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 the financial information presented in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2023 , filed with the SEC on August 3, 2023. Throughout the following discussion, we explain changes between the three months ended September 30, 2023, and the three months ended June 30, 2023 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2023, and the nine months ended September 30, 2022 (“YTD 2023-over-YTD 2022”). 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 long-term vision is to sustainably grow value for all of our stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our strategy is to be a premier operator of top-tier oil and gas assets. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include returning value to stockholders through our Stock Repurchase Program and fixed dividend payments, and focusing on continued operational excellence. Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We remain focused on maximizing returns and increasing the value of our top-tier assets through disciplined capital spending, strategic acreage acquisitions, and continued development and optimization of our existing assets. We believe that our high-quality asset base provides for a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining strong financial flexibility. We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with 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 ESG policies, programs, and initiatives, and together with management reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based metrics that include key financial, operational, environmental, health, and safety measures. We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. While the United States inflation rate has decreased since the beginning of the year and the average rate of inflation in 2023 is lower than it was in 2022, inflation continues to impact certain aspects of our business. Tightening of monetary policy by the United States Federal Reserve, declining global oil inventory in storage, continued oil production curtailment agreements among the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”), instability in the Middle East, and economic and trade sanctions associated with the war between Russia and Ukraine have driven commodity price volatility, contributed to instances of supply chain disruptions and a rise in interest rates, and could have further industry-specific impacts that 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 2022 Form 10-K . Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on returning capital to stockholders through cash flow generation. Areas of Operations Our Midland Basin assets are comprised of approximately 110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the third quarter of 2023, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization of our Midland Basin position. Our 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 Dimmit and Webb Counties, Texas (“South Texas”). In the third quarter of 2023, we focused our operations in South Texas on production from both the Austin Chalk formation and Eagle Ford shale formation, development of the Eagle Ford shale formation, and development and further delineation of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. 22 Third Quarter 2023 Overview and Outlook for the Remainder of 2023 During the third quarter of 2023, we continued to execute on our goal of sustainably returning capital to our stockholders through our Stock Repurchase Program and fixed quarterly dividend by repurchasing and subsequently retiring approximately 2.4 million shares of our outstanding common stock at a cost of $96.3 million, excluding excise taxes, commissions, and fees, and paying quarterly dividends of $0.15 per share totaling $17.8 million. In September 2023, we declared a quarterly cash dividend of $0.15 per share of common stock outstanding to be paid on November 6, 2023. Additionally, our Board of Directors approved an increase to our fixed dividend policy, pursuant to which we intend to pay $0.18 per share per quarter, beginning in the first quarter of 2024. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion of our Stock Repurchase Program. We expect our total 2023 capital program, excluding acquisitions and certain leasing efforts, to be approximately $1.1 billion. This reflects an increase from our previous expectation for capital expenditures related to additional working interests acquired in certain wells in the Midland Basin during the third quarter of 2023. Our capital program remains focused on our highly economic oil development projects in both our Midland Basin and South Texas assets. During 2023, we expect to repeat our track record of inventory replacement and growth, and to continue applying our strength in geosciences and development optimization. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2023 capital program. Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2023, remained flat sequentially at 153.7 MBOE, as a six percent increase from our Midland Basin assets was offset by a six percent decrease from our South Texas assets. These changes were a result of the timing of well completions. Oil, gas, and NGL realized prices, before the effect of derivative settlements (“realized price” or “realized prices”), increased sequentially by 12 percent, 20 percent, and 13 percent, respectively, as a result of increases in benchmark commodity prices during the third quarter of 2023. Total realized price per BOE increased 16 percent sequentially, resulting in a 17 percent increase in oil, gas, and NGL production revenue, which was $639.7 million for the three months ended September 30, 2023, compared with $546.6 million for the three months ended June 30, 2023. Oil, gas, and NGL production expense of $9.78 per BOE for the three months ended September 30, 2023, decreased six percent sequentially, primarily as a result of a decrease in transportation costs per BOE partially offset by an increase in production tax expense per BOE. We recorded a net derivative loss of $75.4 million and a net derivative gain of $11.7 million for the three months ended September 30, 2023, and June 30, 2023, respectively. Included within these amounts is a derivative settlement loss of $0.3 million for the three months ended September 30, 2023, and a derivative settlement gain of $15.6 million for the three months ended June 30, 2023. Operational and financial activities during the three months ended September 30, 2023, resulted in the following: • Net cash provided by operating activities of $383.0 million, compared with $383.3 million for the three months ended June 30, 2023. • Net income of $222.3 million, or $1.88 per diluted share, compared with net income of $149.9 million, or $1.25 per diluted share, for the three months ended June 30, 2023. • Adjusted EBITDAX, a non-GAAP financial measure, of $475.6 million, compared with $390.2 million for the three months ended June 30, 2023. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities. Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2023, and June 30, 2023, and Between the Nine Months Ended September 30, 2023, and 2022 below for additional discussion. Operational Activities. In our Midland Basin program, we operated three drilling rigs and one completion crew, drilled 19 gross (11 net) wells, completed 20 gross (17 net) wells, and acquired five net wells during the third quarter of 2023. Average net daily equivalent production volumes increased sequentially by six percent to 77.4 MBOE. Costs incurred in our Midland Basin program during the three months ended September 30, 2023, totaled $161.3 million, or 62 percent of our total costs incurred for the period. During the remainder of 2023, we expect our activity to focus on developing formations within our RockStar and Sweetie Peck positions, and on developing our recently acquired acreage. We added a fourth drilling rig at the end of the third quarter of 2023 and we anticipate operating four drilling rigs for the remainder of 2023. Subsequent to September 30, 2023, we added a second completion crew and we anticipate operating between one and two completion crews for the remainder of 2023. In our South Texas program, we operated two drilling rigs and one completion crew for a portion of the quarter, drilled 13 gross (13 net) wells, and completed 13 gross (13 net) wells during the third quarter of 2023. Average net daily equivalent production volumes decreased sequentially by six percent to 76.3 MBOE. Costs incurred in our South Texas program during the three months ended September 30, 2023, totaled $90.7 million, or 35 percent of our total costs incurred for the period. We anticipate operating two drilling 23 rigs for the remainder of 2023 and one completion crew for a majority of the remainder of 2023, focused primarily on 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 nine months ended September 30, 2023: Midland Basin South Texas (1) Total Gross Net Gross Net Gross Net Wells drilled but not completed at December 31, 2022 49 40 29 28 78 69 Wells drilled 8 7 7 7 15 14 Wells completed (12) (10) (17) (16) (29) (26) Wells drilled but not completed at March 31, 2023 45 37 19 19 64 56 Wells drilled 11 5 12 12 23 17 Wells completed (20) (16) (8) (8) (28) (24) Wells drilled but not completed at June 30, 2023 36 27 23 23 59 50 Wells drilled 19 11 13 13 32 24 Wells completed (20) (17) (13) (13) (33) (30) Wells acquired (2) — 5 — — — 5 Wells drilled but not completed at September 30, 2023 35 25 23 23 58 48 ____________________________________________ Note: Amounts may not calculate due to rounding. (1) The South Texas drilled but not completed well count as of December 31, 2022, included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2022, eight of which were in the Eagle Ford shale formation. (2) Amount relates to additional working interests acquired during the three months ended September 30, 2023, on wells drilled during the first half of 2023, that were not completed as of September 30, 2023. Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $260.6 million and $943.2 million for the three and nine months ended September 30, 2023, respectively, and were primarily incurred in our Midland Basin and South Texas programs as discussed in Operational Activities above. Of our total costs incurred for the three and nine months ended September 30, 2023, $20.6 million and $111.9 million, respectively, related to proved and unproved property acquisitions in the Midland Basin, including the acquisition of additional working interests in certain wells. 24 Production Results. The table below presents our production by product type for each of our assets for the periods presented: For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 Midland Basin Production: Oil (MMBbl) 4.5 4.2 13.0 14.7 Gas (Bcf) 15.4 14.8 44.6 47.5 NGLs (MMBbl) — — — — Equivalent (MMBOE) 7.1 6.6 20.4 22.6 Average net daily equivalent (MBOE per day) 77.4 73.0 74.8 82.9 Relative percentage 50 % 47 % 49 % 57 % South Texas Production: Oil (MMBbl) 1.6 1.7 4.7 3.6 Gas (Bcf) 17.5 18.9 54.2 46.3 NGLs (MMBbl) 2.5 2.6 7.2 5.9 Equivalent (MMBOE) 7.0 7.4 21.0 17.2 Average net daily equivalent (MBOE per day) 76.3 81.4 76.7 63.0 Relative percentage 50 % 53 % 51 % 43 % Total Production: Oil (MMBbl) 6.2 5.9 17.7 18.3 Gas (Bcf) 32.9 33.7 98.9 93.8 NGLs (MMBbl) 2.5 2.6 7.2 5.9 Equivalent (MMBOE) 14.1 14.1 41.4 39.8 Average net daily equivalent (MBOE per day) 153.7 154.4 151.5 145.8 ____________________________________________ 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 September 30, 2023, and June 30, 2023, and Between the Nine Months Ended September 30, 2023, and 2022 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 effect of derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products. 25 The following table summarizes commodity price data, as well as the effect of derivative settlements, for the three months ended September 30, 2023, June 30, 2023, and September 30, 2022: For the Three Months Ended September 30, 2023 June 30, 2023 September 30, 2022 Oil (per Bbl): Average NYMEX contract monthly price $ 82.26 $ 73.78 $ 91.56 Realized price $ 80.95 $ 72.12 $ 92.66 Effect of oil derivative settlements $ (2.18) $ (0.08) $ (21.22) Gas: Average NYMEX monthly settle price (per MMBtu) $ 2.55 $ 2.10 $ 8.20 Realized price (per Mcf) $ 2.48 $ 2.07 $ 7.58 Effect of gas derivative settlements (per Mcf) $ 0.35 $ 0.43 $ (2.00) NGLs (per Bbl): Average OPIS price (1) $ 27.81 $ 25.21 $ 42.47 Realized price $ 23.61 $ 20.83 $ 36.36 Effect of NGL derivative settlements $ 0.60 $ 0.61 $ (2.11) ____________________________________________ (1) Effective January 1, 2023, average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix. Given the uncertainty surrounding global financial markets, production output from OPEC+, instability in the Middle East, economic and trade sanctions associated with the war between Russia and Ukraine, and the potential impacts of these issues on global commodity markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include further inflation, supply chain disruptions, a continued rise in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are 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 or outages in the areas of our operations and beyond. The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 26, 2023, and September 30, 2023: As of October 26, 2023 As of September 30, 2023 NYMEX WTI oil (per Bbl) $ 80.49 $ 84.26 NYMEX Henry Hub gas (per MMBtu) $ 3.38 $ 3.20 OPIS NGLs (per Bbl) $ 26.71 $ 28.32 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 the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Please refer to Note 7 - 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. 26 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, 2023, and the preceding three quarters: For the Three Months Ended September 30, June 30, March 31, December 31, 2023 2023 2023 2022 (in millions) Production (MMBOE) 14.1 14.1 13.2 13.1 Oil, gas, and NGL production revenue $ 639.7 $ 546.6 $ 570.8 $ 669.3 Oil, gas, and NGL production expense $ 138.3 $ 145.6 $ 142.3 $ 150.7 Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 189.4 $ 157.8 $ 154.2 $ 143.6 Exploration $ 10.2 $ 15.0 $ 18.4 $ 10.8 General and administrative $ 29.3 $ 27.5 $ 27.7 $ 32.8 Net income $ 222.3 $ 149.9 $ 198.6 $ 258.5 Selected Performance Metrics For the Three Months Ended September 30, June 30, March 31, December 31, 2023 2023 2023 2022 Average net daily equivalent production (MBOE per day) 153.7 154.4 146.4 142.9 Lease operating expense (per BOE) $ 5.08 $ 4.98 $ 5.16 $ 5.20 Transportation costs (per BOE) $ 2.07 $ 2.89 $ 2.81 $ 2.86 Production taxes as a percent of oil, gas, and NGL production revenue 4.3 % 4.3 % 4.7 % 4.8 % Ad valorem tax expense (per BOE) $ 0.70 $ 0.83 $ 0.81 $ 0.97 Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) $ 13.39 $ 11.23 $ 11.70 $ 10.93 General and administrative (per BOE) $ 2.07 $ 1.96 $ 2.10 $ 2.50 ____________________________________________ Note: Amounts may not calculate due to rounding. 27 Overview of Selected Production and Financial Information, Including Trends For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Nine Months Ended Amount Change Between Periods Percent Change Between Periods September 30, June 30, September 30, September 30, 2023 2023 2023 2022 Net production volumes: (1) Oil (MMBbl) 6.2 5.9 0.3 5 % 17.7 18.3 (0.6) (3) % Gas (Bcf) 32.9 33.7 (0.8) (2) % 98.9 93.8 5.0 5 % NGLs (MMBbl) 2.5 2.6 (0.1) (3) % 7.2 5.9 1.3 22 % Equivalent (MMBOE) 14.1 14.1 0.1 1 % 41.4 39.8 1.6 4 % Average net daily production: (1) Oil (MBbl per day) 67.0 64.5 2.5 4 % 64.8 66.9 (2.1) (3) % Gas (MMcf per day) 357.9 370.4 (12.5) (3) % 362.2 343.7 18.5 5 % NGLs (MBbl per day) 27.0 28.2 (1.2) (4) % 26.3 21.6 4.7 22 % Equivalent (MBOE per day) 153.7 154.4 (0.7) — % 151.5 145.8 5.7 4 % Oil, gas, and NGL production revenue (in millions): (1) Oil production revenue $ 499.2 $ 423.4 $ 75.8 18 % $ 1,343.5 $ 1,800.3 $ (456.8) (25) % Gas production revenue 81.8 69.7 12.1 17 % 245.3 645.9 (400.7) (62) % NGL production revenue 58.7 53.4 5.2 10 % 168.3 230.5 (62.2) (27) % Total oil, gas, and NGL production revenue $ 639.7 $ 546.6 $ 93.1 17 % $ 1,757.0 $ 2,676.7 $ (919.6) (34) % Oil, gas, and NGL production expense (in millions): (1) Lease operating expense $ 71.9 $ 69.9 $ 2.0 3 % $ 209.9 $ 198.2 $ 11.7 6 % Transportation costs 29.2 40.6 (11.4) (28) % 106.9 112.4 (5.5) (5) % Production taxes 27.3 23.4 3.9 17 % 77.4 130.7 (53.3) (41) % Ad valorem tax expense 9.8 11.6 (1.8) (16) % 32.1 29.0 3.1 11 % Total oil, gas, and NGL production expense $ 138.3 $ 145.6 $ (7.3) (5) % $ 426.2 $ 470.2 $ (44.0) (9) % Realized price: Oil (per Bbl) $ 80.95 $ 72.12 $ 8.83 12 % $ 75.90 $ 98.52 $ (22.62) (23) % Gas (per Mcf) $ 2.48 $ 2.07 $ 0.41 20 % $ 2.48 $ 6.88 $ (4.40) (64) % NGLs (per Bbl) $ 23.61 $ 20.83 $ 2.78 13 % $ 23.40 $ 39.04 $ (15.64) (40) % Per BOE $ 45.24 $ 38.89 $ 6.35 16 % $ 42.47 $ 67.23 $ (24.76) (37) % Per BOE data: (1) Oil, gas, and NGL production expense: Lease operating expense $ 5.08 $ 4.98 $ 0.10 2 % $ 5.07 $ 4.98 $ 0.09 2 % Transportation costs 2.07 2.89 (0.82) (28) % 2.58 2.82 (0.24) (9) % Production taxes 1.93 1.66 0.27 16 % 1.87 3.28 (1.41) (43) % Ad valorem tax expense 0.70 0.83 (0.13) (16) % 0.78 0.73 0.05 7 % Total oil, gas, and NGL production expense (1) $ 9.78 $ 10.36 $ (0.58) (6) % $ 10.30 $ 11.81 $ (1.51) (13) % Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 13.39 $ 11.23 $ 2.16 19 % $ 12.12 $ 11.56 $ 0.56 5 % General and administrative $ 2.07 $ 1.96 $ 0.11 6 % $ 2.04 $ 2.05 $ (0.01) — % Derivative settlement gain (loss) (2) $ (0.02) $ 1.11 $ (1.13) (102) % $ 0.49 $ (14.95) $ 15.44 103 % Earnings per share information (in thousands, except per share data): (3) Basic weighted-average common shares outstanding 117,823 119,408 (1,585) (1) % 119,589 122,318 (2,729) (2) % Diluted weighted-average common shares outstanding 118,328 120,074 (1,746) (1) % 120,165 124,233 (4,068) (3) % Basic net income per common share $ 1.89 $ 1.26 $ 0.63 50 % $ 4.77 $ 6.98 $ (2.21) (32) % Diluted net income per common share $ 1.88 $ 1.25 $ 0.63 50 % $ 4.75 $ 6.87 $ (2.12) (31) % 28 ______________________________________ (1) Amounts and percentage changes may not calculate due to rounding. (2) Derivative settlements for the three months ended September 30, 2023, and for the nine months ended September 30, 2023, and 2022, 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 September 30, 2023, remained flat sequentially as a six percent increase from our Midland Basin assets was offset by a six percent decrease from our South Texas assets, resulting from the timing of well completions. Average net daily equivalent production increased four percent YTD 2023-over-YTD 2022 as a result of an increase in well completions. The total YTD 2023-over-YTD 2022 increase in average net daily equivalent production consisted of a 22 percent increase from our South Texas assets partially offset by a 10 percent decrease from our Midland Basin assets, resulting from the timing of well completions, and the timing of capital expenditures during 2022 and 2023. We expect a slight increase in total net equivalent production for the full-year 2023, compared with 2022, primarily driven by an increase in well completions and increased production from our South Texas assets as we benefit from reduced production curtailments attributable to the build-out of South Texas oil handling capacity. We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion. Our realized price on a per BOE basis increased $6.35 sequentially as a result of increases in oil, gas, and NGL benchmark prices. For the three months ended September 30, 2023, we recognized a loss on the settlement of our commodity derivative contracts of $0.02 per BOE, compared to a gain on the settlement of our commodity derivative contracts of $1.11 per BOE for the three months ended June 30, 2023. Our realized price on a per BOE basis decreased $24.76 YTD 2023-over-YTD 2022 as a result of decreases in oil, gas, and NGL benchmark prices. For the nine months ended September 30, 2023, we recognized a gain on the settlement of our commodity derivative contracts of $0.49 per BOE, compared to a loss of $14.95 per BOE for the same period in 2022. LOE on a per BOE basis increased two percent both sequentially and YTD 2023-over-YTD 2022. The sequential quarterly increase was a result of a shift in our production mix from our South Texas assets to our Midland Basin assets, which have higher unit operating costs, partially offset by a decrease in workover expense. The YTD 2023-over-YTD 2022 increase was a result of increased workover activity and increases in labor costs, both of which we expect will lead to an increase in LOE on a per BOE basis for the full-year 2023, compared with 2022. 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 affect total LOE. Transportation costs on a per BOE basis decreased 28 percent sequentially and decreased nine percent YTD 2023-over-YTD 2022 as a result of the expiration of a long-term contract in South Texas on June 30, 2023. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For the full-year 2023, we expect transportation costs on a per BOE basis to decrease compared with 2022, as a result of the expiration of the long-term contract discussed above. Production tax expense on a per BOE basis increased 16 percent sequentially as a result of increases in realized prices, and decreased 43 percent YTD 2023-over-YTD 2022, as a result of decreases in realized prices. Our overall production tax rate for the three and nine months ended September 30, 2023, was 4.3 percent and 4.4 percent, respectively, compared with 4.3 percent for the three months ended June 30, 2023, and 4.9 percent for the nine months ended September 30, 2022. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize. Ad valorem tax expense on a per BOE basis decreased 16 percent sequentially and increased seven percent YTD 2023-over-YTD 2022 as a result of changes to the assessed values of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes, which is generally driven by fluctuations in commodity prices. Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased 19 percent sequentially due to inflation, and an increase in production from our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. DD&A expense on a per BOE basis increased five percent YTD 2023-over-YTD 2022 due to inflation, partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties. We expect DD&A expense per BOE and on an absolute basis to increase in 2023, compared with 2022, primarily as a result of cost increases, partially offset by a shift in production mix to our South Texas assets. General and administrative (“G&A”) expense on a per BOE basis increased six percent sequentially primarily as a result of increased compensation expense. G&A expense on a per BOE basis remained flat YTD 2023-over-YTD 2022. We currently expect G&A expense to remain relatively flat per BOE and on an absolute basis for the full-year 2023 compared with 2022. 29 Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2023, and June 30, 2023, and Between the Nine Months Ended September 30, 2023, and 2022 below for additional discussion of operating expenses. Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2023, and June 30, 2023, and Between the Nine Months Ended September 30, 2023, and 2022 Average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense Sequential Quarterly Changes. The following table presents changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the three months ended September 30, 2023, and June 30, 2023: Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL Production Revenue Increase Oil, Gas, and NGL Production Expense Increase (Decrease) (MBOE per day) (in millions) (in millions) Midland Basin 4.4 $ 75.4 $ 6.6 South Texas (5.1) 17.8 (13.9) Total (0.7) $ 93.1 $ (7.3) __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes remained flat, as a six percent increase from our Midland Basin assets was offset by a six percent decrease from our South Texas assets. As a result of increases in benchmark commodity prices, realized prices for oil, gas, and NGLs increased 12 percent, 20 percent, and 13 percent, respectively, resulting in a 17 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense decreased five percent, primarily driven by a decrease in transportation costs, partially offset by an increase in production tax expense. YTD 2023-over-YTD 2022 Changes. The following table presents changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the nine months ended September 30, 2023, and 2022: Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL Production Revenue Decrease Oil, Gas, and NGL Production Expense Decrease (MBOE per day) (in millions) (in millions) Midland Basin (8.1) $ (688.8) $ (39.9) South Texas 13.8 (230.9) (4.1) Total 5.7 $ (919.6) $ (44.0) __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes increased four percent, consisting of a 22 percent increase from our South Texas assets, partially offset by a 10 percent decrease from our Midland Basin assets. As a result of decreases in benchmark commodity prices, realized prices for oil, gas, and NGLs decreased 23 percent, 64 percent, and 40 percent, respectively. These decreases were partially offset by increased average net daily equivalent production resulting in a 34 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense decreased nine percent, primarily driven by decreases in production tax expense and transportation costs, partially offset by increases in LOE and ad valorem tax expense. 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. Depletion, depreciation, amortization, and asset retirement obligation liability accretion For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 189.4 $ 157.8 $ 501.4 $ 460.2 30 DD&A expense increased 20 percent sequentially and increased nine percent YTD 2023-over-YTD 2022. The sequential quarterly increase primarily resulted from inflation and an increase in production from our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. The YTD 2023-over-YTD 2022 increase resulted from a combination of inflation and a four percent increase in average net daily equivalent production. These increases were partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis. Exploration For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) Geological, geophysical, and other expenses $ 2.7 $ 7.4 $ 20.7 $ 21.8 Overhead 7.5 7.6 22.9 22.3 Total $ 10.2 $ 15.0 $ 43.6 $ 44.1 Exploration expense decreased 32 percent sequentially primarily due to a decrease in geological and geophysical expense. Exploration expense remained flat YTD 2023-over-YTD 2022. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead. General and administrative For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) General and administrative $ 29.3 $ 27.5 $ 84.4 $ 81.7 G&A expense increased six percent sequentially and increased three percent YTD 2023-over-YTD 2022, primarily as a result of increased compensation expense. We currently expect G&A expense to remain relatively flat on an absolute basis for the full-year 2023 compared with 2022, but G&A expense can be impacted by full-year financial and operational results. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense on a per BOE basis. Net derivative (gain) loss For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) Net derivative (gain) loss $ 75.4 $ (11.7) $ 12.4 $ 385.2 Net derivative (gain) loss is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. Compared to our derivative contract prices, we expect increases in benchmark commodity prices to result in net derivative losses, and decreases in benchmark commodity prices to result in net derivative gains. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion. Interest expense For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) Interest expense $ (23.1) $ (22.1) $ (67.7) $ (97.7) 31 Interest expense increased four percent sequentially and decreased 31 percent YTD 2023-over-YTD 2022. The sequential quarterly increase was primarily driven by a decrease in capitalized interest as a result of the timing of the development of our wells in progress. The YTD 2023-over-YTD 2022 decrease was a result of the reduction in the aggregate principal amount of our Senior Notes through various transactions in 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the redemption of our 2025 Senior Secured Notes on June 17, 2022. As a result of these transactions, we expect interest expense to decrease for the full-year 2023, compared with 2022. Additionally, total interest expense 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. Loss on extinguishment of debt For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions) Loss on extinguishment of debt $ — $ — $ — $ (67.6) The redemption of our 2025 Senior Secured Notes on June 17, 2022, resulted in a net loss on extinguishment of debt of $67.2 million for the nine months ended September 30, 2022, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the remaining unamortized debt discount, and $7.4 million of accelerated expense recognition of the remaining unamortized deferred financing costs. Income tax (expense) benefit For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 (in millions, except tax rate) Income tax (expense) benefit $ 46.0 $ (42.1) $ (51.6) $ (219.0) Effective tax rate (26.1) % 21.9 % 8.3 % 20.4 % Our effective tax rate decreased both sequentially and YTD 2023-over-YTD 2022 primarily due to benefits recognized from the result of the multi-year R&D credit study completed during the third quarter of 2023, which were partially offset by a release of the valuation allowance during the nine months ended September 30, 2022, that lowered the effective tax rate compared to no valuation benefit recognized during the nine months ended September 30, 2023. The tax rates for each period presented also reflect the proportional effects of state income taxes, limits on expensing of certain covered individual’s compensation, and the cumulative effect of other small differences. Based on current projections, we estimate that after utilization of a portion of the R&D credits, between $10.0 million and $15.0 million of full-year 2023 income tax expense will be current. We made $6.2 million of cash tax payments during the nine months ended September 30, 2023, primarily related to Texas franchise taxes. 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 effect on our effective tax rate and current tax expense. Please refer to the Risk Factors section in Part 1, Item 1A of our 2022 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 For the nine months ended September 30, 2023, we funded our capital expenditures, return of capital program, and asset acquisitions with cash flows from operating activities and cash on hand, and we expect that to continue for the remainder of 2023. However, we may also use borrowings under our revolving credit facility or raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage 32 ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit rating during 2023, citing our ability to consistently generate meaningful cash flows, disciplined capital spending, return of capital to stockholders, debt redemptions during 2022, and sustained strong operational performance, including our established inventory of drilling locations in our primary plays, all of which contribute to our strong liquidity profile. 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, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry. 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 commodity 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 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our commodity 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 $3.0 billion. As of September 30, 2023, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, which considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. Subsequent to September 30, 2023, the semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at existing amounts. The next scheduled borrowing base redetermination date is April 1, 2024. No individual bank participating in the Credit Agreement represents more than 10 percent of the aggregate lender commitment. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of September 30, 2023, 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, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of October 26, 2023, September 30, 2023, and December 31, 2022. We had no revolving credit facility borrowings during the nine months ended September 30, 2023, and 2022. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility. Weighted-Average Interest and Weighted-Average Borrowing Rates Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate commitment amount under the Credit Agreement, letter of credit fees, the non-cash amortization of deferred financing costs, and for the periods during which the 2025 Senior Secured Notes were outstanding, the non-cash amortization of the related discount. 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 periods presented: For the Three Months Ended For the Nine Months Ended September 30, 2023 June 30, 2023 September 30, 2023 September 30, 2022 Weighted-average interest rate 7.0 % 7.1 % 7.1 % 7.8 % Weighted-average borrowing rate 6.4 % 6.4 % 6.4 % 7.0 % Our weighted-average interest rate and our weighted-average borrowing rate each remained flat sequentially, and decreased YTD 2023-over-YTD 2022, primarily due to the redemption of our 2024 Senior Notes and 2025 Senior Secured Notes during 2022. As a result of these redemptions, we expect our weighted-average interest rate and weighted-average borrowing rate to decrease for the full-year 2023 compared with 2022. Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rates are affected by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration 33 of unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2024 Senior Notes were redeemed on February 14, 2022, and the 2025 Senior Secured Notes were redeemed on June 17, 2022. After these dates, the weighted-average interest rate was no longer affected by the non-cash amortization of deferred financing costs or, for the 2025 Senior Secured Notes, the non-cash amortization of the discount. Uses of Cash We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, dividends, debt obligations, including interest and early repayments or redemptions; and for repurchases of shares of our common stock under the Stock Repurchase Program. 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, 2023, we spent $876.1 million on capital expenditures and on acquisitions of proved and unproved oil and gas properties, including the acquisition of additional working interests in certain wells. This amount differs from the costs incurred amount of $943.2 million for the nine months ended September 30, 2023, 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, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory 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 total 2023 capital program, which we expect to fund with cash flows from operations, is expected to be approximately $1.1 billion and excludes acquisitions and certain leasing efforts. This amount reflects an increase from our previous expectation for capital expenditures related to additional working interests acquired in certain wells in the Midland Basin during the third quarter of 2023. We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. During the nine months ended September 30, 2023, and 2022, we repurchased and subsequently retired 6.3 million and 0.5 million shares, respectively, of our common stock at a cost of $205.1 million and $20.2 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2023, $237.7 million remained available under the Stock Repurchase Program for repurchases of our common stock. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion. On February 14, 2022, we redeemed all of the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes, and on June 17, 2022, we redeemed all of the $446.7 million of aggregate principal amount outstanding of our 2025 Senior Secured Notes. All redeemed 2024 Senior Notes and 2025 Senior Secured Notes were canceled upon settlement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. During the nine months ended September 30, 2023, and 2022, we paid $54.2 million and $1.2 million, respectively, in dividends to our stockholders. In September 2023, we declared a quarterly cash dividend of $0.15 per share of common stock outstanding to be paid on November 6, 2023. Additionally, our Board of Directors approved an increase to our quarterly fixed dividend policy, pursuant to which we intend to pay $0.18 per share per quarter, beginning in the first quarter of 2024. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remains at the discretion of our Board of Directors. Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2023, and 2022 The following tables present changes in cash flows between the nine months ended September 30, 2023, and 2022, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report. 34 Operating activities For the Nine Months Ended September 30, Amount Change Between Periods 2023 2022 (in millions) Net cash provided by operating activities $ 1,097.9 $ 1,398.0 $ (300.1) Net cash provided by operating activities decreased for the nine months ended September 30, 2023, compared with the same period in 2022, primarily as a result of an $893.4 million decrease in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $44.3 million in cash paid for LOE and ad valorem taxes, partially offset by a $626.7 million decrease in cash paid on settled derivative trades and a $45.9 million decrease in cash paid for interest. 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 2023 2022 (in millions) Net cash used in investing activities $ (875.4) $ (592.4) $ (283.0) Net cash used in investing activities increased for the nine months ended September 30, 2023, compared with the same period in 2022, as a result of a $174.9 million increase in capital expenditures and $109.3 million of cash paid to acquire proved and unproved oil and gas properties in the Midland Basin, including the acquisition of additional working interests in certain wells. Please refer to Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion of acquisition of proved and unproved oil and gas properties. Financing activities For the Nine Months Ended September 30, Amount Change Between Periods 2023 2022 (in millions) Net cash used in financing activities $ (265.5) $ (639.9) $ 374.4 Net cash used in financing activities for the nine months ended September 30, 2023, primarily related to $205.2 million of cash paid, including commissions and fees, to repurchase and subsequently retire 6.3 million shares of our common stock under the Stock Repurchase Program and $54.2 million of dividends paid. Net cash used in financing activities for the nine months ended September 30, 2022, related to $480.2 million of cash paid, including premium, to redeem our 2025 Senior Secured Notes, and $104.8 million of cash paid to redeem our 2024 Senior Notes. Additionally, we paid $25.1 million for the net share settlement of employee stock awards and $20.2 million, including commissions and fees, to repurchase and subsequently retire 0.5 million shares of our common stock under the Stock Repurchase Program. Interest Rate Risk We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect 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 affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of September 30, 2023, our outstanding principal amount of fixed-rate debt totaled $1.6 billion, and we had no floating-rate debt outstanding. 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. The Federal Reserve has continued to increase short-term interest rates in 2023. These increases, and any future increases, are likely to increase the cost of and affect our ability to borrow funds. 35 Commodity Price Risk The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to execute our Stock Repurchase Program and pay dividends, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility related to production output from OPEC+, instability in the Middle East, economic and trade sanctions associated with the war between Russia and Ukraine, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and a rise in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. 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, 2023, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $134.3 million, $24.5 million, and $16.8 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2023, would have offset the declines in oil, gas, and NGL production revenue by approximately $43.7 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, 2023, 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 $48.0 million, $8.2 million, and $0.6 million, respectively. Off-Balance Sheet Arrangements We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), 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, 2023, or through the filing of this report. Critical Accounting 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 2022 Form 10-K for discussion of our accounting estimates. Accounting Matters Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance. 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 2022 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 36 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 (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented: For the Three Months Ended For the Nine Months Ended September 30, 2023 September 30, 2022 September 30, 2023 September 30, 2022 (in thousands) Net income (GAAP) $ 222,343 $ 481,240 $ 570,769 $ 853,489 Interest expense 23,106 22,825 67,713 97,708 Interest income (4,106) (1,546) (13,802) (2,080) Income tax expense (benefit) (45,979) 119,379 51,619 218,951 Depletion, depreciation, amortization, and asset retirement obligation liability accretion 189,353 145,865 501,374 460,169 Exploration (1) 9,071 13,203 40,612 41,152 Stock-based compensation expense 6,038 5,105 14,519 13,858 Net derivative (gain) loss 75,355 (137,577) 12,352 385,180 Derivative settlement gain (loss) (314) (186,299) 20,398 (595,080) Loss on extinguishment of debt — — — 67,605 Other, net 698 (2,040) 1,625 3,482 Adjusted EBITDAX (non-GAAP) 475,565 460,155 1,267,179 1,544,434 Interest expense (23,106) (22,825) (67,713) (97,708) Interest income 4,106 1,546 13,802 2,080 Income tax (expense) benefit 45,979 (119,379) (51,619) (218,951) Exploration (1) (2) (8,912) (11,993) (31,566) (27,959) Amortization of debt discount and deferred financing costs 1,371 1,303 4,114 8,910 Deferred income taxes (51,075) 110,048 43,171 202,996 Other, net (8,041) (2,003) (22,160) (2,541) Net change in working capital (52,893) 96,518 (57,329) (13,230) Net cash provided by operating activities (GAAP) $ 382,994 $ 513,370 $ 1,097,879 $ 1,398,031 ____________________________________________ (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. (2) For the three and nine months ended September 30, 2023, amounts exclude certain capital expenditures related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase. For the three and nine months ended September 30, 2022, amounts exclude certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of operation. 37