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. Overview of the Company General Overview Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to energy security and prosperity, and having a positive impact in the communities where we live and work. 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 assets. Our investment portfolio is currently focused on high quality oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in South Texas. Areas of Operations Our Midland Basin assets are located in the Permian Basin in West Texas and are comprised of approximately 80,000 net acres (“Midland Basin”). In the third quarter of 2020, we focused on continuing to delineate, develop, and expand 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 159,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). Our current operations in South Texas are focused on developing the Eagle Ford shale formation and delineating 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. Third Quarter 2020 Overview and Outlook for the Remainder of 2020 The impacts of the Pandemic on supply and demand for oil, gas, and NGLs continue to be unpredictable. Given the dynamic nature of the Pandemic, we are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will continue to impact our business, results of operations, and financial condition, or the timing of any subsequent recovery. Future case surges or outbreaks could have further negative impacts, and as a result, we may be required to adjust our business plan. For additional detail, please refer to Risk Factors in Part II, Item 1A of this report and those risk factors previously disclosed in our 2019 Form 10-K . During the third quarter of 2020, the Pandemic and associated macroeconomic events continued to affect the realized prices we received for our production, and we expect these impacts to continue for the remainder of the year. Despite continuing negative impacts 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. During the third quarter of 2020, we repurchased $62.5 million and $29.0 million in aggregate principal amount of our 2022 Senior Notes and 2024 Senior Notes, respectively, while also reducing the balance on our revolving credit facility by $15.0 million from June 30, 2020 to September 30, 2020. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. Our financial risk management program has significantly reduced the impact of substantially lower oil prices in 2020, and as a result of this program we recorded an oil derivative settlement gain of $15.16 per barrel for the nine months ended September 30, 2020. Our realized oil price before the effects of derivative settlements was $35.92 for the nine months ended September 30, 2020. As of September 30, 2020, a majority of our expected oil production for the remainder of 2020 is covered by derivative contracts at weighted-average NYMEX equivalent prices greater than $56.00 per barrel. Please refer to Oil, Gas, and NGL Prices below for additional detail on our financial risk management program and the pricing effects of our derivative settlements. Additionally, in response to the current economic environment, we have renegotiated certain contracts resulting in realized and future cost savings that directly support our objective of maximizing cash flows. As a result of these cost saving measures and improving operational efficiencies, we expect average well costs for 2020 to be lower than our preliminary expectations for the year. We believe that sustainability is critical to positioning ourselves financially to participate in future energy investment opportunities and executing our strategy of being a premier operator with high standards for corporate responsibility. We remain committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive difference 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 reports to our Board of Directors regarding such matters. The safety of our employees, contractors, and the communities where we work is our first priority as we continue to operate during the Pandemic. While the execution of our core business operations requires certain individuals to be physically present at well 29 site locations, substantially all of our office-based employees have continued working remotely in order to limit physical interactions and 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. 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 continue to be effective and we continue to address new risks directly related to the Pandemic as we identify them. The information below summarizes our operating and financial performance and our expectations for the remainder of 2020. We entered 2020 with a total capital program budget between $825 million and $850 million. However, given the Pandemic and related circumstances discussed above, we reduced our 2020 capital program by approximately 25 percent for the full year 2020. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2020 capital program remains focused on developing and retaining our most economic projects in both our Midland Basin and South Texas assets. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund our 2020 capital program. Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2020, was 126.3 MBOE, compared with 134.9 MBOE for the same period in 2019. This decrease was driven by a 22 percent decrease in production volumes from our South Texas assets, partially offset by a seven percent increase in production volumes from our Midland Basin assets. The overall decrease in production volumes for the three months ended September 30, 2020, was primarily due to fewer net well completions during the nine months ended September 30, 2020, compared with the same period in 2019, as we reduced capital expenditures in response to lower commodity prices in 2020. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased 30 percent, 12 percent, and 11 percent, respectively, for the three months ended September 30, 2020, compared with the same period in 2019. As a result of decreased production and pricing, oil, gas, and NGL production revenue decreased 28 percent to $282.0 million for the three months ended September 30, 2020, from $389.4 million for the same period in 2019. We recorded a net derivative loss of $63.9 million and a net derivative gain of $100.9 million for the three months ended September 30, 2020, and 2019, respectively. Included within these derivative amounts is a gain of $70.3 million on derivative contracts that settled during the three months ended September 30, 2020, and a gain of $24.7 million for the same period in 2019. Total production costs on a per BOE basis decreased 21 percent to $8.20 per BOE for the three months ended September 30, 2020, from $10.41 per BOE for the same period in 2019. Financial and operational activities during the three months ended September 30, 2020, resulted in the following: • a $103.1 million decrease in our total outstanding long-term debt balance from June 30, 2020, to September 30, 2020, primarily driven by net cash provided by operating activities of $201.6 million for the three months ended September 30, 2020, which was in excess of net cash used in investing activities of $116.6 million for the three months ended September 30, 2020; • net loss of $98.3 million, or $0.86 per diluted share, for the three months ended September 30, 2020, compared with net income of $42.2 million, or $0.37 per diluted share, for the same period in 2019. The net loss for the three months ended September 30, 2020, was primarily due to a $134.2 million downward mark-to-market adjustment on our commodity derivative contracts. Please refer to Comparison of Financial Results and Trends Between the Three and Nine Months Ended September 30, 2020, and 2019 below for additional discussion regarding the components of net income (loss) for the periods presented; and • adjusted EBITDAX, a non-GAAP financial measure, for the three months ended September 30, 2020, was $232.5 million, compared with $257.8 million for the same period in 2019. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities. Operational Activities. The financial results and operational activity discussed throughout this report reflect the impacts of the Pandemic and the misalignment of supply and demand caused by competition among oil producing nations for crude oil market share. We will continue to monitor the economic environment through the remainder of the year and maintain flexibility to make related financial and operational adjustments as warranted. In our Midland Basin program, we operated four drilling rigs and one completion crew during the third quarter of 2020. We drilled 23 gross (19 net) wells and completed 22 gross (22 net) wells during the third quarter of 2020, and increased production volumes year-over-year by seven percent to 7.1 MMBOE. Costs incurred for oil and gas producing activities in our Midland Basin program during the three months ended September 30, 2020, totaled $120.4 million, or 89 percent of our total costs incurred for the period. We plan to operate between three and four drilling rigs and between one and two completion crews for the remainder of the year. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin continue to focus primarily on delineating and developing the Lower Spraberry and Wolfcamp shale intervals. 30 In our South Texas program, we entered the third quarter of 2020 with no drilling rigs and we began operating one drilling rig in September. We completed two gross (two net) wells during the third quarter of 2020. Production volumes for the third quarter of 2020 decreased 22 percent year-over-year. While natural decline and our deferral of activity led to a decrease in total production volumes, oil production volumes increased 40 percent year-over-year as a result of the higher liquids content from our Austin Chalk completions. Costs incurred for oil and gas producing activities in our South Texas program during the three months ended September 30, 2020, totaled $7.2 million, or five percent of our total costs incurred for the period. We anticipate operating one drilling rig and one completion crew at times during the remainder of 2020 in South Texas. Drilling and completion activities in South Texas during the remainder of 2020 will be focused on delineating 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 nine months ended September 30, 2020: Midland Basin South Texas Total Gross Net Gross Net Gross Net Wells drilled but not completed at December 31, 2019 51 48 21 21 72 69 Wells drilled 25 22 3 3 28 25 Wells completed (19) (19) (1) (1) (20) (20) Other (1) — 1 — — — 1 Wells drilled but not completed at March 31, 2020 57 52 23 23 80 75 Wells drilled 25 23 4 4 29 27 Wells completed (13) (10) (1) (1) (14) (11) Wells drilled but not completed at June 30, 2020 69 65 26 26 95 91 Wells drilled 23 19 — — 23 19 Wells completed (22) (22) (2) (2) (24) (24) Other (1) — 1 — — — 1 Wells drilled but not completed at September 30, 2020 70 63 24 24 94 87 ____________________________________________ (1) Includes adjustments related to normal business activities, including working interest changes for existing drilled but not completed wells. Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $135.7 million and $437.1 million for the three and nine months ended September 30, 2020, respectively, and were incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above. Production Results. The table below presents our production by product type for each of our areas of operation for the three months ended September 30, 2020, and 2019: Midland Basin South Texas Total Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2020 2019 2020 2019 2020 2019 Production: Oil (MMBbl) 5.0 5.1 0.5 0.3 5.5 5.4 Gas (Bcf) 12.3 9.1 13.8 20.4 26.1 29.5 NGLs (MMBbl) — — 1.8 2.1 1.8 2.1 Equivalent (MMBOE) 7.1 6.6 4.5 5.8 11.6 12.4 Average net daily equivalent (MBOE/d) 76.9 71.7 49.3 63.2 126.3 134.9 Relative percentage 61 % 53 % 39 % 47 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. 31 The table below presents our production by product type for each of our areas of operation for the nine months ended September 30, 2020, and 2019: Midland Basin South Texas Total Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 2020 2019 Production: Oil (MMBbl) 16.0 14.8 1.3 0.9 17.2 15.7 Gas (Bcf) 34.0 24.4 44.6 57.3 78.6 81.7 NGLs (MMBbl) — — 4.8 6.2 4.8 6.2 Equivalent (MMBOE) 21.6 18.8 13.5 16.7 35.2 35.5 Average net daily equivalent (MBOE/d) 79.0 69.0 49.4 61.1 128.3 130.1 Relative percentage 62 % 53 % 38 % 47 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. Please refer to A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three and Nine Months Ended September 30, 2020, and 2019 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. The following table summarizes commodity price data, as well as the effects of derivative settlements, for the third and second quarters of 2020 as well as the third quarter of 2019: For the Three Months Ended September 30, 2020 June 30, 2020 September 30, 2019 Oil (per Bbl): Average NYMEX contract monthly price $ 40.93 $ 27.85 $ 56.45 Realized price, before the effect of derivative settlements $ 37.69 $ 22.25 $ 53.99 Effect of oil derivative settlements $ 12.51 $ 25.81 $ (0.41) Gas: Average NYMEX monthly settle price (per MMBtu) $ 1.98 $ 1.72 $ 2.23 Realized price, before the effect of derivative settlements (per Mcf) $ 1.90 $ 1.34 $ 2.17 Effect of gas derivative settlements (per Mcf) $ 0.03 $ 0.04 $ 0.41 NGLs (per Bbl): Average OPIS price (1) $ 19.13 $ 14.02 $ 18.89 Realized price, before the effect of derivative settlements $ 14.07 $ 10.43 $ 15.73 Effect of NGL derivative settlements $ 0.29 $ 1.94 $ 7.14 ____________________________________________ (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. During the first nine months of 2020, benchmark prices for oil were impacted by the misalignment of supply and demand caused by the Pandemic and other macroeconomic events. 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. We expect future benchmark prices for oil, gas, and NGLs to remain depressed for 32 the foreseeable future due to the Pandemic and the misalignment of supply and demand. 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 Third Quarter 2020 Overview and Outlook for the Remainder of 2020 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 October 21, 2020, and September 30, 2020: As of October 21, 2020 As of September 30, 2020 NYMEX WTI oil (per Bbl) $ 41.13 $ 41.53 NYMEX Henry Hub gas (per MMBtu) $ 3.13 $ 2.84 OPIS NGLs (per Bbl) $ 20.22 $ 19.46 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 senior executive officers and finance personnel. The amount of our production covered by derivatives is driven by 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. Financial Results of Operations and Additional Comparative Data The tables below provide information regarding selected production and financial information for the three months ended September 30, 2020, and the preceding three quarters. For the Three Months Ended September 30, June 30, March 31, December 31, 2020 2020 2020 2019 (in millions) Production (MMBOE) 11.6 11.2 12.4 12.8 Oil, gas, and NGL production revenue $ 282.0 $ 169.8 $ 354.2 $ 449.0 Oil, gas, and NGL production expense $ 95.3 $ 80.4 $ 119.6 $ 127.3 Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 181.7 $ 180.9 $ 233.5 $ 228.7 Exploration $ 8.5 $ 9.8 $ 11.3 $ 17.7 General and administrative $ 24.5 $ 27.2 $ 27.4 $ 37.2 Net loss $ (98.3) $ (89.3) $ (411.9) $ (102.1) ____________________________________________ Note: Amounts may not calculate due to rounding. Selected Performance Metrics For the Three Months Ended September 30, June 30, March 31, December 31, 2020 2020 2020 2019 Average net daily equivalent production (MBOE per day) 126.3 122.9 135.9 138.8 Lease operating expense (per BOE) $ 3.65 $ 3.30 $ 4.75 $ 4.67 Transportation costs (per BOE) $ 3.11 $ 3.12 $ 3.11 $ 3.46 Production taxes as a percent of oil, gas, and NGL production revenue 4.3 % 3.7 % 4.2 % 4.2 % Ad valorem tax expense (per BOE) $ 0.40 $ 0.22 $ 0.60 $ 0.37 Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) $ 15.64 $ 16.17 $ 18.88 $ 17.91 General and administrative (per BOE) $ 2.10 $ 2.43 $ 2.22 $ 2.92 ____________________________________________ Note: Amounts may not calculate due to rounding. 33 A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends For the Three Months Ended September 30, Amount Change Between Periods Percent Change Between Periods For the Nine Months Ended September 30, Amount Change Between Periods Percent Change Between Periods 2020 2019 2020 2019 Net production volumes: (1) Oil (MMBbl) 5.5 5.4 0.1 2 % 17.2 15.7 1.5 10 % Gas (Bcf) 26.1 29.5 (3.4) (12) % 78.6 81.7 (3.1) (4) % NGLs (MMBbl) 1.8 2.1 (0.3) (15) % 4.8 6.2 (1.4) (22) % Equivalent (MMBOE) 11.6 12.4 (0.8) (6) % 35.2 35.5 (0.4) (1) % Average net daily production: (1) Oil (MBbl per day) 59.9 59.0 0.9 2 % 62.9 57.5 5.4 9 % Gas (MMcf per day) 283.3 320.6 (37.4) (12) % 286.7 299.2 (12.4) (4) % NGLs (MBbl per day) 19.2 22.5 (3.3) (15) % 17.7 22.8 (5.1) (22) % Equivalent (MBOE per day) 126.3 134.9 (8.6) (6) % 128.3 130.1 (1.8) (1) % Oil, gas, and NGL production revenue (in millions): (1) Oil production revenue $ 207.6 $ 292.9 $ (85.2) (29) % $ 618.9 $ 836.1 $ (217.2) (26) % Gas production revenue 49.6 64.0 (14.5) (23) % 125.1 194.4 (69.3) (36) % NGL production revenue 24.8 32.5 (7.7) (24) % 62.1 106.3 (44.3) (42) % Total oil, gas, and NGL production revenue $ 282.0 $ 389.4 $ (107.4) (28) % $ 806.0 $ 1,136.7 $ (330.7) (29) % Oil, gas, and NGL production expense (in millions): (1) Lease operating expense $ 42.4 $ 58.7 $ (16.3) (28) % $ 138.1 $ 166.0 $ (27.9) (17) % Transportation costs 36.1 49.6 (13.5) (27) % 109.4 142.9 (33.5) (23) % Production taxes 12.1 16.0 (3.9) (25) % 33.2 46.1 (12.9) (28) % Ad valorem tax expense 4.7 4.8 (0.1) (2) % 14.6 18.4 (3.8) (21) % Total oil, gas, and NGL production expense $ 95.3 $ 129.0 $ (33.8) (26) % $ 295.3 $ 373.4 $ (78.1) (21) % Realized price, before the effect of derivative settlements: Oil (per Bbl) $ 37.69 $ 53.99 $ (16.30) (30) % $ 35.92 $ 53.31 $ (17.39) (33) % Gas (per Mcf) $ 1.90 $ 2.17 $ (0.27) (12) % $ 1.59 $ 2.38 $ (0.79) (33) % NGLs (per Bbl) $ 14.07 $ 15.73 $ (1.66) (11) % $ 12.81 $ 17.09 $ (4.28) (25) % Per BOE $ 24.28 $ 31.39 $ (7.11) (23) % $ 22.92 $ 32.00 $ (9.08) (28) % Per BOE data: (1) Production costs: Lease operating expense $ 3.65 $ 4.73 $ (1.08) (23) % $ 3.93 $ 4.67 $ (0.74) (16) % Transportation costs 3.11 4.00 (0.89) (22) % 3.11 4.02 (0.91) (23) % Production taxes 1.04 1.29 (0.25) (19) % 0.94 1.30 (0.36) (28) % Ad valorem tax expense 0.40 0.39 0.01 3 % 0.41 0.52 (0.11) (21) % Total production costs (1) $ 8.20 $ 10.41 $ (2.21) (21) % $ 8.40 $ 10.51 $ (2.11) (20) % Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 15.64 $ 17.02 $ (1.38) (8) % $ 16.95 $ 16.76 $ 0.19 1 % General and administrative $ 2.10 $ 2.63 $ (0.53) (20) % $ 2.25 $ 2.69 $ (0.44) (16) % Derivative settlement gain (2) $ 6.05 $ 1.99 $ 4.06 204 % $ 8.14 $ 0.67 $ 7.47 1,115 % Earnings per share information: (3) Basic weighted-average common shares outstanding (in thousands) 114,371 112,804 1,567 1 % 113,462 112,441 1,021 1 % Diluted weighted-average common shares outstanding (in thousands) 114,371 113,334 1,037 1 % 113,462 112,441 1,021 1 % Basic net income (loss) per common share $ (0.86) $ 0.37 $ (1.23) (332) % $ (5.28) $ (0.76) $ (4.52) (595) % Diluted net income (loss) per common share $ (0.86) $ 0.37 $ (1.23) (332) % $ (5.28) $ (0.76) $ (4.52) (595) % ______________________________________ (1) Amounts and percentage changes may not calculate due to rounding. (2) Derivative settlements for the three and nine months ended September 30, 2020, and 2019 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. 34 Average net daily equivalent production for the three months ended September 30, 2020, decreased six percent compared with the same period in 2019, primarily driven by a 22 percent decrease in production volumes from our South Texas assets, partially offset by a seven percent increase in production volumes from our Midland Basin assets. The total decrease in production volumes was primarily due to fewer net well completions during the nine months ended September 30, 2020, compared with the same period in 2019, as we reduced capital expenditures in response to lower commodity prices in 2020. Average net daily equivalent production for the nine months ended September 30, 2020, remained relatively flat compared with the same period in 2019 as decreases in production volumes from our South Texas assets were mostly offset by increases in production volumes from our Midland Basin assets. For the full year 2020, we expect total production volumes to decrease compared with 2019. 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 before the effect of derivative settlements on a per BOE basis decreased $7.11 per BOE and $9.08 per BOE for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019, primarily driven by lower benchmark commodity prices for oil, gas, and NGLs resulting from the Pandemic and other macroeconomic events. Regional pricing differentials in the Midland Basin negatively affected our realized prices in 2019 and continue to negatively affect our realized prices in 2020. The negative impacts on revenue associated with the decreases in our realized prices before the effect of derivative settlements on a per BOE basis were partially offset by increases in the gains we recognized on the settlement of our derivative contracts of $4.06 per BOE and $7.47 per BOE for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. Lease operating expense (“LOE”) on a per BOE basis decreased 23 percent and 16 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were driven by reduced costs and reduced workover activity during the first nine months of 2020. For the full year 2020, we expect LOE on a per BOE basis to be lower, compared with 2019, as we continue to benefit from reduced costs and improved operational efficiencies. While we will continue our efforts to reduce costs during 2020, 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 impacts total LOE. Transportation costs on a per BOE basis decreased 22 percent and 23 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were driven by a 22 percent and 19 percent reduction in production volumes from our South Texas assets, which incur the majority of our transportation costs, for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. 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 in 2020, compared with 2019, as production from our Midland Basin assets, which is sold at or near the wellhead and incurs minimal transportation costs, continues to become a larger portion of our total production, and as we experience natural declines in production from our Eagle Ford shale wells in South Texas as we focus on new wells with higher liquids content in the Austin Chalk, which have lower transportation costs on a per BOE basis. Production taxes on a per BOE basis decreased 19 percent and 28 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were primarily driven by a decrease in realized prices. Our overall production tax rates for the three and nine months ended September 30, 2020, were 4.3 percent and 4.1 percent, respectively, compared to 4.1 percent for each of the three and nine months ended September 30, 2019. We expect our total production tax expense to decrease in 2020, compared with 2019, as we expect oil, gas, and NGL production revenue to decrease due to decreased pricing and volumes. 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 we recognize. Ad valorem tax expense on a per BOE basis increased three percent and decreased 21 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. The decrease for the nine months ended September 30, 2020, was primarily the result of changes to the expected 2020 value assessments of our producing properties by respective tax authorities. 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 decreased eight percent and remained relatively flat for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. The decrease for the three months ended September 30, 2020, 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, partially offset by higher production volumes from our oil producing Midland Basin assets as these assets have higher depletion rates than our primarily gas and NGL producing South Texas assets. 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 2020, we expect the DD&A rate to be relatively flat compared with 2019 and DD&A expense on an absolute basis to be lower compared with 2019, primarily as a result of anticipated lower production volumes. 35 General and administrative (“G&A”) expense on a per BOE basis decreased 20 percent and 16 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were 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, and actions taken to reduce costs as a result of the Pandemic. For the full year 2020, we expect G&A expense to be lower, in total and on a per BOE basis, compared with 2019. Please refer to Comparison of Financial Results and Trends Between the Three and Nine Months Ended September 30, 2020, and 2019 below for additional discussion on operating expenses. Comparison of Financial Results and Trends Between the Three and Nine Months Ended September 30, 2020, and 2019 Net equivalent production, production revenue, and production expense The following table presents the regional changes in our net equivalent production, production revenue, and production expense between the three and nine months ended September 30, 2020, and 2019: Net Equivalent Production Increase (Decrease) Production Revenue Decrease Production Expense Decrease Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended (MBOE per day) (in millions) (in millions) Midland Basin 5.2 10.0 $ (77.3) $ (209.2) $ (11.7) $ (22.1) South Texas (13.8) (11.7) (30.1) (121.6) (22.1) (56.0) Total (8.6) (1.8) $ (107.4) $ (330.7) $ (33.8) $ (78.1) __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes for the three and nine months ended September 30, 2020, decreased six percent and one percent, respectively, compared with the same periods in 2019. Realized prices before the effects of derivative settlements for oil, gas, and NGLs decreased 30 percent, 12 percent, and 11 percent, respectively, for the three months ended September 30, 2020, compared with the same period in 2019. For the nine months ended September 30, 2020, realized prices before the effects of derivative settlements decreased 33 percent for both oil and gas, and decreased 25 percent for NGLs, compared with the same period in 2019. As a result of the decreases in production and pricing, oil, gas, and NGL production revenue decreased 28 percent and 29 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. Total production expense for the three and nine months ended September 30, 2020, decreased 26 percent and 21 percent, respectively, compared with the same periods in 2019. Please refer to A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis. Depletion, depreciation, amortization, and asset retirement obligation liability accretion For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 181.7 $ 211.1 $ 596.1 $ 595.2 DD&A expense decreased 14 percent for the three months ended September 30, 2020, compared with the same period in 2019, and remained relatively flat for the nine months ended September 30, 2020, compared with the same period in 2019. The decrease for the three months ended September 30, 2020 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, partially offset by higher production volumes from our oil producing Midland Basin assets as these assets have higher depletion rates than our primarily gas and NGL producing South Texas assets. Please refer to A Three Month and Nine Month Overview of Selected Production and Financial Information, Including Trends above for additional discussion. 36 Exploration For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Geological and geophysical expenses $ 0.2 $ 1.1 $ 1.7 $ 2.0 Overhead and other expenses 8.3 10.5 28.0 31.9 Total $ 8.5 $ 11.6 $ 29.7 $ 33.9 Exploration expense decreased 26 percent and 12 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were primarily driven by the reorganization of certain functions in the fourth quarter of 2019 that eliminated duplicative regional operational functions and reduced overhead costs. For the full year 2020, we expect exploration expense to decrease compared with 2019 as a result of lower overhead; however, exploration expense is impacted by actual geological and geophysical studies we perform and the potential for exploratory dry hole expense. Impairment For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Impairment of proved oil and gas properties and related support equipment $ — $ — $ 956.7 $ — Abandonment and impairment of unproved properties 8.8 6.3 50.6 25.1 Total $ 8.8 $ 6.3 $ 1,007.3 $ 25.1 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, we recorded impairment expense related to our South Texas proved oil and gas properties and related support facilities during the nine months ended September 30, 2020. There were no proved oil and gas property impairments recorded during the same period in 2019. Unproved property abandonments and impairments recorded during the three and nine months ended September 30, 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 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 remain depressed or decline further 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. Given the uncertainties in commodity prices and the associated impacts they may have on service provider costs, we cannot predict with any reasonable certainty the likelihood or magnitude of further property impairments beyond those recorded during the nine months ended September 30, 2020. Please refer to Note 11 - 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 September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) General and administrative $ 24.5 $ 32.6 $ 79.1 $ 95.6 37 G&A expense decreased 25 percent and 17 percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. These decreases were primarily due to reduced overhead costs resulting from the reorganization that was announced in the fourth quarter of 2019, and actions taken to reduce costs as a result of the Pandemic. Please refer to the section A Three Month and Nine Month 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 September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Net derivative (gain) loss $ 63.9 $ (100.9) $ (314.3) $ (3.5) We recognized a derivative gain of $545.3 million in the first quarter of 2020, and derivative losses of $167.2 million and $63.9 million in the second and third quarters of 2020, respectively. The gain in the first quarter of 2020 was primarily driven by a $471.9 million upward mark-to-market adjustment due to weakening oil prices during the first three months of the year. The losses recognized in the second and third quarters of 2020 were driven by downward mark-to-market adjustments of $309.7 million and $134.2 million, respectively, due to strengthening commodity prices during these periods. Additionally, we recognized gains on the settlement of derivative contracts of $70.3 million and $286.3 million during the three and nine months ended September 30, 2020, respectively. We recognized a derivative loss of $177.1 million in the first quarter of 2019, and derivative gains of $79.7 million and $100.9 million in the second and third quarters of 2019, respectively. The loss in the first quarter of 2019 was primarily driven by a $172.1 million downward mark-to-market adjustment due to strengthening oil prices during the first three months of the year. The gains recognized in the second and third quarters of 2019 were driven by upward mark-to-market adjustments of $75.6 million and $76.2 million, respectively, due to weakening commodity prices during these periods. Additionally, we recognized gains on the settlement of derivative contracts of $24.7 million and $23.8 million during the three and nine months ended September 30, 2019, respectively. 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 September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Interest expense $ 41.5 $ 40.6 $ 123.4 $ 118.2 Interest expense increased two percent and four percent for the three and nine months ended September 30, 2020, respectively, compared with the same periods in 2019. The increase for the nine months ended September 30, 2020, was primarily due to an increase in interest expense associated with borrowings under our revolving credit facility and a decrease in interest expense capitalized to wells. We expect interest expense related to our Senior Notes to remain relatively flat for the remainder of 2020 compared with 2019 as the increase related to the higher interest rate on the 2025 Senior Secured Notes will be mostly offset by the decreased interest associated with the reduction in principal of Old Notes exchanged. 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. Gain on extinguishment of debt For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions) Gain on extinguishment of debt $ 25.1 $ — $ 264.5 $ — During the three months ended September 30, 2020, we recorded net gains on the early extinguishment of portions of our 2022 Senior Notes and 2024 Senior Notes of $12.2 million and $12.9 million, respectively. 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. During the first quarter of 2020, we recorded a $12.2 million net gain on the early extinguishment of a portion of our 2022 Senior Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion on these transactions. 38 Income tax (expense) benefit For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in millions, except tax rate) Income tax (expense) benefit $ 23.0 $ (16.1) $ 158.7 $ 16.3 Effective tax rate 18.9 % 27.6 % 20.9 % 16.1 % The decrease in the effective income tax benefit rate for the three months ended September 30, 2020, compared to the income tax expense rate during the same period in 2019, was primarily due to the differing effects permanent items have on the loss before income taxes compared to the income before income taxes for the three months ended September 30, 2020, and 2019, respectively. The increase in the effective tax rate for the nine months ended September 30, 2020, compared with the same period in 2019, was primarily due to the proportional effect of recording discrete excess tax deficiencies from share-based compensation awards and other permanent items on a larger pretax loss for the nine months ended September 30, 2020, compared to the same period in 2019. 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 achieve our operational objectives while continuing to meet our current financial obligations in a challenging commodity price environment. 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, and we have successfully renegotiated certain contracts and have realized cost savings that directly support our objective of maximizing cash flows. Sources of Cash We currently expect our 2020 capital program to be funded by cash flows from operations with any remaining cash needs being funded by borrowings under our revolving credit facility. During the nine months ended September 30, 2020, we generated $534.1 million of cash flows from operating activities. Although we expect cash flows from these sources to be sufficient to fund our expected 2020 capital program, we may also 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 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, and volumes produced, all of which affect us and our industry. As a result of the current macroeconomic environment, our credit ratings were downgraded during the first half of 2020 by three major rating agencies. These downgrades and any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. 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. Current or future macroeconomic events may negatively impact our ability to benefit from these contracts. 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. As of the filing of this report, the fall semi-annual borrowing base redetermination was in process. The next scheduled borrowing base redetermination date is April 1, 2021. As of September 30, 2020, the remaining available borrowing capacity under our Credit Agreement provided $880.0 million in liquidity; however, our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities. 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 October 21, 2020, September 30, 2020, and December 31, 2019. 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. The 39 financial covenants under the Credit Agreement require that our (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 4.00 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. We were in compliance with all financial and non-financial covenants as of September 30, 2020, and through the filing of this report. Please refer to the caption Non-GAAP Financial Measures below for our definition of adjusted EBITDAX and reconciliations of net income (loss) and net cash provided by operating activities to adjusted EBITDAX. Our daily weighted-average revolving credit facility debt balance was $200.1 million and $170.9 million for the three months ended September 30, 2020, and 2019, respectively, and $142.2 million and $97.5 million for the nine months ended September 30, 2020, and 2019, respectively. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities, 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 which provides 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 2025 Senior Secured Notes and 2021 Senior Secured Convertible Notes. Our weighted-average borrowing rate includes paid and accrued interest only. The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the three and nine months ended September 30, 2020, and 2019: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 Weighted-average interest rate 7.3 % 6.3 % 6.8 % 6.4 % Weighted-average borrowing rate 6.5 % 5.6 % 6.0 % 5.7 % 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 and nine months ended September 30, 2020, our weighted-average interest rate and our weighted-average borrowing rate increased, compared with the same periods in 2019, primarily as a result of the higher interest rate on our 2025 Senior Secured Notes issued during the second quarter of 2020. The rates disclosed in the above table do not reflect amounts associated with the early redemption of certain of our Old 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. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. 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 nine months ended September 30, 2020, we spent $426.9 million on capital expenditures and on acquiring proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $437.1 million for the nine months ended September 30, 2020, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, 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, 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 40 cash flows, acquisition and divestiture activities, debt requirements, and other factors. We entered 2020 with a total capital program budget between $825 million and $850 million. However, given the macroeconomic events discussed throughout this report, we currently expect to reduce our 2020 capital program by approximately 25 percent for the full year 2020. We are unable to reasonably estimate the period of time that these market conditions will exist, the extent of the impact they will have on our business, liquidity, results of operations, financial condition, or the timing of any subsequent recovery. 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 exchanges may be made in open market transactions, privately negotiated transactions, or otherwise. Any such repurchases or exchanges 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 nine months ended September 30, 2020, we repurchased $103.2 million of principal amount of our 2022 Senior Notes and $29.0 million of principal amount of our 2024 Senior Notes in open market transactions at a discount, resulting in net gains on extinguishment of debt of $24.4 million and $12.9 million, respectively. 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, as well as, in connection with the Private Exchange, (a) $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes, which was borrowed against our revolving credit facility, and (b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or approximately five percent of our outstanding common stock, exercisable upon the occurrence of certain future triggering events. The balance of our revolving credit facility increased $55.5 million from $122.5 million at December 31, 2019, to $178.0 million at September 30, 2020, notwithstanding the redemption of $185.7 million in aggregate principal amount of our Senior Unsecured Notes and 2021 Senior Convertible Notes for $147.8 million in cash during the nine months ended September 30, 2020. Please refer to Note 5 - Long-Term Debt and Note 11 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2020, we expect to continue to focus on improving our debt metrics, which could include further 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 nine months ended September 30, 2020, 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 2020. Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2020, and 2019 The following tables present changes in cash flows between the nine months ended September 30, 2020, and 2019, 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 Nine Months Ended September 30, Amount Change Between Periods 2020 2019 (in millions) Net cash provided by operating activities $ 534.1 $ 581.6 $ (47.5) Net cash provided by operating activities decreased for the nine months ended September 30, 2020, compared with the same period in 2019. Cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, decreased $215.9 million, cash paid for interest increased $9.1 million, and cash received from settled derivative trades increased $228.3 million. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements. Investing activities For the Nine Months Ended September 30, Amount Change Between Periods 2020 2019 (in millions) Net cash used in investing activities $ (426.8) $ (778.7) $ 351.9 41 Net cash used in investing activities decreased for the nine months ended September 30, 2020, compared with the same period in 2019, primarily due to reduced capital expenditures of $368.9 million. Net cash used in investing activities during the nine months ended September 30, 2020, was funded by net cash provided by operating activities. Financing activities For the Nine Months Ended September 30, Amount Change Between Periods 2020 2019 (in millions) Net cash provided by (used in) financing activities $ (107.3) $ 122.7 $ (230.0) For the nine months ended September 30, 2020, we paid $94.3 million to repurchase certain of our 2022 Senior Notes and 2024 Senior Notes in open market transactions. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. For the nine months ended September 30, 2019, we had net borrowings under our revolving credit facility of $129.0 million used to fund capital expenditures. 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 September 30, 2020, we had a $178.0 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 September 30, 2020, our outstanding principal amount of fixed-rate debt totaled $2.2 billion and our floating-rate debt outstanding totaled $178.0 million. Please refer to Note 11 - 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, all of which are typically beyond our control. The markets for oil, gas, and NGLs have been volatile, especially over the last several months and years. During the first half of 2020, oil, gas, and NGL prices weakened to historic lows as a result of the Pandemic and other macroeconomic events and will likely continue to be volatile in the future. 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 nine months ended September 30, 2020, 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 $61.9 million, $12.5 million, and $6.2 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2020, would have offset the declines in oil, gas, and NGL production revenue by approximately $59.2 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 September 30, 2020, 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 $117.7 million, $26.2 million, and $1.8 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 nine months ended September 30, 2020, or through the filing of this report. 42 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 2019 Form 10-K for discussion of our accounting policies and estimates. New Accounting Pronouncements Please refer to Note 1 - Summary of Significant Accounting Policies under Part I, Item 1 of this report for new accounting pronouncements. 43 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 the Credit Agreement section in Overview of Liquidity and Capital Resources above. 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 income (loss) (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented: For the Three Months Ended September 30, For the Nine Months Ended September 30, 2020 2019 2020 2019 (in thousands) Net income (loss) (GAAP) $ (98,292) $ 42,234 $ (599,439) $ (84,946) Interest expense 41,519 40,584 123,385 118,191 Income tax expense (benefit) (22,969) 16,111 (158,662) (16,337) Depletion, depreciation, amortization, and asset retirement obligation liability accretion 181,708 211,125 596,053 595,201 Exploration (1) 7,882 10,341 26,970 30,070 Impairment 8,750 6,337 1,007,263 25,092 Stock-based compensation expense 4,164 6,766 15,437 18,758 Net derivative (gain) loss 63,871 (100,889) (314,269) (3,463) Derivative settlement gain 70,305 24,722 286,270 23,843 Net gain on divestiture activity — — (91) (323) Gain on extinguishment of debt (25,070) — (264,546) — Other, net 615 434 1,651 1,129 Adjusted EBITDAX (non-GAAP) 232,483 257,765 720,022 707,215 Interest expense (41,519) (40,584) (123,385) (118,191) Income tax (expense) benefit 22,969 (16,111) 158,662 16,337 Exploration (1) (7,882) (10,341) (26,970) (30,070) Amortization of debt discount and deferred financing costs 4,506 3,921 13,084 11,554 Deferred income taxes (22,796) 19,617 (159,064) (13,620) Other, net (2,991) (1,438) (7,854) (3,420) Net change in working capital 16,843 (9,673) (40,411) 11,781 Net cash provided by operating activities (GAAP) $ 201,613 $ 203,156 $ 534,084 $ 581,586 ____________________________________________ (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. 44