Report on Form 10-K, the Board undertook its annual review of director independence and considered transactions and relationships between each director or any member of his or her immediate family and the Company and its subsidiaries and affiliates, and has determined that, except for Mr. Eric P. McCrady, our current President & Chief Executive Officer, none of our current directors, Stephen J. McDaniel, Judith D. Buie, Damien A. Hannes, H. Weldon Holcombe, Neville W. Martin, and Thomas L. Mitchell, have a material relationship with our Company (either directly or as a partner, stockholder or officer of an organization that has a relationship with us) and each of these directors is independent. In making its determination, the Board applied Nasdaq listing standards and SEC rules and regulations.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The following table presents fees for professional audit services rendered by Deloitte for the audit of the Company’s annual financial statements for the years ended December 31, 2020 and 2019, and fees for other services rendered by Deloitte during those periods, all of which were approved by the Audit Committee:
2020 ($)
2019 ($)
Audit fees
572,350
910,315
Audit-related fees
-
-
Tax fees
-
-
All other fees
86,590
179,170
Total
658,940
1,089,485
Audit Fees
Audit fees consist of fees billed for the audit of our annual consolidated financial statements, the review of the interim consolidated financial statements, and related services that are normally provided in connection with registration statements. Such services can only be provided by our principal accountants. Fees for the year ended December 31, 2019 included approximately $203,770 for one-time audit-services performed on our conversion of historical accounting records from IFRS to GAAP in connection with our Redomiciliation.
Audit-Related Fees
We did not incur any audit-related fees in 2020 or 2019.
Tax Fees
We did not incur any fees for tax advice, planning and other services in 2020 or 2019.
All Other Fees
During 2020 and 2019, we engaged Deloitte & Touche LLP’s advisory services group to analyze our previously filed severance tax returns and other relevant information to identify additional marketing cost deductions and statutory exemptions not previously taken by the Company.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules.
Financial Statements. Refer to the Index to our Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this annual report for a list of all financial statements filed as part of this report.
Financial Statement Schedules. All schedules are omitted since the required information is not present, or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in our Consolidated Financial Statements or the Notes thereto included in Item 8. “Financial Statements and Supplementary Data” of this annual report.
Exhibits. The exhibits listed in the accompanying exhibit index are filed (except where otherwise indicated) as part of this report.