SM Energy Co 10-Q

ITEM 2. 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. Additionally, the following discussion includes sequential quarterly comparison to financial information presented in our Quarterly Report on Form 10-Q for the qu arter ended March 31, 2021 , filed with the SEC on April 30, 2021. Throughout the following discussion, we explain changes between the three months ended June 30, 2021, compared with the three months ended March 31, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the six months ended June 30, 2021, compared with the same period in 2020 (“YTD 2021-over-YTD 2020”). 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 vision is to be a premier operator of top tier assets and to sustainably grow value for all of our stakeholders. This includes short-term operational and financial goals of 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 goal is to deliver cash flow growth that is supported by our high-quality asset base and ability to generate favorable returns. 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 on 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 environmental, social and governance policies, programs and initiatives, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations, compensation for our executives and eligible employees under our long-term incentive plans, and compensation for all employees under our short-term incentive plans is calculated based on certain Company-wide performance-based metrics that include key financial, operational, and environmental, health, and safety measures. Areas of Operations Our Midland Basin assets are comprised of approximately 81,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the second quarter of 2021, drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continued to focus primarily on delineating, developing, and expanding our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations. Our South Texas assets are comprised of approximately 155,000 net acres located in the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on production from both the Eagle Ford shale formation and Austin Chalk formation and further delineation and development of the Austin Chalk formation. Our overlapping acreage position in the Eagle Ford shale and Austin Chalk formations includes acreage in oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. 2021 capital activity in South Texas has been, and will continue to be, concentrated on the Austin Chalk formation given the favorable economics we achieve from a higher oil and NGL product mix. Second Quarter 2021 Overview and Outlook for the Remainder of 2021 During the second quarter of 2021, we issued $400.0 million in aggregate principal amount of our 2028 Senior Notes and we used the net proceeds to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes outstanding through the 2022 Senior Notes Redemption. We paid total consideration, excluding accrued interest, of $385.3 million, and recorded a loss on extinguishment of debt of $2.1 million for the three months ended June 30, 2021, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. The Pandemic remains a global health crisis, and while the United States has seen substantial improvements in public health and macroeconomic measures in recent months, and has deployed vaccinations to prevent the spread of the COVID-19 virus, stability in the markets and demand for the commodities produced by our industry have not returned to pre-Pandemic levels, and may not for some time. The impacts of the Pandemic continue to be unpredictable and dynamic, so we are unable to reasonably estimate the period of time that related market conditions could exist or the extent to which they could continue to impact our business, results of operations, financial condition, or the timing of further recovery. Commodity prices have improved from historic lows in 2020, however, 23 future case surges or outbreaks, and COVID-19 virus variants, could have further negative impacts, and as a result, may require us to adjust our business plan. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K . Despite continuing impacts of the Pandemic 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. The safety of our employees, contractors, and the communities where we work remains our first priority as we continue to operate during the Pandemic. While our core business operations require certain individuals to be physically present at well site locations, the vast majority of our office-based employees have continued working remotely in order to limit physical interactions and to mitigate the spread of COVID-19. For individuals who are unable to perform their jobs remotely, we maintain and continually assess procedures designed to limit the spread of COVID-19, including social distancing and enhanced sanitization measures, 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 federal Occupational Safety and Health Act guidelines related to the prevention of the transmission of COVID-19. Since these measures were initially implemented in the first quarter of 2020, we have continued to operate without significant disruptions to our business operations. Our pre-existing control environment and internal controls have continued to be effective and we have continued to address new risks directly related to the Pandemic as we identify them. Our 2021 total capital program budget is between $650.0 million and $675.0 million. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2021 capital program remains focused on highly economic oil development projects in both our Midland Basin assets and South Texas assets. Based on the current macroeconomic environment, 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 improving leverage metrics and maintaining strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our 2021 capital program. Financial and Operational Results. Average net daily equivalent production for the three months ended June 30, 2021, was 136.5 MBOE and increased 22 percent sequentially as the first quarter of 2021 was impacted by a significant weather event in the state of Texas that lasted for several days in February 2021, which included abnormally low temperatures and freezing conditions, and resulted in widespread power outages (“Texas Weather Event”). Strengthening benchmark commodity prices in the second quarter of 2021 resulted in increases in realized prices, as defined below, for oil and NGLs of 16 percent and five percent, respectively, for the three months ended June 30, 2021, compared with the three months ended March 31, 2021. The supply and demand imbalance caused by the Texas Weather Event inflated realized prices for gas in the first quarter of 2021, which resulted in a 20 percent decrease in realized prices for the three months ended June 30, 2021, compared with the three months ended March 31, 2021. Total realized price per BOE increased eight percent for the three months ended June 30, 2021, compared with the three months ended March 31, 2021. This increase resulted in oil, gas, and NGL production revenue of $562.6 million for the three months ended June 30, 2021, compared with $423.2 million for the three months ended March 31, 2021, which was an increase of 33 percent. Production costs per BOE of $10.10 for the three months ended June 30, 2021, were flat compared with the three months ended March 31, 2021. We recorded net derivative losses of $370.3 million and $344.7 million for the three months ended June 30, 2021, and March 31, 2021, respectively. Included within these amounts are realized derivative settlement losses of $158.8 million and $107.9 million for the three months ended June 30, 2021, and March 31, 2021, respectively, resulting from increased commodity prices. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion. Financial and operational activities during the three months ended June 30, 2021, resulted in the following: • Net cash provided by operating activities of $296.4 million for the three months ended June 30, 2021, compared with $105.6 million for the three months ended March 31, 2021. The sequential quarterly increase was primarily a result of changes in working capital. • A net loss of $223.0 million, or $1.88 per diluted share, for the three months ended June 30, 2021, compared with a net loss of $251.3 million, or $2.19 per diluted share, for the three months ended March 31, 2021. The net loss for the three months ended June 30, 2021, was primarily due to a $370.3 million net derivative loss. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion regarding the components of net loss for the periods presented. • Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended June 30, 2021, was $256.9 million, compared with $215.0 million for the three months ended March 31, 2021. Please refer to the caption Non-GAAP 24 Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net loss and net cash provided by operating activities. Operational Activities. In our Midland Basin program, we operated three drilling rigs and averaged three completion crews during the second quarter of 2021. We drilled 14 gross (11 net) wells and completed 44 gross (40 net) wells during the second quarter of 2021, and production volumes increased sequentially by 22 percent to 8.3 MMBOE compared with the three months ended March 31, 2021. Costs incurred in our Midland Basin program during the three months ended June 30, 2021, totaled $155.9 million, or 69 percent of our total costs incurred for the period. We anticipate operating between two and three drilling rigs and between one and two completion crews at times during the remainder of 2021, focused primarily on delineating and developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin. In our South Texas program, we operated two drilling rigs and one completion crew at times during the second quarter of 2021. We drilled 11 gross (11 net) wells and completed five gross (five net) wells during the second quarter of 2021, and production volumes increased sequentially by 28 percent to 4.1 MMBOE compared with the three months ended March 31, 2021. Costs incurred in our South Texas program during the three months ended June 30, 2021, totaled $59.5 million, or 26 percent of our total costs incurred for the period. We anticipate operating between one and two drilling rigs and one completion crew during the remainder of 2021, focused primarily on delineating and developing the Austin Chalk formation. The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three and six months ended June 30, 2021: Midland Basin South Texas (2) Total Gross Net Gross Net Gross Net Wells drilled but not completed at December 31, 2020 66 58 31 28 97 86 Wells drilled 16 13 5 5 21 18 Wells completed (16) (14) (6) (3) (22) (17) Other (1) — 1 — — — 1 Wells drilled but not completed at March 31, 2021 66 58 30 30 96 88 Wells drilled 14 11 11 11 25 22 Wells completed (44) (40) (5) (5) (49) (45) Wells drilled but not completed at June 30, 2021 36 29 36 36 72 65 ____________________________________________ (1) 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, farmouts, and other activities. (2) The South Texas drilled but not completed well count as of each period end presented above includes 13 gross (13 net) wells that are not included in our five-year development plan, 12 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, totaled $224.6 million and $417.2 million for the three and six months ended June 30, 2021, respectively, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above. 25 Production Results. The table below presents our production by product type for each of our areas of operation for the sequential quarterly periods and the YTD 2021-over-YTD 2020 periods: For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 Midland Basin Production: Oil (MMBbl) 6.2 5.1 11.3 10.9 Gas (Bcf) 12.8 10.6 23.4 21.7 NGLs (MMBbl) — — — — Equivalent (MMBOE) 8.3 6.9 15.2 14.6 Average net daily equivalent (MBOE per day) 91.6 76.1 83.9 80.0 Relative percentage 67 % 68 % 68 % 62 % South Texas Production: Oil (MMBbl) 0.5 0.3 0.8 0.8 Gas (Bcf) 13.6 11.0 24.6 30.8 NGLs (MMBbl) 1.3 1.0 2.4 3.1 Equivalent (MMBOE) 4.1 3.2 7.3 9.0 Average net daily equivalent (MBOE per day) 44.9 35.5 40.2 49.4 Relative percentage 33 % 32 % 32 % 38 % Total Production: Oil (MMBbl) 6.7 5.4 12.1 11.7 Gas (Bcf) 26.5 21.5 48.0 52.5 NGLs (MMBbl) 1.3 1.0 2.4 3.1 Equivalent (MMBOE) 12.4 10.0 22.5 23.6 Average net daily equivalent (MBOE per day) 136.5 111.6 124.2 129.4 ____________________________________________ Note: Amounts may not calculate due to rounding. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for discussion on production. 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 effects of derivative settlements, unless otherwise indicated. 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. 26 The following table summarizes commodity price data, as well as the effects of derivative settlements, for the three months ended June 30, 2021, March 31, 2021, and June 30, 2020: For the Three Months Ended June 30, 2021 March 31, 2021 June 30, 2020 Oil (per Bbl): Average NYMEX contract monthly price $ 66.07 $ 57.84 $ 27.85 Realized price, before the effect of derivative settlements $ 65.34 $ 56.33 $ 22.25 Effect of oil derivative settlements $ (20.11) $ (10.38) $ 25.81 Gas: Average NYMEX monthly settle price (per MMBtu) $ 2.83 $ 2.69 $ 1.72 Realized price, before the effect of derivative settlements (per Mcf) $ 3.34 $ 4.16 $ 1.34 Effect of gas derivative settlements (per Mcf) $ (0.46) $ (1.88) $ 0.04 NGLs (per Bbl): Average OPIS price (1) $ 31.52 $ 30.47 $ 14.02 Realized price, before the effect of derivative settlements $ 28.41 $ 26.93 $ 10.43 Effect of NGL derivative settlements $ (9.22) $ (10.79) $ 1.94 ____________________________________________ (1) Average OPIS price 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. Given the dynamic nature of the Pandemic, we expect future benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing of any further recovery or future infection rate surges or outbreaks. 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. Please refer to Second Quarter 2021 Overview and Outlook for the Remainder of 2021 above for additional discussion of factors impacting pricing. The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of July 21, 2021, and June 30, 2021: As of July 21, 2021 As of June 30, 2021 NYMEX WTI oil (per Bbl) $ 67.29 $ 69.99 NYMEX Henry Hub gas (per MMBtu) $ 3.69 $ 3.48 OPIS NGLs (per Bbl) $ 34.64 $ 35.61 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 of our 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 our ability to enter into favorable commodity derivative contracts. 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 us to participate in some of the upward movements in oil and gas prices while also setting a price floor for a portion of our oil and gas production. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 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. 27 Financial Results of Operations and Additional Comparative Data The tables below provide information regarding selected production and financial information for the three months ended June 30, 2021, and the preceding three quarters. For the Three Months Ended June 30, March 31, December 31, September 30, 2021 2021 2020 2020 (in millions) Production (MMBOE) 12.4 10.0 11.3 11.6 Oil, gas, and NGL production revenue $ 562.6 $ 423.2 $ 320.2 $ 282.0 Oil, gas, and NGL production expense $ 125.5 $ 100.9 $ 96.0 $ 95.3 Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 204.7 $ 167.0 $ 188.9 $ 181.7 Exploration $ 8.7 $ 9.3 $ 11.3 $ 8.5 General and administrative $ 24.6 $ 24.7 $ 20.0 $ 24.5 Net loss $ (223.0) $ (251.3) $ (165.2) $ (98.3) ____________________________________________ Note: Amounts may not calculate due to rounding. Selected Performance Metrics For the Three Months Ended June 30, March 31, December 31, September 30, 2021 2021 2020 2020 Average net daily equivalent production (MBOE per day) 136.5 111.6 122.4 126.3 Lease operating expense (per BOE) $ 4.62 $ 4.64 $ 4.10 $ 3.65 Transportation costs (per BOE) $ 3.01 $ 2.94 $ 2.89 $ 3.11 Production taxes as a percent of oil, gas, and NGL production revenue 4.5 % 4.6 % 4.0 % 4.3 % Ad valorem tax expense (per BOE) $ 0.45 $ 0.52 $ 0.38 $ 0.40 Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) $ 16.48 $ 16.62 $ 16.77 $ 15.64 General and administrative (per BOE) $ 1.98 $ 2.46 $ 1.78 $ 2.10 ____________________________________________ Note: Amounts may not calculate due to rounding. 28 Overview of Selected Production and Financial Information, Including Trends For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Six Months Ended Amount Change Between Periods Percent Change Between Periods June 30, March 31, June 30, June 30, 2021 2021 2021 2020 Net production volumes: (1) Oil (MMBbl) 6.7 5.4 1.2 23 % 12.1 11.7 0.4 3 % Gas (Bcf) 26.5 21.5 4.9 23 % 48.0 52.5 (4.5) (9) % NGLs (MMBbl) 1.3 1.0 0.3 29 % 2.4 3.1 (0.7) (23) % Equivalent (MMBOE) 12.4 10.0 2.4 24 % 22.5 23.6 (1.1) (5) % Average net daily production: (1) Oil (MBbl per day) 73.4 60.3 13.1 22 % 66.9 64.4 2.5 4 % Gas (MMcf per day) 290.9 239.4 51.6 22 % 265.3 288.5 (23.2) (8) % NGLs (MBbl per day) 14.6 11.4 3.2 28 % 13.1 16.9 (3.9) (23) % Equivalent (MBOE per day) 136.5 111.6 24.9 22 % 124.2 129.4 (5.2) (4) % Oil, gas, and NGL production revenue (in millions): (1) Oil production revenue $ 436.4 $ 305.8 $ 130.6 43 % $ 742.1 $ 411.2 $ 330.9 80 % Gas production revenue 88.3 89.7 (1.3) (1) % 178.0 75.6 102.4 136 % NGL production revenue 37.9 27.7 10.1 37 % 65.6 37.2 28.4 76 % Total oil, gas, and NGL production revenue $ 562.6 $ 423.2 $ 139.4 33 % $ 985.7 $ 524.0 $ 461.7 88 % Oil, gas, and NGL production expense (in millions): (1) Lease operating expense $ 57.4 $ 46.7 $ 10.7 23 % $ 104.0 $ 95.7 $ 8.3 9 % Transportation costs 37.4 29.6 7.8 26 % 66.9 73.3 (6.4) (9) % Production taxes 25.2 19.5 5.7 29 % 44.7 21.1 23.5 111 % Ad valorem tax expense 5.6 5.2 0.3 7 % 10.8 9.9 0.9 9 % Total oil, gas, and NGL production expense $ 125.5 $ 100.9 $ 24.5 24 % $ 226.4 $ 200.0 $ 26.4 13 % Realized price, before the effect of derivative settlements (“realized price”): Oil (per Bbl) $ 65.34 $ 56.33 $ 9.01 16 % $ 61.30 $ 35.09 $ 26.21 75 % Gas (per Mcf) $ 3.34 $ 4.16 $ (0.82) (20) % $ 3.71 $ 1.44 $ 2.27 158 % NGLs (per Bbl) $ 28.41 $ 26.93 $ 1.48 5 % $ 27.77 $ 12.09 $ 15.68 130 % Per BOE $ 45.28 $ 42.11 $ 3.17 8 % $ 43.87 $ 22.25 $ 21.62 97 % Per BOE data: (1) Production costs: Lease operating expense $ 4.62 $ 4.64 $ (0.02) — % $ 4.63 $ 4.06 $ 0.57 14 % Transportation costs 3.01 2.94 0.07 2 % 2.98 3.11 (0.13) (4) % Production taxes 2.03 1.94 0.09 5 % 1.99 0.90 1.09 121 % Ad valorem tax expense 0.45 0.52 (0.07) (13) % 0.48 0.42 0.06 14 % Total production costs (1) $ 10.10 $ 10.04 $ 0.06 1 % $ 10.07 $ 8.49 $ 1.58 19 % Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 16.48 $ 16.62 $ (0.14) (1) % $ 16.54 $ 17.59 $ (1.05) (6) % General and administrative $ 1.98 $ 2.46 $ (0.48) (20) % $ 2.20 $ 2.32 $ (0.12) (5) % Derivative settlement gain (loss) (2) $ (12.78) $ (10.74) $ (2.04) (19) % $ (11.87) $ 9.17 $ (21.04) (229) % Earnings per share information (in thousands, except per share data): (3) Basic weighted-average common shares outstanding 118,357 114,759 3,598 3 % 116,568 113,015 3,553 3 % Diluted weighted-average common shares outstanding 118,357 114,759 3,598 3 % 116,568 113,015 3,553 3 % Basic net loss per common share $ (1.88) $ (2.19) $ 0.31 14 % $ (4.07) $ (4.43) $ 0.36 8 % Diluted net loss per common share $ (1.88) $ (2.19) $ 0.31 14 % $ (4.07) $ (4.43) $ 0.36 8 % 29 ______________________________________ (1) Amounts and percentage changes may not calculate due to rounding. (2) Derivative settlements for the three months ended June 30, 2021, and for the six months ended June 30, 2021, and 2020, are included within the net derivative (gain) loss line item in the accompanying statements of operations. (3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion. Average net daily equivalent production for the three months ended June 30, 2021, increased 22 percent sequentially and decreased four percent YTD 2021-over-YTD 2020. The sequential quarterly increase is primarily related to the Texas Weather Event that caused temporary impacts to production in the first quarter of 2021. 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 for the three months ended June 30, 2021, increased $3.17 sequentially as a result of strengthening benchmark commodity prices. The positive impact on oil, gas, and NGL production revenues resulting from the sequential quarterly realized price increase was partially offset by an increase in the loss on the settlement of our derivative contracts of $2.04 per BOE. Our realized price on a per BOE basis increased $21.62 YTD 2021-over-YTD 2020, primarily as a result of strengthening benchmark commodity prices as benchmark commodity prices during the six months ended June 30, 2020, fell to historic lows as a result of the impacts of the Pandemic. Further contributing to the YTD 2021-over-YTD 2020 increase were increased gas prices during the first quarter of 2021 resulting from the supply and demand imbalance caused by the Texas Weather Event. The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2021-over-YTD 2020 realized price increase was mostly offset by a 229% change in the settlement of our derivative contracts which were a loss of $11.87 per BOE for the six months ended June 30, 2021, compared to a gain of $9.17 per BOE for the same period in 2020. Lease operating expense (“LOE”) on a per BOE basis for the three months ended June 30, 2021, remained flat sequentially, and increased 14 percent YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 increase was driven by the increased percentage of oil in our total product mix, which has higher lifting costs per BOE, and by a total net equivalent production volume decrease of five percent. For the full year 2021, we expect LOE on a per BOE basis to increase, compared with 2020, due to higher oil production and increased workover expense. 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 for the three months ended June 30, 2021 increased slightly sequentially, and decreased four percent YTD 2021-over-YTD 2020 as a result of a 19 percent decrease in production volumes from our South Texas assets, which incur the majority of our transportation costs. We expect total transportation costs to fluctuate relative to changes in production from our South Texas assets. On a per BOE basis, we expect transportation costs to decrease for the full year 2021, compared with 2020, as production from our Midland Basin assets, which is sold at or near the wellhead and incurs minimal transportation costs, comprises a larger portion of our total production. Further, we anticipate natural declines in production from our Eagle Ford shale wells in South Texas, which incur higher transportation costs on a per BOE basis, and we intend to focus on new wells with higher liquids content in the Austin Chalk, which have lower transportation costs on a per BOE basis. In addition, we expect to benefit from certain transportation contract cost reductions that are expected to further reduce our transportation expense per BOE during 2021. Production taxes on a per BOE basis for the three months ended June 30, 2021, increased five percent sequentially, and increased 121 percent YTD 2021-over-YTD 2020, primarily driven by increases in realized prices. Our overall production tax rate was 4.5 percent for each of the three and six months ended June 30, 2021, compared with 4.6 percent for the three months ended March 31, 2021, and 4.0 percent for the six months ended June 30, 2020. The YTD 2021-over-YTD 2020 increase in the production tax rate was primarily driven by increases in realized prices and increased production from our Midland Basin assets. We expect our total production tax expense to increase in 2021, compared with 2020, as we expect oil, gas, and NGL production revenue to increase due to increased pricing. 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 that we recognize. Ad valorem tax expense on a per BOE basis for the three months ended June 30, 2021, decreased 13 percent sequentially, and increased 14 percent YTD 2021-over-YTD 2020. The sequential quarterly decrease was a result of increased net equivalent production volumes. The YTD 2021-over-YTD 2020 increase was primarily a result of 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 change. Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis remained flat sequentially, and decreased six percent YTD 2021-over-YTD 2020. The YTD 2021-over-YTD 2020 decrease was primarily driven by 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. For the full year 2021, we expect DD&A per BOE and DD&A expense on an absolute basis to 30 decrease compared with 2020, primarily as a result of increased activity in our Austin Chalk program compared with 2020, 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 decreased 20 percent sequentially, and decreased five percent YTD 2021-over-YTD 2020. The sequential quarterly decrease was primarily the result of increased production volumes during the three months ended June 30, 2021, and the YTD 2021-over-YTD 2020 decrease was primarily the result of actions taken to reduce costs in response to the Pandemic. For the full year 2021, we expect G&A expense to be relatively flat, in total and on a per BOE basis, compared with 2020. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 below for additional discussion on operating expenses. Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2021, and March 31, 2021, and Between the Six Months Ended June 30, 2021, and 2020 Net equivalent production, production revenue, and production expense Sequential Quarterly Changes. The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the three months ended June 30, 2021, and March 31, 2021: Net Equivalent Production Increase Production Revenue Increase Production Expense Increase (MBOE per day) (in millions) (in millions) Midland Basin 15.5 $ 112.0 $ 13.9 South Texas 9.4 27.4 10.6 Total 24.9 $ 139.4 $ 24.5 __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes increased 22 percent driven by increases of 26 percent and 20 percent in average net daily equivalent production volumes from our South Texas and Midland Basin assets, respectively. These increases were primarily related to the Texas Weather Event, which caused temporary impacts to production in the first quarter of 2021. Realized prices for oil and NGLs increased 16 percent and five percent, respectively, and decreased 20 percent for gas. As a result of increases in benchmark commodity prices for oil and NGLs during the second quarter of 2021, oil, gas, and NGL production revenue increased 33 percent. Total production expense increased 24 percent as a result of increased average net daily equivalent production volumes and realized prices. YTD 2021-over-YTD 2020. The following table presents the changes in our net equivalent production, production revenue, and production expense, by area, between the six months ended June 30, 2021, and 2020: Net Equivalent Production Increase (Decrease) Production Revenue Increase Production Expense Increase (Decrease) (MBOE per day) (in millions) (in millions) Midland Basin 3.9 $ 386.2 $ 27.7 South Texas (9.2) 75.5 (1.3) Total (5.2) $ 461.7 $ 26.4 __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes decreased four percent, driven by a decrease of 19 percent in average net daily equivalent production volumes from our South Texas assets, partially offset by an increase of five percent in average net daily equivalent production volumes from our Midland Basin assets. These changes were primarily the result of higher capital allocations to the Midland Basin in prior years. Realized prices for oil, gas, and NGLs increased 75 percent, 158 percent, and 130 percent, respectively. As a result of increases in benchmark commodity prices, during the first half of 2021, oil, gas, and NGL production revenue increased 88 percent. Total production expense increased 13 percent, primarily as a result of increased production taxes. Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis. 31 Depletion, depreciation, amortization, and asset retirement obligation liability accretion For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 204.7 $ 167.0 $ 371.7 $ 414.3 DD&A expense for the three months ended June 30, 2021, increased 23 percent sequentially, and decreased 10 percent YTD 2021-over-YTD 2020. The sequential quarterly increase was primarily driven by an increase in total net equivalent production volumes of 24 percent. The YTD 2021-over-YTD 2020 decrease was driven by both a decrease in production volumes of five percent 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. Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis. Exploration For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Geological and geophysical expenses $ 0.8 $ 0.3 $ 1.1 $ 1.4 Overhead and other expenses 7.9 9.0 16.9 19.7 Total $ 8.7 $ 9.3 $ 18.0 $ 21.1 Exploration expense for the three months ended June 30, 2021, decreased seven percent sequentially, and decreased 15 percent YTD 2021-over-YTD 2020, primarily as a result of decreases in overhead and other expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and the potential for exploratory dry hole expense. Impairment For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Impairment of proved oil and gas properties and related support equipment $ — $ — $ — $ 956.7 Abandonment and impairment of unproved properties 8.8 8.8 17.5 41.9 Total $ 8.8 $ 8.8 $ 17.5 $ 998.5 __________________________________________ Note: Amounts may not calculate due to rounding. There were no proved oil and gas property impairments for the three and six months ended June 30, 2021. During the six months ended June 30, 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. Unproved property abandonments and impairments recorded during each period presented above 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 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. Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of July 21, 2021, we do not expect any material property impairments in the third quarter of 2021 resulting from commodity price impacts. 32 Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense. General and administrative For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) General and administrative $ 24.6 $ 24.7 $ 49.4 $ 54.7 G&A expense remained flat sequentially, and decreased 10 percent YTD 2021-over-YTD 2020, primarily as a result of actions taken to reduce costs in response to the Pandemic. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis. Net derivative (gain) loss For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Net derivative (gain) loss $ 370.3 $ 344.7 $ 715.0 $ (378.1) We recognized a derivative loss of $370.3 million for the three months ended June 30, 2021. The loss was primarily driven by a $211.5 million downward mark-to-market adjustment due to strengthening commodity prices during the second quarter of 2021. Additionally, we recognized losses on the settlement of derivative contracts of $158.8 million during the three months ended June 30, 2021. We recognized a derivative loss of $344.7 million for the three months ended March 31, 2021. The loss was primarily driven by a $236.8 million downward mark-to-market adjustment due to strengthening commodity prices during the first three months of 2021. Additionally, we recognized losses on the settlement of derivative contracts of $107.9 million during the three months ended March 31, 2021. We recognized a derivative loss of $715.0 million for the six months ended June 30, 2021. For contracts that settled during the first half of 2021, the fair value was a net liability of $76.1 million at December 31, 2020, and net cash settlements totaled $266.7 million, resulting in a $190.6 million loss. We recorded a $524.4 million mark-to-market loss on unsettled contracts as of June 30, 2021 resulting from strengthening commodity prices during the first half of 2021. We recognized a derivative gain of $378.1 million for the six months ended June 30, 2020, driven by $216.0 million of gains recognized on the settlement of derivative contracts and a $162.2 million upward mark-to-market adjustment resulting from oil price fluctuations during the first half of the year. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion. Interest expense For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Interest expense $ 39.5 $ 39.9 $ 79.4 $ 81.9 Interest expense remained flat sequentially and YTD 2021-over-YTD 2020. We expect interest expense related to our Senior Notes to decrease slightly for 2021 compared with 2020 primarily as a result of the decreased principal amount outstanding on our Senior Notes resulting from the Exchange Offers executed in the second quarter of 2020. 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 Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion. 33 Gain (loss) on extinguishment of debt For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions) Gain (loss) on extinguishment of debt $ (2.1) $ — $ (2.1) $ 239.5 The Tender Offer and 2022 Senior Notes Redemption executed during the second quarter of 2021 resulted in a net loss on extinguishment of debt of $2.1 million, which included $1.5 million of accelerated unamortized deferred financing costs and $600,000 of net premiums paid. 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 partial principal redemption of Old Notes and the debt discount associated with the issuance of the 2025 Senior Secured Notes. During the three months ended March 31, 2020, we recorded a $12.2 million net gain on the early extinguishment of a portion of our 2022 Senior Notes, which included discounts realized upon repurchase of $12.4 million partially offset by $235,000 of accelerated unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of these transactions. Income tax (expense) benefit For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 (in millions, except tax rate) Income tax (expense) benefit $ 0.2 $ (0.1) $ 0.1 $ 135.7 Effective tax rate 0.1 % — % — % 21.3 % The effective tax benefit rate remained flat sequentially. The decrease in the effective tax benefit rate for the six months ended June 30, 2021, compared with the same period in 2020, was primarily due to the effects of forecasted income for the year ended December 31, 2021, compared to forecasted loss at June 30, 2020, and the correlative effect on the valuation allowance balance in each period. For each of the comparable periods, the tax rates reflect the proportional effects of excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation. Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material impact on our effective tax rate and current tax expense. Please refer to the Risk Factors section in Part I, Item 1A of our 2020 Form 10-K for additional discussion. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional 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 2021 capital program to be funded by cash flows from operations. Although we expect cash flows from operations to be sufficient to fund our expected 2021 capital program, we may also use borrowings under our revolving credit facility or may elect to 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 cost carrying 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. 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. 34 We have no control over the market prices for oil, gas, or 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 I, Item 1 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 March 2021, as a result of the regular, semi-annual redetermination, both the borrowing base and aggregate lender commitments were reaffirmed at the amounts noted above. The next scheduled borrowing base redetermination date is October 1, 2021. As of June 30, 2021, the remaining available borrowing capacity under our Credit Agreement provided $1.0 billion in liquidity. 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 I, Item 1 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 July 21, 2021, June 30, 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 June 30, 2021, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. Our daily weighted-average revolving credit facility debt balance was $141.5 million and $134.2 million for the three months ended June 30, 2021, and March 31, 2021, respectively, and $137.9 million and $113.0 million for the six months ended June 30, 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. The use of LIBOR as a global reference rate is expected to be discontinued after 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. 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 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 the non-cash amortization of the discounts related to the 2021 Senior Secured Convertible Notes and 2025 Senior Secured Notes. Our weighted-average borrowing rate includes paid and accrued interest only. The following table details our weighted-average interest rates and our weighted-average borrowing rates for the periods presented: For the Three Months Ended For the Six Months Ended June 30, 2021 March 31, 2021 June 30, 2021 June 30, 2020 Weighted-average interest rate 7.6 % 7.7 % 7.7 % 6.6 % Weighted-average borrowing rate 6.7 % 6.7 % 6.7 % 5.8 % Our weighted-average interest rates and weighted-average borrowing rates are impacted by the 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. For the three months ended June 30, 2021, our weighted-average interest rate and our weighted-average borrowing rate remained flat sequentially, and increased YTD 2021-over-YTD 2020, primarily as a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second 35 quarter of 2020. 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. 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 the six months ended June 30, 2021, we spent approximately $370.2 million on capital expenditures. This amount differs from the costs incurred amount of $417.2 million for the six months ended June 30, 2021, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts. 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. 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 and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. Our 2021 total capital program budget is between $650.0 million and $675.0 million. We will continue to monitor the economic environment throughout the year and adjust our activity level as warranted. 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, 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 the second quarter of 2021, we issued our 2028 Senior Notes and used the net cash proceeds of $393.6 million to repurchase $193.1 million and $172.3 million of outstanding principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, through the Tender Offer, and to redeem the remaining $19.3 million of 2022 Senior Notes then outstanding through the 2022 Senior Notes Redemption. We paid total consideration of $385.3 million, including net premiums, and paid $5.2 million of accrued interest related to the 2022 and 2024 Senior Notes. During the first quarter of 2020, we repurchased a total of $40.7 million in aggregate principal amount of our 2022 Senior Notes in open market transactions at a discount, resulting in a net gain on extinguishment of debt of $12.2 million. During the second quarter of 2020, we completed the Exchange Offers, which resulted in the exchange of $718.9 million in aggregate principal amount of Old Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes. Further, in connection with the Private Exchange, we tendered $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes, which was borrowed against our revolving credit facility, and issued the Warrants. Please refer to Note 3 - Equity for additional discussion of the Warrants, including related impacts to equity and Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion of the debt transactions. As part of our strategy for 2021, we will continue to focus on improving our debt metrics, which could include reducing the amount of our outstanding debt. 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 our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the six months ended June 30, 2021, we did not repurchase any shares of our common stock, and we currently do not plan to repurchase any outstanding shares of our common stock during the remainder of 2021. Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2021, and 2020 The following tables present changes in cash flows between the six months ended June 30, 2021, and 2020, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying unaudited condensed consolidated statements of cash flows in Part I, Item 1 of this report. Operating activities For the Six Months Ended June 30, Amount Change Between Periods 2021 2020 (in millions) Net cash provided by operating activities $ 402.0 $ 332.5 $ 69.5 36 Net cash provided by operating activities increased for the six months ended June 30, 2021, compared with the same period in 2020, primarily due to working capital changes resulting from the timing of cash receipts and disbursements. During the six months ended June 30, 2021, compared with the same period in 2020, cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes increased $295.8 million, cash paid for LOE and ad valorem taxes decreased $22.7 million, and cash paid on settled derivative trades increased $379.9 million. Investing activities For the Six Months Ended June 30, Amount Change Between Periods 2021 2020 (in millions) Net cash used in investing activities $ (370.0) $ (310.1) $ (59.9) Net cash used in investing activities increased for the six months ended June 30, 2021, compared with the same period in 2020, due to increased capital expenditures of $60.0 million. Financing activities For the Six Months Ended June 30, Amount Change Between Periods 2021 2020 (in millions) Net cash used in financing activities $ (32.1) $ (22.4) $ (9.7) Net cash used in financing activities for the six months ended June 30, 2021, related to $385.3 million of net cash paid, including net premiums to fund the Tender Offer and the 2022 Senior Notes Redemption and net repayments under our revolving credit facility of $40.5 million, offset by net cash proceeds of $393.6 million from the issuance of our 2028 Senior Notes. Net cash used in financing activities for the six months ended June 30, 2020, related to $81.8 million of net cash paid to repurchase certain of our Senior Notes, and $10.5 million of debt issuance costs incurred upon the issuance of the 2025 Senior Secured Notes, offset by net borrowings under our revolving credit facility of $70.5 million. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. 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 June 30, 2021, we had a $52.5 million 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 Unsecured Notes or fixed-rate Senior Secured Notes but can impact their fair values. As of June 30, 2021, our outstanding principal amount of fixed-rate debt totaled $2.2 billion and our floating-rate debt outstanding totaled $52.5 million. Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 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 infection rate surges or outbreaks could have further negative impacts on prices. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our production for the six months ended June 30, 2021, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $74.2 million, $17.8 million, and $6.6 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the six months ended June 30, 2021, would have offset the declines in oil, gas, and NGL production revenue by approximately $82.1 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 June 30, 2021, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative 37 instruments would have changed our net derivative positions for these products by approximately $145.1 million, $28.3 million, and $11.8 million, respectively. Off-Balance Sheet Arrangements As part of our ongoing business, 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 (“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 the six months ended June 30, 2021, or through the filing of this report. Critical Accounting Policies and Estimates Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2020 Form 10-K for discussion of our accounting policies and estimates. New Accounting Pronouncements Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for new accounting pronouncements. 38 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 the 2020 Form 10-K . 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 that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default. The following table provides reconciliations of our net loss (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented: For the Three Months Ended June 30, For the Six Months Ended June 30, 2021 2020 2021 2020 (in thousands) Net loss (GAAP) $ (222,995) $ (89,252) $ (474,264) $ (501,147) Interest expense 39,536 40,354 79,407 81,866 Income tax benefit (162) (36,685) (56) (135,693) Depletion, depreciation, amortization, and asset retirement obligation liability accretion 204,714 180,856 371,674 414,345 Exploration (1) 7,902 8,696 15,941 19,088 Impairment 8,750 8,750 17,500 998,513 Stock-based compensation expense 3,956 5,712 9,693 11,273 Net derivative (gain) loss 370,348 167,200 715,037 (378,140) Derivative settlement gain (loss) (158,822) 142,528 (266,707) 215,965 (Gain) loss on extinguishment of debt 2,144 (227,281) 2,144 (239,476) Other, net 1,512 612 1,502 945 Adjusted EBITDAX (non-GAAP) 256,883 201,490 471,871 487,539 Interest expense (39,536) (40,354) (79,407) (81,866) Income tax benefit 162 36,685 56 135,693 Exploration (1) (7,902) (8,696) (15,941) (19,088) Amortization of debt discount and deferred financing costs 4,722 4,586 9,445 8,578 Deferred income taxes (162) (36,921) (214) (136,268) Other, net (297) (3,714) (14,879) (4,863) Net change in working capital 82,529 (38,737) 31,092 (57,254) Net cash provided by operating activities (GAAP) $ 296,399 $ 114,339 $ 402,023 $ 332,471 ____________________________________________ (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. 39