# SM Energy Co (SM) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from SM Energy Co's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/893538/000089353822000020/sm-20211231.htm
Accession: 0000893538-22-000020
Filing date: 2022-02-25
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/SM/
All MD&A years: /company/SM/mda/
Next year: /company/SM/mda/fy2022/ (FY 2022)

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

The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.

Overview of the Company

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. Our short-term operational and financial goals include generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term vision is to sustainably grow value for all of our stakeholders. We believe that in order to accomplish this vision, we must be a premier operator of top-tier oil and gas assets. Our strategy for achieving these goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the development and implementation of the Company’s ESG policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2022 annual meeting of stockholders to be filed within 120 days from December 31, 2021, for additional discussion.

The markets for the commodities produced by our industry strengthened in 2021 as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with oil and natural gas prices reaching their highest average annual price since 2014. However, commodity markets remain subject to heightened levels of uncertainty related to the Pandemic and escalating tensions between Russia and Ukraine. Russian military incursion into Ukraine could give rise to regional instability and result in heightened economic sanctions by the U.S. and the international community that, in turn, could increase uncertainty with respect to global financial markets and production output from OPEC+ and other oil producing nations. Additionally, the Pandemic remains a global health crisis and continues to evolve. Despite the emergence of new variants, deployment of vaccines and vaccine boosters to slow the spread of the COVID-19 virus has resulted in substantial improvements in global financial markets and public health. Disruption in financial and commodity markets and industry-specific impacts could result from future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, and as a result, may require us to adjust our business plan. Despite continuing impacts of the Pandemic, geopolitical issues, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top-tier Midland Basin and South Texas assets.

Throughout the Pandemic, the safety of our employees, contractors, and the communities where we work has remained our first priority. While our core business operations require certain individuals to be physically present at well site locations, the majority of our office-based employees have worked remotely since the onset of the Pandemic, in order to limit physical interactions and to mitigate the spread of COVID-19. We maintain and continually assess procedures designed to limit the spread of COVID-19, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and OSHA guidelines related to the prevention of the transmission of COVID-19. Throughout the Pandemic, we have operated without significant disruptions to our business, and we believe that our pre-existing control environment and internal controls continue to be effective.

2021 Financial and Operational Highlights

We remain focused on maximizing returns and increasing the value of our top-tier Midland Basin and South Texas assets. We expect to do this through continued development optimization and further delineation of our Midland Basin assets and through further development of our Austin Chalk formation in South Texas. We believe our assets provide strong returns and are capable of providing for growth of internally generated cash flows while allowing for flexibility of production levels, which aligns with our priorities of reducing debt, improving leverage metrics and maintaining strong financial flexibility.

Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2021, increased 11 percent to 140.7 MBOE, compared with 126.9 MBOE for 2020, comprised of a 19 percent increase from our Midland Basin assets

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and a two percent decrease from our South Texas assets. The total increase resulted from an increased number of completions, strong well performance, and our continued focus on operational execution. Realized prices for oil, gas, and NGLs increased 83 percent, 169 percent, and 141 percent, respectively, for the year ended December 31, 2021, compared with 2020. As a result of increased realized prices, oil, gas, and NGL production revenue increased 131 percent to $2.6 billion for the year ended December 31, 2021, compared with $1.1 billion for 2020. We recorded a net derivative loss of $901.7 million for the year ended December 31, 2021, compared to a net derivative gain of $161.6 million for 2020. These amounts include a derivative settlement loss of $749.0 million for the year ended December 31, 2021, and a derivative settlement gain of $351.3 million for the year ended December 31, 2020. Operational activities during the year ended December 31, 2021, resulted in the following financial and operational results:

•Net cash provided by operating activities of $1.2 billion for the year ended December 31, 2021, which was in excess of net cash used in investing activities of $667.2 million for the same period. Please refer to Analysis of Cash Flow Changes Between 2021 and 2020 and Between 2020 and 2019 in Part II, Item 8 of this report below for additional discussion.

•A cash balance of $332.7 million and no outstanding balance on the revolving credit facility as of December 31, 2021, compared with a revolving credit facility balance of $93.0 million as of December 31, 2020.

•Net income of $36.2 million, or $0.29 per diluted share, for the year ended December 31, 2021, compared with a net loss of $764.6 million, or $6.72 per diluted share for 2020. Net income for the year ended December 31, 2021, was primarily a result of increased production volumes and improved pricing, substantially offset by net derivative losses of $901.7 million. Please refer to Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 below for additional discussion regarding the components of net income (loss) for each period presented.

•Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2021, of $1.2 billion, compared with $975.4 million for 2020. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.

•Total estimated proved reserves as of December 31, 2021, increased 22 percent from December 31, 2020, to 492.0 MMBOE, of which, 58 percent were liquids (oil and NGLs) and 61 percent were proved developed reserves. We added 139.1 MMBOE through extensions and infill as a result of continued success in and further development of our Austin Chalk and Midland Basin assets, partially offset by 51.4 MMBOE of production during 2021 and the removal of 40.6 MMBOE of proved undeveloped reserves reclassified to unproved reserves categories as a result of development plan optimization. Our proved reserve life index increased to 9.6 years as of December 31, 2021, compared with 8.7 years as of December 31, 2020. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $7.0 billion as of December 31, 2021, compared with $2.7 billion as of December 31, 2020, which was an increase of 160 percent year-over-year. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Operational Activities. During 2021, we continued to experience strong well performance in the RockStar area of our Midland Basin position due to successful operational execution, enhanced completion designs, and execution of our development strategy to drill and complete long laterals resulting from successful infill leasing and acreage trades, which have increased the contiguous nature of our acreage position. A large portion of our water transportation and disposal needs continue to be satisfied by the water facilities we operate in a core area of our RockStar acreage. Our South Texas program benefited from successful development of the Austin Chalk formation and continued strong performance from Eagle Ford shale wells. Efficiency and optimization in completions and operations in both the Midland Basin and in South Texas continued throughout 2021, and effective partnerships with our key service providers have allowed us to maintain continuity of operations during the Pandemic.

Our Midland Basin program averaged three drilling rigs and two completion crews during 2021. We drilled 61 gross (49 net) wells and completed 97 gross (81 net) wells during 2021 and net equivalent production increased year-over-year by 18 percent to 34.4 MMBOE. Costs incurred during 2021 totaled $433.8 million, or 60 percent of our total 2021 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on developing the Spraberry and Wolfcamp formations.

Our South Texas program averaged one drilling rig and one completion crew during 2021. We drilled 32 gross (32 net) and completed 31 gross (28 net) wells during 2021 and net equivalent production decreased year-over-year by two percent to 16.9 MMBOE. Costs incurred during 2021 totaled $240.7 million, or 34 percent of our total 2021 costs incurred. Drilling and completion activities in South Texas during 2021 were primarily focused on developing the Austin Chalk formation.

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The table below provides a summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the year ended December 31, 2021:

[[GREPCENT_TABLE]]
[["","Midland Basin","","South Texas","","Total"],["","Gross","","Net","","Gross","","Net","","Gross","","Net"],["Wells drilled but not completed at December 31, 2020 (1)","66","","","58","","","31","","","28","","","97","","","86"],["Wells drilled","61","","","49","","","32","","","32","","","93","","","81"],["Wells completed","(97)","","","(81)","","","(31)","","","(28)","","","(128)","","","(109)"],["Other (2)","\u2014","","","1","","","\u2014","","","\u2014","","","\u2014","","","1"],["Wells drilled but not completed at December 31, 2021 (3)","30","","","27","","","32","","","32","","","62","","","59"]]
[[/GREPCENT_TABLE]]

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(1)    The South Texas drilled but not completed well count as of December 31, 2020, included 13 gross (13 net) wells that were not included in our five-year development plan, 12 of which were in the Eagle Ford shale.

(2)    Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells. Working interest changes can result from divestitures, joint development agreements, farm-outs, and other activities.

(3)    The South Texas drilled but not completed well count as of December 31, 2021, includes 11 gross (11 net) wells that are not included in our five-year development plan, 10 of which are in the Eagle Ford shale.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

[[GREPCENT_TABLE]]
[["","For the Year Ended"],["","December 31, 2021"],["","(in millions)"],["Development costs","$","583.5"],["Exploration costs","125.4"],["Acquisitions"],["Proved properties","0.1"],["Unproved properties","9.0"],["Total, including asset retirement obligations (1)","$","718.0"]]
[[/GREPCENT_TABLE]]

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(1)    Please refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2021:

[[GREPCENT_TABLE]]
[["","Midland Basin","","South Texas","","Total"],["Net production volumes:"],["Oil (MMBbl)","25.2","","","2.7","","","27.9"],["Gas (Bcf)","55.4","","","52.9","","","108.4"],["NGLs (MMBbl)","\u2014","","","5.4","","","5.4"],["Equivalent (MMBOE)","34.4","","","16.9","","","51.4"],["Average net daily equivalent (MBOE per day)","94.4","","","46.4","","","140.7"],["Relative percentage","67","%","","33","%","","100","%"]]
[[/GREPCENT_TABLE]]

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Note: Amounts may not calculate due to rounding.

Net equivalent production increased 11 percent for the year ended December 31, 2021, compared with 2020, comprised of an 18 percent increase from our Midland Basin assets and a two percent decrease from our South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 below for additional discussion on production.

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Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effects of derivative settlements, for the years ended December 31, 2021, 2020, and 2019:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["Oil (per Bbl):"],["Average NYMEX contract monthly price","$","67.92","","","$","39.40","","","$","57.03"],["Realized price","$","67.72","","","$","37.08","","","$","54.10"],["Effect of oil derivative settlements","$","(18.73)","","","$","14.40","","","$","(0.90)"],["Gas:"],["Average NYMEX monthly settle price (per MMBtu)","$","3.84","","","$","2.08","","","$","2.63"],["Realized price (per Mcf)","$","4.85","","","$","1.80","","","$","2.39"],["Effect of gas derivative settlements (per Mcf)","$","(1.41)","","","$","0.11","","","$","0.21"],["NGLs (per Bbl):"],["Average OPIS price (1)","$","36.65","","","$","17.96","","","$","22.34"],["Realized price","$","33.67","","","$","13.96","","","$","17.26"],["Effect of NGL derivative settlements","$","(13.68)","","","$","1.28","","","$","4.43"]]
[[/GREPCENT_TABLE]]

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(1)    Average OPIS prices per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

Commodity prices in 2021 significantly improved from historic lows experienced in 2020 as a result of the misalignment of supply and demand caused by the Pandemic and other macroeconomic events. Given the dynamic nature of the Pandemic, uncertainty surrounding the escalating tensions between Russia and Ukraine, and the potential impacts to global commodity and financial markets, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Our realized prices at local sales points may also be affected by infrastructure capacity in the area of our operations and beyond.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 10, 2022, and December 31, 2021:

[[GREPCENT_TABLE]]
[["","As of February 10, 2022","","As of December 31, 2021"],["NYMEX WTI oil (per Bbl)","$","83.82","","","$","72.89"],["NYMEX Henry Hub gas (per MMBtu)","$","4.15","","","$","3.69"],["OPIS NGLs (per Bbl)","$","41.29","","","$","37.02"]]
[[/GREPCENT_TABLE]]

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows

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us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Outlook

Our total 2022 capital program, which we expect to fund with cash flows from operations, is expected to be approximately $750.0 million. We expect to focus our 2022 capital program on highly economic oil development projects in both our Midland Basin assets and our South Texas assets.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended December 31, 2021, and the preceding three quarters.

[[GREPCENT_TABLE]]
[["","For the Three Months Ended"],["","December 31,","","September 30,","","June 30,","","March 31,"],["","2021","","2021","","2021","","2021"],["","(in millions)"],["Net equivalent production (MMBOE)","14.6","","","14.3","","","12.4","","","10.0"],["Oil, gas, and NGL production revenue","$","852.4","","","$","759.8","","","$","562.6","","","$","423.2"],["Oil, gas, and NGL production expense","$","143.3","","","$","135.7","","","$","125.5","","","$","100.9"],["Depletion, depreciation, amortization, and asset retirement obligation liability accretion","$","200.0","","","$","202.7","","","$","204.7","","","$","167.0"],["Exploration","$","12.6","","","$","8.7","","","$","8.7","","","$","9.3"],["General and administrative","$","37.1","","","$","25.5","","","$","24.6","","","$","24.7"],["Net income (loss)","$","424.9","","","$","85.6","","","$","(223.0)","","","$","(251.3)"]]
[[/GREPCENT_TABLE]]

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Note: Amounts may not calculate due to rounding.

Selected Performance Metrics

[[GREPCENT_TABLE]]
[["","For the Three Months Ended"],["","December 31,","","September 30,","","June 30,","","March 31,"],["","2021","","2021","","2021","","2021"],["Average net daily equivalent production (MBOE per day)","158.3","","","155.8","","","136.5","","","111.6"],["Lease operating expense (per BOE)","$","4.21","","","$","4.20","","","$","4.62","","","$","4.64"],["Transportation costs (per BOE)","$","2.61","","","$","2.41","","","$","3.01","","","$","2.94"],["Production taxes as a percent of oil, gas, and NGL production revenue","4.8","%","","4.7","%","","4.5","%","","4.6","%"],["Ad valorem tax expense (per BOE)","$","0.22","","","$","0.38","","","$","0.45","","","$","0.52"],["Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE)","$","13.74","","","$","14.14","","","$","16.48","","","$","16.62"],["General and administrative (per BOE)","$","2.55","","","$","1.78","","","$","1.98","","","$","2.46"]]
[[/GREPCENT_TABLE]]

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Note: Amounts may not calculate due to rounding.

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Overview of Selected Production and Financial Information, Including Trends

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,","","Amount Change Between","","Percent Change Between"],["","2021","","2020","","2019","","2021/2020","","2020/2019","","2021/2020","","2020/2019"],["Net production volumes: (1)"],["Oil (MMBbl)","27.9","","","23.0","","","21.9","","","4.9","","","1.1","","","21","%","","5","%"],["Gas (Bcf)","108.4","","","103.9","","","109.8","","","4.5","","","(5.9)","","","4","%","","(5)","%"],["NGLs (MMBbl)","5.4","","","6.1","","","8.1","","","(0.7)","","","(2.0)","","","(12)","%","","(25)","%"],["Equivalent (MMBOE)","51.4","","","46.4","","","48.3","","","4.9","","","(1.9)","","","11","%","","(4)","%"],["Average net daily production: (1)"],["Oil (MBbl per day)","76.5","","","62.9","","","59.9","","","13.6","","","3.0","","","22","%","","5","%"],["Gas (MMcf per day)","296.9","","","283.9","","","300.8","","","13.0","","","(17.0)","","","5","%","","(6)","%"],["NGLs (MBbl per day)","14.7","","","16.7","","","22.2","","","(2.0)","","","(5.6)","","","(12)","%","","(25)","%"],["Equivalent (MBOE per day)","140.7","","","126.9","","","132.3","","","13.9","","","(5.4)","","","11","%","","(4)","%"],["Oil, gas, and NGL production revenue (in millions): (1)"],["Oil production revenue","$","1,891.8","","","$","853.6","","","$","1,183.2","","","$","1,038.3","","","$","(329.6)","","","122","%","","(28)","%"],["Gas production revenue","525.5","","","187.5","","","262.5","","","338.0","","","(75.1)","","","180","%","","(29)","%"],["NGL production revenue","180.6","","","85.2","","","140.0","","","95.4","","","(54.8)","","","112","%","","(39)","%"],["Total oil, gas, and NGL production revenue","$","2,597.9","","","$","1,126.2","","","$","1,585.8","","","$","1,471.7","","","$","(459.6)","","","131","%","","(29)","%"],["Oil, gas, and NGL production expense (in millions): (1)"],["Lease operating expense","$","225.5","","","$","184.2","","","$","225.5","","","$","41.2","","","$","(41.3)","","","22","%","","(18)","%"],["Transportation costs","139.4","","","142.0","","","187.1","","","(2.6)","","","(45.1)","","","(2)","%","","(24)","%"],["Production taxes","121.1","","","46.1","","","65.0","","","75.0","","","(18.9)","","","163","%","","(29)","%"],["Ad valorem tax expense","19.4","","","18.9","","","23.1","","","0.5","","","(4.2)","","","3","%","","(18)","%"],["Total oil, gas, and NGL production expense","$","505.4","","","$","391.2","","","$","500.7","","","$","114.2","","","$","(109.5)","","","29","%","","(22)","%"],["Realized price:"],["Oil (per Bbl)","$","67.72","","","$","37.08","","","$","54.10","","","$","30.64","","","$","(17.02)","","","83","%","","(31)","%"],["Gas (per Mcf)","$","4.85","","","$","1.80","","","$","2.39","","","$","3.05","","","$","(0.59)","","","169","%","","(25)","%"],["NGLs (per Bbl)","$","33.67","","","$","13.96","","","$","17.26","","","$","19.71","","","$","(3.30)","","","141","%","","(19)","%"],["Per BOE","$","50.58","","","$","24.26","","","$","32.84","","","$","26.32","","","$","(8.58)","","","108","%","","(26)","%"],["Per BOE data: (1)"],["Oil, gas, and NGL production expense:"],["Lease operating expense","$","4.39","","","$","3.97","","","$","4.67","","","$","0.42","","","$","(0.70)","","","11","%","","(15)","%"],["Transportation costs","2.71","","","3.06","","","3.88","","","(0.35)","","","(0.82)","","","(11)","%","","(21)","%"],["Production taxes","2.36","","","0.99","","","1.35","","","1.37","","","(0.36)","","","138","%","","(27)","%"],["Ad valorem tax expense","0.38","","","0.41","","","0.48","","","(0.03)","","","(0.07)","","","(7)","%","","(15)","%"],["Total oil, gas, and NGL production expense","$","9.84","","","$","8.43","","","$","10.38","","","$","1.41","","","$","(1.95)","","","17","%","","(19)","%"],["Depletion, depreciation, amortization, and asset retirement obligation liability accretion","$","15.08","","","$","16.91","","","$","17.06","","","$","(1.83)","","","$","(0.15)","","","(11)","%","","(1)","%"],["General and administrative","$","2.18","","","$","2.14","","","$","2.75","","","$","0.04","","","$","(0.61)","","","2","%","","(22)","%"],["Derivative settlement gain (loss) (2)","$","(14.58)","","","$","7.57","","","$","0.81","","","$","(22.15)","","","$","6.76","","","(293)","%","","835","%"],["Earnings per share information (in thousands, except per share data): (3)"],["Basic weighted-average common shares outstanding","119,043","","","113,730","","","112,544","","","5,313","","","1,186","","","5","%","","1","%"],["Diluted weighted-average common shares outstanding","123,690","","","113,730","","","112,544","","","9,960","","","1,186","","","9","%","","1","%"],["Basic net income (loss) per common share","$","0.30","","","$","(6.72)","","","$","(1.66)","","","$","7.02","","","$","(5.06)","","","104","%","","(305)","%"],["Diluted net income (loss) per common share","$","0.29","","","$","(6.72)","","","$","(1.66)","","","$","7.01","","","$","(5.06)","","","104","%","","(305)","%"]]
[[/GREPCENT_TABLE]]

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(1)    Amounts and percentage changes may not calculate due to rounding.

(2)    Derivative settlements for the years ended December 31, 2021, 2020, and 2019, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).

(3)    Please refer to Note 9 - Earnings Per Share in Part II, Item 8 of this report for additional discussion.

Average net daily equivalent production for the year ended December 31, 2021, increased 11 percent compared with 2020, comprised of a 19 percent increase from our Midland Basin assets and a two percent decrease from our South Texas assets. The total increase resulted from an increased number of completions, strong well performance, and our continued focus on operational execution. In 2022, we expect total production volumes to remain relatively flat compared with 2021, and we expect oil volumes as a percentage of our total production mix to decrease due to increased capital allocation to our Austin Chalk assets and timing of Midland Basin completions. Please refer to Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 below for additional discussion.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price on a per BOE basis increased $26.32 for the year ended December 31, 2021, compared with 2020, primarily as a result of higher benchmark commodity prices which have improved from historic lows experienced during 2020 as a result of the impacts of the Pandemic and other macroeconomic events. Further contributing to the increase were improved gas prices during the first quarter of 2021 resulting from a supply and demand imbalance caused by a significant cold weather event in the state of Texas that lasted for several days in February 2021. The positive impact on oil, gas, and NGL production revenues resulting from the year-over-year realized price increase was substantially offset by a 293 percent change in the settlement of our derivative contracts which were a loss of $14.58 per BOE for the year ended December 31, 2021, compared to a gain of $7.57 per BOE for 2020.

LOE on a per BOE basis increased 11 percent for the year ended December 31, 2021, compared with 2020, driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and increased workover expense. For 2022, we expect LOE on a per BOE basis to slightly increase, compared with 2021, primarily as a result of anticipated increases in service provider costs and workover activity, which we expect to be partially offset by a shift in activity toward the Austin Chalk. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and industry activity, all of which impact total LOE.

Transportation costs on a per BOE basis decreased 11 percent for the year ended December 31, 2021, compared with 2020. This decrease was driven by transportation contract cost reductions during the second half of 2021, and a two percent decrease in net equivalent production from our South Texas assets, which incur the majority of our transportation costs. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets. For 2022, we expect transportation costs on a per BOE basis to increase compared with 2021.

Production tax expense on a per BOE basis for the year ended December 31, 2021, increased 138 percent compared with 2020, primarily driven by increases in realized prices and an increase in production from our Midland Basin assets. Our overall production tax rate was 4.7 percent and 4.1 percent for the years ended December 31, 2021, and 2020, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.

Ad valorem tax expense on a per BOE basis decreased seven percent for the year ended December 31, 2021, compared with 2020, primarily as a result of increased production and changes to the expected value assessments of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.

Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased 11 percent for the year ended December 31, 2021, compared with 2020, as a result of strong well performance, increased estimated proved reserves, lower well costs in our Midland Basin assets, and the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. We expect DD&A expense per BOE and DD&A expense on an absolute basis to decrease in 2022, compared with 2021, primarily as a result of increased estimated proved reserves, strong well performance, and increased activity in our Austin Chalk program, as these assets have a lower DD&A rate than our Midland Basin assets.

General and administrative (“G&A”) expense on a per BOE basis increased two percent for the year ended December 31, 2021, compared with 2020. This increase was primarily driven by increased compensation expense partially offset by increased production. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and therefore are subject to variability. For 2022, we expect G&A expense to slightly decrease on an absolute basis and to decrease on a per BOE basis, compared with 2021.

44

Please refer to Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019 for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between 2021 and 2020 and Between 2020 and 2019

Please refer to Comparison of Financial Results and Trends Between 2020 and 2019 and Between 2019 and 2018 in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2020 Annual Report on Form 10-K, filed with the SEC on February 18, 2021, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2020, compared with the year ended December 31, 2019.

Average net daily equivalent production, production revenue, and production expense

The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years ended December 31, 2021, and 2020:

[[GREPCENT_TABLE]]
[["","Net Equivalent Production Increase (Decrease)","","Production Revenue Increase","","Production Expense Increase"],["","(MBOE per day)","","(in millions)","","(in millions)"],["Midland Basin","14.9","","","$","1,148.8","","","$","95.0"],["South Texas","(1.0)","","","322.9","","","19.2"],["Total","13.9","","","$","1,471.7","","","$","114.2"]]
[[/GREPCENT_TABLE]]

____________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2021, increased 11 percent compared with 2020, comprised of a 19 percent increase from our Midland Basin assets, and a two percent decrease from our South Texas assets. Realized prices for oil, gas, and NGLs increased 83 percent, 169 percent, and 141 percent, respectively, for the year ended December 31, 2021, compared with 2020. As a result of increased production and improved pricing, production revenue for oil, gas, and NGLs increased 131 percent for the year ended December 31, 2021, compared with 2020. Total production expense for the year ended December 31, 2021, increased 29 percent, compared with 2020, primarily as a result of increased production taxes and LOE.

The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years ended December 31, 2020, and 2019:

[[GREPCENT_TABLE]]
[["","Net Equivalent Production Increase (Decrease)","","Production Revenue Decrease","","Production Expense Decrease"],["","(MBOE per day)","","(in millions)","","(in millions)"],["Midland Basin","7.5","","","$","(316.2)","","","$","(34.1)"],["South Texas","(12.9)","","","(143.4)","","","(75.4)"],["Total","(5.4)","","","$","(459.6)","","","$","(109.5)"]]
[[/GREPCENT_TABLE]]

____________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2020, decreased four percent compared with 2019. Realized prices for oil, gas, and NGLs decreased 31 percent, 25 percent, and 19 percent, respectively, for the year ended December 31, 2020, compared with 2019. As a result of decreased production and pricing, production revenue for oil, gas, and NGLs decreased 29 percent for the year ended December 31, 2020, compared with 2019. Total production expense for the year ended December 31, 2020, decreased 22 percent compared with 2019.

Please refer to Overview of Selected Production and Financial Information, Including Trends for additional discussion, including discussion of trends on a per BOE basis.

45

Depletion, depreciation, amortization, and asset retirement obligation liability accretion

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Depletion, depreciation, amortization, and asset retirement obligation liability accretion","$","774.4","","","$","785.0","","","$","823.8"]]
[[/GREPCENT_TABLE]]

DD&A expense for the year ended December 31, 2021, remained flat compared with 2020. DD&A expense for the year ended December 31, 2020, decreased five percent compared with 2019, primarily as a result of the reduction in the depletable cost basis of our South Texas proved oil and gas properties as a result of proved property impairments recognized during the first quarter of 2020, partially offset by higher production from our oil producing Midland Basin assets that have higher depletion rates than our primarily gas and NGL producing South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.

Exploration

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Geological and geophysical expenses","$","1.2","","","$","4.3","","","$","2.9"],["Exploratory dry hole","\u2014","","","\u2014","","","4.8"],["Overhead and other expenses","38.1","","","36.7","","","43.8"],["Total","$","39.3","","","$","41.0","","","$","51.5"]]
[[/GREPCENT_TABLE]]

Exploration expense decreased four percent for the year ended December 31, 2021, compared with 2020, primarily as a result of decreases in geological and geophysical expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and unsuccessful exploration activities, if any.

Impairment

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Impairment of proved oil and gas properties and related support equipment","$","\u2014","","","$","956.7","","","$","\u2014"],["Abandonment and impairment of unproved properties","35.0","","","59.3","","","33.8"],["Total","$","35.0","","","$","1,016.0","","","$","33.8"]]
[[/GREPCENT_TABLE]]

During the year ended December 31, 2020, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities as a result of the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. There were no proved oil and gas impairments recorded during 2021 or 2019.

Unproved property abandonments and impairments recorded during the years ended December 31, 2021, 2020, and 2019, related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks.

We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.

Reserve estimates and related impairments of proved and unproved properties are difficult to predict in a volatile price environment. If commodity prices for the products we produce decline as a result of supply and demand fundamentals associated with the Pandemic or other macroeconomic events, we may experience additional proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as

46

of February 10, 2022, we do not expect any material oil and gas property impairments in the first quarter of 2022 resulting from commodity price impacts.

Please refer to Critical Accounting Policies and Estimates below and Note 8 – Fair Value Measurements in Part II, Item 8 of this report for additional discussion.

General and administrative

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["General and administrative","$","111.9","","","$","99.2","","","$","132.8"]]
[[/GREPCENT_TABLE]]

G&A expense increased 13 percent for the year ended December 31, 2021, compared with 2020, primarily as a result of increased compensation expense incurred during the year. G&A expense decreased 25 percent for the year ended December 31, 2020, compared with 2019, primarily due to reduced overhead costs resulting from the reorganization of certain functions in the fourth quarter of 2019 that eliminated duplicative regional operational functions, as well as actions taken to reduce costs as a result of the Pandemic. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense.

Net derivative (gain) loss

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Net derivative (gain) loss","$","901.7","","","$","(161.6)","","","$","97.5"]]
[[/GREPCENT_TABLE]]

Net derivative (gain) loss is a result of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. The net derivative loss for the year ended December 31, 2021, resulted from increases in benchmark commodity prices during 2021. The net derivative gain for the year ended December 31, 2020, resulted from decreases in benchmark commodity prices during 2020. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

Other operating expense, net

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Other operating expense, net","$","46.1","","","$","24.8","","","$","19.9"]]
[[/GREPCENT_TABLE]]

Other operating expense, net, increased for the year ended December 31, 2021, compared with 2020, as a result of legal settlements recorded during 2021, including the settlement of the SPM NAM LLC et al. case disclosed in Legal Proceedings in Part I, Item 3 of this report.

Interest expense

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Interest expense","$","(160.4)","","","$","(163.9)","","","$","(159.1)"]]
[[/GREPCENT_TABLE]]

Interest expense decreased two percent for the year ended December 31, 2021, compared with 2020. In 2022, we expect interest expense related to our Senior Notes to decrease compared with 2021 as result of the reduction in the aggregate principal amount of Senior Secured Notes and Senior Unsecured Notes through various transactions in 2021 and 2022. Total interest expense is impacted by, and can vary based on, the timing and amount of borrowings under our revolving credit facility. Please refer to Overview of Liquidity and Capital Resources below, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion, including the definitions of Senior Notes, Senior Secured Notes, Senior Unsecured Notes, and 2028 Senior Notes.

47

Net gain (loss) on extinguishment of debt

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions)"],["Net gain (loss) on extinguishment of debt","$","(2.1)","","","$","280.1","","","$","\u2014"]]
[[/GREPCENT_TABLE]]

The Exchange Offers executed during the second quarter of 2020 resulted in a net gain on extinguishment of debt of $227.3 million, which was primarily comprised of the gain on the partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes. Additionally, during the year ended December 31, 2020, we repurchased certain of our 2022 Senior Notes and 2024 Senior Notes in open market transactions, resulting in a net gain on extinguishment of debt of $52.8 million. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion, including the definitions of Exchange Offers, Old Notes, 2025 Senior Secured Notes, 2022 Senior Notes, and 2024 Senior Notes.

Income tax (expense) benefit

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in millions, except tax rate)"],["Income tax (expense) benefit","$","(9.9)","","","$","192.1","","","$","44.0"],["Effective tax rate","21.5","%","","20.1","%","","19.1","%"]]
[[/GREPCENT_TABLE]]

The increase in the effective tax rate for the year ended December 31, 2021, compared with 2020, was primarily due to the differing effects of permanent items on income before income taxes for the year ended December 31, 2021, compared to a loss before income taxes in 2020. During 2021, an additional valuation allowance recorded against tax effected net derivative liabilities partially offset by an excess tax benefit from stock-based compensation awards and other deferred tax adjustments, resulted in an increase in the tax rate year-over-year. The additional valuation allowance recorded against tax effected net derivative liabilities could reverse and decrease our effective tax rate in 2022, if commodity prices remain at or exceed their current levels and we generate cumulative net income. The United States Congress continues to work on separate provisions of the Build Back Better Act, however, as of the filing of this report, no legislation impacting the Internal Revenue Code (“IRC”) has been passed. Changes to the IRC could eliminate or reduce certain oil and gas industry deductions and could increase the overall corporate income tax rate.

The increase in the effective tax rate for the year ended December 31, 2020, compared with 2019, was primarily due to the differing effects of permanent items on the loss before income taxes for each of the years ended December 31, 2020, and 2019. For the year ended December 31, 2020, the tax benefit rate increased compared with the same period in 2019 as a result of state permanent items reflecting state planning strategies. This increase was partially offset by the impact of the valuation allowance recorded on our deferred tax assets combined with the effects of excess tax deficiencies from stock-based compensation awards, limits on expensing of certain covered individuals’ compensation, and other permanent expense items.

Please refer to Overview of Liquidity and Capital Resources and Critical Accounting Policies and Estimates below as well as Note 4 – Income Taxes in Part II, Item 8 of this report for further discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our current financial obligations. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Sources of Cash

We expect our 2022 capital program to be funded by cash flows from operations. Although we expect cash flows from operations to be sufficient to fund our expected 2022 capital program, we may also use borrowings under our revolving credit facility or raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which affect us and our industry.

48

Our credit ratings impact the availability of and cost for us to borrow additional funds. During the first half of 2021, three major credit rating agencies upgraded our credit ratings, citing our improved debt leverage and our expected ability to generate meaningful free cash flows, among other reasons. Additionally, one of these major credit rating agencies further upgraded our credit rating in conjunction with the issuance of our 2028 Senior Notes. Subsequent to December 31, 2021, and in consideration of the redemption of our 2024 Senior Notes on February 14, 2022, one major credit rating agency upgraded our credit rating, citing our priorities of continuing to reduce debt and improve our leverage metrics, and our expected ability to generate meaningful cash flows, among other reasons. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for the definition of 2024 Senior Notes and 2028 Senior Notes.

We have no control over the market prices for oil, gas, and NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information about our oil, gas, and NGL derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, and a borrowing base and aggregate lender commitments of $1.1 billion. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. During the fourth quarter of 2021, the fall semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at $1.1 billion. The next borrowing base redetermination date is scheduled for April 1, 2022. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under our Credit Agreement as of February 10, 2022, December 31, 2021, and December 31, 2020.

We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of December 31, 2021, and through the filing of this report. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.

As of December 31, 2021, we had no outstanding balance on our revolving credit facility. Our daily weighted-average revolving credit facility debt balance was $106.0 million and $145.6 million for the years ended December 31, 2021, and 2020, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, repayment of scheduled debt maturities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.

Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR which was discontinued as a global reference rate for new loans and contracts after December 31, 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. During 2022, in advance of the maturity date of our existing Credit Agreement, we expect to enter into a new credit agreement that will, in addition to other negotiated terms, conditions, agreements, and other provisions, specify a new interest rate for Eurodollar loans. We currently do not expect to incur borrowings in the form of Eurodollar loans prior to that time, and we currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. Please refer to Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for discussion of FASB ASU 2020-04 and ASU 2021-01, which provide guidance related to reference rate reform.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and for the periods during which they were outstanding, the non-cash amortization of the discounts related to the 2021 Senior Secured Convertible Notes and 2025 Senior Secured Notes, each as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report. Our weighted-average borrowing rate includes paid and accrued interest only.

49

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2021, 2020, and 2019:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["Weighted-average interest rate","7.7","%","","7.0","%","","6.4","%"],["Weighted-average borrowing rate","6.8","%","","6.1","%","","5.7","%"]]
[[/GREPCENT_TABLE]]

Our weighted-average interest rates and our weighted-average borrowing rates increased for the year ended December 31, 2021, compared with 2020, and for the year ended December 31, 2020, compared with 2019. These increases were primarily a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second quarter of 2020.

Our weighted-average interest rate and weighted-average borrowing rate are impacted by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021. After this date, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs or the non-cash amortization of the discount related to the 2021 Senior Secured Convertible Notes. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During 2021, we spent approximately $678.2 million on capital expenditures and on acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $718.0 million for the year ended December 31, 2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Please refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.

Changes to the IRC could increase the corporate income tax rate and could eliminate or reduce current tax deductions for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. Future legislation regarding these issues could reduce our net cash provided by operating activities over time, and could therefore result in a reduction of funding available for the items discussed above.

We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. During 2021, we issued our 2028 Senior Notes and with the proceeds, repurchased certain of our 2022 Senior Notes and 2024 Senior Notes through the Tender Offer. Subsequently, we redeemed the remaining 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. The 2021 Senior Secured Convertible Notes matured on July 1, 2021, and on that day, we used borrowings under our revolving credit facility to retire, at par, the outstanding principal amount. During 2020, we completed the Exchange Offers and we repurchased certain of our 2022 Senior Notes and 2024 Senior Notes in open market transactions. As part of our strategy for 2022, we continue to focus on reducing absolute debt and improving our debt metrics and on February 14, 2022, we redeemed the remaining $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.

As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, compliance with securities laws, and the terms and provisions of

50

our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During 2021, we did not repurchase any shares of our common stock.

During the years ended December 31, 2021, 2020, and 2019, we paid $2.4 million, $2.3 million, and $11.3 million, respectively, in dividends to our stockholders. These amounts reflect a bi-annual dividend of $0.01 per share for each of the years ended December 31, 2021, and 2020, and a bi-annual dividend of $0.05 per share for the year ended December 31, 2019. Our current intention is to continue to make dividend payments for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, other covenants, and other factors that could arise. The payment and amount of future dividends remains at the discretion of our Board of Directors.

Analysis of Cash Flow Changes Between 2021 and 2020 and Between 2020 and 2019

The following tables present changes in cash flows between the years ended December 31, 2021, 2020, and 2019, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows (“accompanying statements of cash flows”) in Part II, Item 8 of this report.

Operating Activities

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,","","Amount Change Between"],["","2021","","2020","","2019","","2021/2020","","2020/2019"],["","(in millions)"],["Net cash provided by operating activities","$","1,159.8","","","$","790.9","","","$","823.6","","","$","368.9","","","$","(32.7)"]]
[[/GREPCENT_TABLE]]

Net cash provided by operating activities increased for the year ended December 31, 2021, compared with 2020, primarily as a result of a $1.3 billion increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, partially offset by an increase of $1.0 billion in cash paid on settled derivative trades.

Net cash provided by operating activities decreased for the year ended December 31, 2020, compared with 2019, primarily as a result of a $316.9 million decrease in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, offset by an increase in cash received from settled derivative trades of $290.7 million.

Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.

Investing Activities

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,","","Amount Change Between"],["","2021","","2020","","2019","","2021/2020","","2020/2019"],["","(in millions)"],["Net cash used in investing activities","$","(667.2)","","","$","(555.6)","","","$","(1,013.3)","","","$","(111.6)","","","$","457.7"]]
[[/GREPCENT_TABLE]]

Net cash used in investing activities increased for the year ended December 31, 2021, compared with 2020, primarily as a result of increased capital expenditures of $127.1 million. Net cash used in investing activities during the year ended December 31, 2021, was funded by net cash provided by operating activities.

Net cash used in investing activities decreased for the year ended December 31, 2020, compared with 2019, primarily as a result of reduced capital expenditures of $476.0 million. Net cash used in investing activities during the year ended December 31, 2020, was funded by net cash provided by operating activities.

Financing Activities

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,","","Amount Change Between"],["","2021","","2020","","2019","","2021/2020","","2020/2019"],["","(in millions)"],["Net cash provided by (used in) financing activities","$","(159.8)","","","$","(235.4)","","","$","111.8","","","$","75.6","","","$","(347.2)"]]
[[/GREPCENT_TABLE]]

During the year ended December 31, 2021, we paid $385.3 million, including net premiums, to fund the Tender Offer and the 2022 Senior Notes Redemption, and we received net cash proceeds of $392.8 million from the issuance of our 2028 Senior Notes.

51

Additionally, we paid $65.5 million to retire our 2021 Senior Secured Convertible Notes and had net repayments under our revolving credit facility of $93.0 million.

During the year ended December 31, 2020, we paid $136.5 million to repurchase certain of our 2022 Senior Notes and 2024 Senior Notes in open market transactions, we paid $53.5 million to certain holders of the 2021 Senior Secured Convertible Notes in connection with the Private Exchange, and we had net repayments under our revolving credit facility of $29.5 million.

During the year ended December 31, 2019, we had net borrowings under our revolving credit facility of $122.5 million.

Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.

Interest Rate Risk

We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of December 31, 2021, we had no outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes but can impact their fair values. As of December 31, 2021, our outstanding principal amount of fixed-rate debt totaled $2.1 billion and we had no floating-rate debt outstanding. Please refer to Note 8 – Fair Value Measurements in Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the Pandemic, however, future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, could have further negative impacts on prices. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the escalating tensions between Russia and Ukraine. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2021 production, a 10 percent decrease in our average realized prices for oil, gas, and NGLs, would have reduced our oil, gas, and NGL production revenues by approximately $189.2 million, $52.5 million, and $18.1 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $189.2 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2021, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $94.3 million, $17.1 million, and $5.6 million, respectively.

Off-Balance Sheet Arrangements

We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE” or “SPEs”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during 2021 or 2020, or through the filing of this report.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business

52

conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.

Successful Efforts Method of Accounting. GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report.

Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations. Please refer to Oil and Gas Producing Activities in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.

Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2021, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period ended December 31, 2021. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Please refer to Risk Factors in Part I, Item 1A of this report.

If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.

The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","MMBOE Change","","MMBOE Change","","MMBOE Change"],["Revisions resulting from performance","3.4","","","3.6","","","(14.9)"],["Removal of proved undeveloped reserves no longer in our five-year development plan","(40.6)","","","(65.0)","","","(9.8)"],["Revisions resulting from price changes","37.2","","","(32.6)","","","(70.0)"],["Total","\u2014","","","(94.0)","","","(94.7)"]]
[[/GREPCENT_TABLE]]

____________________________________________

Note: Amounts may not calculate due to rounding.

As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.

53

We cannot reasonably predict future commodity prices, although we believe that together, the below analyses provide reasonable information regarding the impact of changes in pricing and trends on total estimated proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated proved reserve volumes from the described hypothetical changes:

[[GREPCENT_TABLE]]
[["","For the year ended December 31, 2021"],["","MMBOE Change","","Percentage Change"],["10 percent decrease in SEC pricing (1)","(3.7)","","","(1)","%"],["Average NYMEX strip pricing as of fiscal year end (2)","(3.6)","","","(1)","%"],["10 percent decrease in proved undeveloped reserves (3)","(19.2)","","","(4)","%"]]
[[/GREPCENT_TABLE]]

____________________________________________

(1)    The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31, 2021, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2)    The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2021, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As of December 31, 2021, SEC pricing was $66.56 per Bbl for oil, $3.60 per MMBtu for gas, and $36.60 per Bbl for NGLs, and five-year average NYMEX strip pricing was $64.34 per Bbl for oil, $3.26 per MMBtu for gas, and $30.19 per Bbl for NGLs.

(3)    The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2021, and does not include any additional impacts to our estimated proved reserves.

Additional reserve information can be found in Reserves in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Impairment of Oil and Gas Properties. Proved oil and gas properties are evaluated for impairment on a pool-by-pool basis and reduced to fair value when events or changes in circumstances indicate that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows.

Unproved oil and gas properties are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties using a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants.

We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of February 10, 2022, we do not expect any material oil and gas property impairments in the first quarter of 2022 resulting from commodity price impacts.

Please refer to Note 1 – Summary of Significant Accounting Policies and Note 8 – Fair Value Measurements in Part II, Item 8 of this report for discussion of impairments of oil and gas properties recorded for the years ended December 31, 2021, 2020, and 2019.

Revenue Recognition. We predominately derive our revenue from the sale of produced oil, gas, and NGLs. Our revenue recognition policy is a critical accounting policy because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. A 10 percent change in our revenue accrual at year-end 2021 would have impacted total operating revenues by approximately $21.6 million for the year ended December 31, 2021. Please refer to Note 1 – Summary of Significant Accounting Policies and Note 2 - Revenue from Contracts with Customers in Part II, Item 8 of this report for additional discussion.

Derivative Financial Instruments. We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to oil, gas, and NGL price volatility and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income

54

(loss). The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Please refer to Note 1 – Summary of Significant Accounting Policies and Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

Income Taxes. We account for deferred income taxes, whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using currently enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are 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. We record deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. 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 as well as significant enacted tax rate changes could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax benefit by approximately $0.5 million for the year ended December 31, 2021. Please refer to Note 1 – Summary of Significant Accounting Policies and Note 4 – Income Taxes in Part II, Item 8 of this report for additional discussion.

Accounting Matters

Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for information on new authoritative accounting guidance.

Environmental

We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, please refer to Risk Factors – Risks Related to Oil and Gas Operations and the Industry – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Climate Change and Air Quality. In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds (“VOCs” or “VOC”) and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. On September 14, and 15, 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. In November 2021, the EPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources.

States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion (“ppb”) in 2015. The EPA maintained the standard in 2020, but in 2021 the EPA communicated that it is reconsidering the 2020 decision. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance.

55

On November 16, 2016, the BLM finalized regulations to address methane emissions from oil and gas operations on federal and tribal lands, as part of President Obama’s Climate Action Plan. The regulations were intended to reduce the waste of gas from flaring, venting, and leaks by oil and gas production. The rule included requirements that prohibits venting of gas except in limited circumstances and limits flaring of gas and includes requirements for leak detection and repair. The rule also increased royalty payments for “waste” gas that is released in contravention of the rule requirements. After continuous court challenges, the BLM issued a final rule in September 2018 that rescinded most of the 2016 rule, including most of the methane control requirements. After the 2018 rescission was vacated by the District Court for the Northern District of California, the 2016 rule was vacated by the District Court for the District of Wyoming. Any future regulations requiring similar capture standards may increase our operational costs, or restrict our production, which could materially and adversely affect our financial condition, results of operations, and cash flows.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, there have been international conventions and efforts to establish standards for the reduction of GHGs globally, including the Paris accords in December 2015. The conditions for entry into force of the Paris accords were met on October 5, 2016 and the Agreement went into force 30 days later on November 4, 2016. At the United Nations Climate Change Conference in Glasgow in 2021, the United States and the European Union announced the Global Methane Pledge that aims to reduce methane emissions by 30 percent compared with 2020 levels.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations.

In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. Approximately 35 percent and 37 percent of our production on a BOE basis in 2021 and 2020, respectively, was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement based on adjusted EBITDAX ratios as further described in Note 5 – Long-Term Debt in Part II, Item 8 of this report. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of

56

that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, would be entitled to exercise all of their remedies for default.

The following table provides reconciliations of our net income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

[[GREPCENT_TABLE]]
[["","For the Years Ended December 31,"],["","2021","","2020","","2019"],["","(in thousands)"],["Net income (loss) (GAAP)","$","36,229","","","$","(764,614)","","","$","(187,001)"],["Interest expense","160,353","","","163,892","","","159,102"],["Income tax expense (benefit)","9,938","","","(192,091)","","","(44,043)"],["Depletion, depreciation, amortization, and asset retirement obligation liability accretion","774,386","","","784,987","","","823,798"],["Exploration (1)","35,346","","","37,541","","","46,995"],["Impairment","35,000","","","1,016,013","","","33,842"],["Stock-based compensation expense","18,819","","","14,999","","","24,318"],["Net derivative (gain) loss","901,659","","","(161,576)","","","97,539"],["Derivative settlement gain (loss)","(748,958)","","","351,261","","","39,222"],["Net (gain) loss on extinguishment of debt","2,139","","","(280,081)","","","\u2014"],["Other, net","507","","","5,074","","","(381)"],["Adjusted EBITDAX (non-GAAP)","1,225,418","","","975,405","","","993,391"],["Interest expense","(160,353)","","","(163,892)","","","(159,102)"],["Income tax (expense) benefit","(9,938)","","","192,091","","","44,043"],["Exploration (1)","(35,346)","","","(37,541)","","","(46,995)"],["Amortization of debt discount and deferred financing costs","17,275","","","17,704","","","15,474"],["Deferred income taxes","9,565","","","(192,540)","","","(41,835)"],["Other, net","(4,260)","","","(11,874)","","","1,739"],["Net change in working capital","117,411","","","11,591","","","16,852"],["Net cash provided by operating activities (GAAP)","$","1,159,772","","","$","790,944","","","$","823,567"]]
[[/GREPCENT_TABLE]]

____________________________________________

(1)    Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.