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, 2024, filed with the SEC on August 8, 2024. Throughout the following discussion, we explain changes between the three months ended September 30, 2024, and the three months ended June 30, 2024 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the nine months ended September 30, 2024, and the nine months ended September 30, 2023 (“YTD 2024-over-YTD 2023”). 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 and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. 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 focusing on continued operational excellence, successfully integrating the Uinta Basin assets, and continuing to return value to stockholders through fixed dividend payments and our Stock Repurchase Program, while also transferring value to stockholders through reduced debt. Our asset portfolio is comprised of high-quality assets in the Midland Basin in West Texas, the Maverick Basin in South Texas, and as of October 1, 2024, the Uinta Basin in northeast Utah, which we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, such as the Uinta Basin Acquisition, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining 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 effectiveness of our ESG policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, 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. Key factors contributing to market fluctuations include ongoing 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+”); lower than expected oil and gas demand from China; War and Geopolitical Instability; United States Federal Reserve monetary policy; shipping channel constraints and disruptions; and changes in global oil inventory in storage. These factors have driven commodity price volatility, contributed to instances of supply chain disruptions and fluctuations 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 2023 Form 10-K , and Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on July 18, 2024. 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 2024, our drilling and completion activities focused on development optimization of our RockStar and Sweetie Peck assets, and delineation and development of our Klondike assets. 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 2024, we focused our operations on development and further delineation of the Austin Chalk formation, and on production from both the Austin Chalk formation and Eagle Ford shale 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 25 includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. On October 1, 2024, we acquired approximately 63,300 net acres located in Duchesne and Uintah counties, Utah (“Uinta Basin”). Our Uinta Basin position provides future development opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and includes acreage with waxy crude and gas composition amenable to processing for NGL extraction. Please refer to Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion. Third Quarter 2024 Overview and Outlook for the Remainder of 2024 During the third quarter of 2024: • We exercised the option to purchase the Altamont Option Assets, and on October 1, 2024, we closed the Uinta Basin Acquisition, as discussed in Note 11 - Acquisitions in Part I, Item 1 of this report. • We issued our 2029 Senior Notes and 2032 Senior Notes and redeemed the remaining $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. • We continued to execute on our goal of sustainably returning capital to our stockholders by paying a net cash dividend of $0.18 per share totaling $20.6 million. Additionally, we declared an increased net cash dividend of $0.20 per share totaling $22.9 million, which will be paid in the fourth quarter of 2024. Financial and Operational Results. Average net daily equivalent production for the three months ended September 30, 2024, increased seven percent sequentially to 170.0 MBOE, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. These increases were a result of strong well performance and the timing of well completions. Oil, gas, and NGL production revenue increased one percent to $642.4 million for the three months ended September 30, 2024, compared with $633.5 million for the three months ended June 30, 2024. Oil, gas, and NGL production expense increased nine percent to $148.4 million for the three months ended September 30, 2024, compared with $136.6 million for the three months ended June 30, 2024, as a result of increases in transportation expense and lease operating expense (“LOE”). Realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), decreased six percent sequentially. During the third quarter of 2024, oil and NGL benchmark prices decreased, and the gas benchmark price increased. These changes resulted in sequential quarterly decreases in oil and NGL realized prices of seven percent and five percent, respectively, partially offset by an increase in the gas realized price of four percent. We recorded net derivative gains of $86.3 million and $12.1 million for the three months ended September 30, 2024, and June 30, 2024, respectively. Included within these amounts are net derivative settlement gains of $16.5 million for each of the three months ended September 30, 2024, and June 30, 2024. Operational and financial activities during the three months ended September 30, 2024, resulted in the following: • Net cash provided by operating activities of $452.3 million, compared with $476.4 million for the three months ended June 30, 2024. • Net income of $240.5 million, or $2.09 per diluted share, compared with net income of $210.3 million, or $1.82 per diluted share, for the three months ended June 30, 2024. • Adjusted EBITDAX, a non-GAAP financial measure, of $481.5 million, compared with $485.9 million for the three months ended June 30, 2024. 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, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 below for additional discussion. Operational Activities. We expect our total 2024 capital program to be between $1.24 billion and $1.26 billion, including capital expenditures related to the development of our recently acquired Uinta Basin assets, but excluding acquisitions. Our capital program remains focused on highly economic oil development projects in our Midland Basin, South Texas, and Uinta Basin assets. During 2024, we expect to continue our focus on strategic inventory replacement and growth by 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 2024 capital program. 26 In our Midland Basin program, we operated four drilling rigs and averaged one completion crew, drilled 27 gross (19 net) wells, and completed 17 gross (15 net) wells during the third quarter of 2024. Average net daily equivalent production volumes increased sequentially by six percent to 84.6 MBOE. Costs incurred during the three months ended September 30, 2024, totaled $168.3 million, or 55 percent of our total costs incurred for the period. We anticipate operating four drilling rigs and one completion crew for the remainder of 2024, focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets. In our South Texas program, we operated two drilling rigs and one completion crew, drilled 16 gross (16 net) wells, and completed 20 gross (20 net) wells during the third quarter of 2024. Average net daily equivalent production volumes increased sequentially by eight percent to 85.4 MBOE. Costs incurred during the three months ended September 30, 2024, totaled $125.9 million, or 41 percent of our total costs incurred for the period. We anticipate operating two drilling rigs and no completion crews for the remainder of 2024, focused primarily on developing the Austin Chalk formation. In our Uinta Basin program, we anticipate operating three drilling rigs and one completion crew during the remainder of 2024, focused primarily on delineating and developing our recently acquired assets. 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, 2024: Midland Basin South Texas (1) Total Gross Net Gross Net Gross Net Wells drilled but not completed at December 31, 2023 39 29 37 37 76 66 Wells drilled 19 17 12 12 31 29 Wells completed (16) (11) (16) (16) (32) (27) Wells drilled but not completed at March 31, 2024 42 35 33 33 75 68 Wells drilled 24 21 10 10 34 31 Wells completed (32) (26) (10) (10) (42) (36) Wells drilled but not completed at June 30, 2024 34 30 33 33 67 63 Wells drilled 27 19 16 16 43 35 Wells completed (17) (15) (20) (20) (37) (35) Wells drilled but not completed at September 30, 2024 (2) 44 34 29 29 73 63 ____________________________________________ (1) As of December 31, 2023, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2023, eight of which were in the Eagle Ford shale. (2) Amount excludes five gross (two net) non-operated wells drilled in the Midland Basin during the third quarter of 2024, resulting in five gross (two net) non-operated wells drilled but not completed at September 30, 2024. Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $304.7 million and $956.8 million for the three and nine months ended September 30, 2024, respectively, and were primarily incurred in our Midland Basin and South Texas programs as discussed in Operational Activities above. 27 Production Results. The table below presents our net 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, 2024 June 30, 2024 September 30, 2024 September 30, 2023 Midland Basin Net Production: Oil (MMBbl) 5.1 4.7 14.1 13.0 Gas (Bcf) 16.1 15.4 46.0 44.6 NGLs (MMBbl) — — — — Equivalent (MMBOE) 7.8 7.2 21.8 20.4 Average net daily equivalent (MBOE per day) 84.6 79.7 79.6 74.8 Relative percentage 50 % 50 % 50 % 49 % South Texas Net Production: Oil (MMBbl) 2.0 1.9 5.4 4.7 Gas (Bcf) 18.5 16.8 51.9 54.2 NGLs (MMBbl) 2.8 2.4 7.4 7.2 Equivalent (MMBOE) 7.9 7.2 21.5 21.0 Average net daily equivalent (MBOE per day) 85.4 78.8 78.3 76.7 Relative percentage 50 % 50 % 50 % 51 % Total Net Production: Oil (MMBbl) 7.1 6.6 19.5 17.7 Gas (Bcf) 34.5 32.2 97.9 98.9 NGLs (MMBbl) 2.8 2.4 7.4 7.2 Equivalent (MMBOE) 15.6 14.4 43.3 41.4 Average net daily equivalent (MBOE per day) 170.0 158.5 157.9 151.5 ____________________________________________ 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, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 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 net 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. 28 The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the three months ended September 30, 2024, June 30, 2024, and September 30, 2023: For the Three Months Ended September 30, 2024 June 30, 2024 September 30, 2023 Oil (per Bbl): Average NYMEX contract monthly price $ 75.10 $ 80.57 $ 82.26 Realized price $ 74.72 $ 80.48 $ 80.95 Effect of oil net derivative settlements $ (0.07) $ (0.18) $ (2.18) Gas: Average NYMEX monthly settle price (per MMBtu) $ 2.16 $ 1.89 $ 2.55 Realized price (per Mcf) $ 1.46 $ 1.40 $ 2.48 Effect of gas net derivative settlements (per Mcf) $ 0.48 $ 0.55 $ 0.35 NGLs (per Bbl): Average OPIS price (1) $ 26.68 $ 27.96 $ 27.81 Realized price $ 21.70 $ 22.86 $ 23.61 Effect of NGL net derivative settlements $ 0.09 $ — $ 0.60 ____________________________________________ (1) 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. 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. 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. Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, lower than expected oil and gas demand from China, War and Geopolitical Instability, changes in global oil inventory in storage, 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 inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. 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 realized price for our Midland Basin gas production was impacted by residue pipeline capacity constraints during the third quarter of 2024; however, a portion of any negative impact to the realized price was mitigated by our commodity derivative contracts in effect during the third quarter of 2024. We expect that increased infrastructure capacity will alleviate constraints during the fourth quarter of 2024. The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of October 24, 2024, and September 30, 2024: As of October 24, 2024 As of September 30, 2024 NYMEX WTI oil (per Bbl) $ 69.04 $ 67.27 NYMEX Henry Hub gas (per MMBtu) $ 3.06 $ 3.20 OPIS NGLs (per Bbl) $ 27.50 $ 27.02 We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows 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. 29 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, 2024, and the preceding three quarters: For the Three Months Ended September 30, June 30, March 31, December 31, 2024 2024 2024 2023 (in millions) Net production (MMBOE) 15.6 14.4 13.2 14.1 Oil, gas, and NGL production revenue $ 642.4 $ 633.5 $ 559.6 $ 606.9 Oil, gas, and NGL production expense $ 148.4 $ 136.6 $ 137.4 $ 137.3 Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 202.9 $ 179.7 $ 166.2 $ 189.1 Exploration $ 12.1 $ 17.1 $ 18.6 $ 15.8 General and administrative $ 35.1 $ 31.1 $ 30.2 $ 36.6 Net income $ 240.5 $ 210.3 $ 131.2 $ 247.1 Selected Performance Metrics For the Three Months Ended September 30, June 30, March 31, December 31, 2024 2024 2024 2023 Average net daily equivalent production (MBOE per day) 170.0 158.5 145.1 153.5 Lease operating expense (per BOE) $ 4.73 $ 4.82 $ 5.54 $ 5.31 Transportation costs (per BOE) $ 2.13 $ 1.94 $ 2.07 $ 2.08 Production taxes as a percent of oil, gas, and NGL production revenue 4.6 % 4.3 % 4.5 % 4.6 % Ad valorem tax expense (per BOE) $ 0.76 $ 0.82 $ 0.89 $ 0.37 Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) $ 12.98 $ 12.46 $ 12.59 $ 13.39 General and administrative (per BOE) $ 2.25 $ 2.16 $ 2.29 $ 2.60 ____________________________________________ Note: Amounts may not calculate due to rounding. 30 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, 2024 2024 2024 2023 Net production volumes: (1) Oil (MMBbl) 7.1 6.6 0.5 8 % 19.5 17.7 1.8 10 % Gas (Bcf) 34.5 32.2 2.3 7 % 97.9 98.9 (1.0) (1) % NGLs (MMBbl) 2.8 2.4 0.3 13 % 7.4 7.2 0.2 3 % Equivalent (MMBOE) 15.6 14.4 1.2 8 % 43.3 41.4 1.9 5 % Average net daily production: (1) Oil (MBbl per day) 77.4 72.7 4.7 6 % 71.3 64.8 6.4 10 % Gas (MMcf per day) 375.4 354.0 21.5 6 % 357.3 362.2 (4.9) (1) % NGLs (MBbl per day) 30.1 26.8 3.3 12 % 27.1 26.3 0.7 3 % Equivalent (MBOE per day) 170.0 158.5 11.5 7 % 157.9 151.5 6.4 4 % Oil, gas, and NGL production revenue (in millions): (1) Oil production revenue $ 531.8 $ 532.6 $ (0.7) — % $ 1,505.3 $ 1,343.5 $ 161.8 12 % Gas production revenue 50.6 45.2 5.4 12 % 163.6 245.3 (81.7) (33) % NGL production revenue 60.0 55.7 4.3 8 % 166.6 168.3 (1.7) (1) % Total oil, gas, and NGL production revenue $ 642.4 $ 633.5 $ 8.9 1 % $ 1,835.4 $ 1,757.0 $ 78.4 4 % Oil, gas, and NGL production expense (in millions): (1) Lease operating expense $ 73.9 $ 69.5 $ 4.4 6 % $ 216.6 $ 209.9 $ 6.7 3 % Transportation costs 33.3 28.0 5.3 19 % 88.7 106.9 (18.2) (17) % Production taxes 29.3 27.2 2.1 8 % 81.7 77.4 4.3 6 % Ad valorem tax expense 11.8 11.8 — — % 35.5 32.1 3.4 11 % Total oil, gas, and NGL production expense $ 148.4 $ 136.6 $ 11.8 9 % $ 422.4 $ 426.2 $ (3.8) (1) % Realized price: Oil (per Bbl) $ 74.72 $ 80.48 $ (5.76) (7) % $ 77.08 $ 75.90 $ 1.18 2 % Gas (per Mcf) $ 1.46 $ 1.40 $ 0.06 4 % $ 1.67 $ 2.48 $ (0.81) (33) % NGLs (per Bbl) $ 21.70 $ 22.86 $ (1.16) (5) % $ 22.45 $ 23.40 $ (0.95) (4) % Per BOE $ 41.08 $ 43.92 $ (2.84) (6) % $ 42.42 $ 42.47 $ (0.05) — % Per BOE data: (1) Oil, gas, and NGL production expense: Lease operating expense $ 4.73 $ 4.82 $ (0.09) (2) % $ 5.01 $ 5.07 $ (0.06) (1) % Transportation costs 2.13 1.94 0.19 10 % 2.05 2.58 (0.53) (21) % Production taxes 1.87 1.89 (0.02) (1) % 1.89 1.87 0.02 1 % Ad valorem tax expense 0.76 0.82 (0.06) (7) % 0.82 0.78 0.04 5 % Total oil, gas, and NGL production expense (1) $ 9.49 $ 9.47 $ 0.02 — % $ 9.76 $ 10.30 $ (0.54) (5) % Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 12.98 $ 12.46 $ 0.52 4 % $ 12.68 $ 12.12 $ 0.56 5 % General and administrative $ 2.25 $ 2.16 $ 0.09 4 % $ 2.23 $ 2.04 $ 0.19 9 % Net derivative settlement gain (2) $ 1.05 $ 1.15 $ (0.10) (9) % $ 1.07 $ 0.49 $ 0.58 118 % Earnings per share information (in thousands, except per share data): (3) Basic weighted-average common shares outstanding 114,405 114,634 (229) — % 114,870 119,589 (4,719) (4) % Diluted weighted-average common shares outstanding 114,993 115,715 (722) (1) % 115,701 120,165 (4,464) (4) % Basic net income per common share $ 2.10 $ 1.83 $ 0.27 15 % $ 5.07 $ 4.77 $ 0.30 6 % Diluted net income per common share $ 2.09 $ 1.82 $ 0.27 15 % $ 5.03 $ 4.75 $ 0.28 6 % 31 ______________________________________ (1) Amounts and percentage changes may not calculate due to rounding. (2) Net derivative settlements for the three months ended September 30, 2024, and for the nine months ended September 30, 2024, and 2023, 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, 2024, increased seven percent sequentially, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. Average net daily equivalent production increased four percent YTD 2024-over-YTD 2023, consisting of increases of six percent and two percent from our Midland Basin and South Texas assets, respectively. These increases were a result of strong well performance and the timing of well completions. We expect a slight increase in total net equivalent production for the full-year 2024, compared with 2023, driven by well performance and an accelerated pace of development of our existing assets, as well as production from our newly acquired assets in the Uinta Basin. 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. The full-year 2024 trends discussed below include our expectations related to the Uinta Basin Acquisition. Our realized price on a per BOE basis decreased $2.84 sequentially and remained flat YTD 2024-over-YTD 2023. The sequential decrease primarily resulted from a decrease in oil benchmark prices. For the three months ended September 30, 2024, and June 30, 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.05 per BOE and $1.15 per BOE, respectively. For the nine months ended September 30, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.07 per BOE and $0.49 per BOE, respectively. LOE on a per BOE basis remained relatively flat both sequentially and YTD 2024-over-YTD 2023 as increases in labor costs and certain other operating costs were mostly offset by a decrease in workover expense due to timing of activity. For the full-year 2024, we expect LOE on a per BOE basis to remain relatively flat, compared with 2023, primarily as a result of expected increases in labor costs and certain other operating costs offset by decreases in workover expense and changes in our overall production mix. 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 increased ten percent sequentially as a result of an eight percent increase in net equivalent production from our South Texas assets, which incur higher transportation costs than our Midland Basin assets. Transportation costs on a per BOE basis in South Texas also increased slightly as a result of expenditures necessary to upgrade certain gathering and transportation infrastructure to handle increasingly liquids-rich production from the Austin Chalk formation. Transportation costs on a per BOE basis decreased 21 percent YTD 2024-over-YTD 2023 primarily 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 and oil production from our Uinta Basin assets, where we incur and anticipate incurring a majority of our transportation costs. For the full-year 2024, we expect transportation costs on a per BOE basis to increase compared with 2023, as a result of the addition of our Uinta Basin assets. Production tax expense on a per BOE basis remained relatively flat both sequentially and YTD 2024-over-YTD 2023. Our overall production tax rate for the three and nine months ended September 30, 2024, was 4.6 percent and 4.4 percent, respectively, compared with 4.3 percent for the three months ended June 30, 2024, and 4.4 percent for the nine months ended September 30, 2023. We expect that our Uinta Basin assets will incur a lower production tax rate compared to our Midland Basin and South Texas assets. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize. Ad valorem tax expense on a per BOE basis decreased seven percent sequentially and increased five percent YTD 2024-over-YTD 2023, 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 four percent sequentially primarily as a result of an increase in our DD&A rate due to inflation. DD&A expense on a per BOE basis increased five percent YTD 2024-over-YTD 2023 due to inflation and a slight shift in production mix resulting from higher activity in our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties. For the full-year 2024, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2023, primarily as a result of expected increased production, the acquisition of the Uinta Basin assets, and a shift in our production mix. 32 General and administrative (“G&A”) expense on a per BOE basis increased four percent sequentially and nine percent YTD 2024-over-YTD 2023 primarily as a result of increased compensation expense due to inflation and increases in certain G&A expenses resulting from the Uinta Basin Acquisition. We expect that these factors will lead to an increase in G&A expense per BOE and G&A expense on an absolute basis for the full-year 2024, compared with 2023. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 below for additional discussion of operating expenses. Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 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, 2024, and June 30, 2024: Average Net Equivalent Production Increase Oil, Gas, and NGL Production Revenue Increase Oil, Gas, and NGL Production Expense Increase (MBOE per day) (in millions) (in millions) Midland Basin 4.9 $ 4.6 $ 2.8 South Texas 6.6 4.4 9.0 Total 11.5 $ 8.9 $ 11.8 __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes increased seven percent, consisting of increases of eight percent and six percent from our South Texas and Midland Basin assets, respectively. As a result of decreases in benchmark commodity prices for oil and NGLs, total realized price per BOE decreased six percent. The increase in average net daily equivalent production volumes was partially offset by the decrease in total realized price per BOE resulting in a one percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense increased nine percent, primarily driven by the impact of the increase in net production volumes on transportation expense and LOE. YTD 2024-over-YTD 2023 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, 2024, and 2023: Average Net Equivalent Production Increase Oil, Gas, and NGL Production Revenue Increase Oil, Gas, and NGL Production Expense Increase (Decrease) (MBOE per day) (in millions) (in millions) Midland Basin 4.8 $ 55.7 $ 6.2 South Texas 1.5 22.7 (10.0) Total 6.4 $ 78.4 $ (3.8) __________________________________________ Note: Amounts may not calculate due to rounding. Average net daily equivalent production volumes increased four percent, consisting of increases of six percent and two percent from our Midland Basin and South Texas assets, respectively. Total realized price per BOE remained flat. As a result of the increase in average net daily equivalent production volumes, oil, gas, and NGL production revenue increased four percent. Oil, gas, and NGL production expense decreased one percent, primarily driven by a decrease in transportation expense, partially offset by increases in LOE, production tax expense, 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. 33 Depletion, depreciation, amortization, and asset retirement obligation liability accretion For the Three Months Ended For the Nine Months Ended September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions) Depletion, depreciation, amortization, and asset retirement obligation liability accretion $ 202.9 $ 179.7 $ 548.8 $ 501.4 DD&A expense increased 13 percent sequentially and nine percent YTD 2024-over-YTD 2023. The sequential quarterly increase was primarily driven by an increase in average net daily equivalent production and an increase in our DD&A rate due to inflation. The YTD 2024-over-YTD 2023 increase resulted from a combination of increased average net daily equivalent production, an increase in our DD&A rate due to inflation, and a slight shift in production mix resulting from higher activity in our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis. Exploration For the Three Months Ended For the Nine Months Ended September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions) Geological, geophysical, and other expenses $ 3.0 $ 8.7 $ 22.7 $ 20.7 Overhead 9.1 8.4 25.1 22.9 Total $ 12.1 $ 17.1 $ 47.8 $ 43.6 Exploration expense decreased 29 percent sequentially primarily due to a decrease in geological and geophysical expenses, partially offset by an increase in exploration overhead expense. The YTD 2024-over-YTD 2023 increase of 10 percent primarily resulted from expenses incurred related to one well deemed non-commercial, which primarily affected the three months ended March 31, 2024. 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, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions) General and administrative $ 35.1 $ 31.1 $ 96.4 $ 84.4 G&A expense increased 13 percent sequentially and 14 percent YTD 2024-over-YTD 2023 as a result of increases in compensation expense due to inflation and increases in certain G&A expenses resulting from the Uinta Basin Acquisition. 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, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions) Net derivative (gain) loss $ (86.3) $ (12.1) $ (70.3) $ 12.4 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. 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, as measured against our derivative contract prices. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion. 34 Interest expense For the Three Months Ended For the Nine Months Ended September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions) Interest expense $ (50.7) $ (21.8) $ (94.4) $ (67.7) Interest expense increased 133 percent sequentially and 39 percent YTD 2024-over-YTD 2023. The sequential quarterly and YTD 2024-over-YTD 2023 increases primarily resulted from the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 and a $9.0 million fee that was paid to secure firm commitments for up to $1.2 billion of senior unsecured 364-day bridge term loans (“Bridge Facility”) in connection with the Uinta Basin Acquisition. We did not draw on the Bridge Facility, and after issuance of the 2029 Senior Notes and the 2032 Senior Notes on July 25, 2024, we terminated the Bridge Facility, and the associated fees were recognized as interest expense. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest as a result of the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Please refer to Overview of Liquidity and Capital Resources below and to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. Income tax expense For the Three Months Ended For the Nine Months Ended September 30, 2024 June 30, 2024 September 30, 2024 September 30, 2023 (in millions, except tax rate) Income tax expense $ (57.1) $ (53.6) $ (142.8) $ (51.6) Effective tax rate 19.2 % 20.3 % 19.7 % 8.3 % The sequential quarterly decrease in the effective tax rate is due to the effect of excess tax benefits from share-based payment awards during the third quarter of 2024 and an increased benefit from qualified R&D credits claimed. The YTD 2024-over-YTD 2023 increase in the effective tax rate is primarily due to the benefit recognized from the multi-year R&D credit study which was completed during the third quarter of 2023. The effective tax rate for the three and nine months ended September 30, 2024, reflects the benefit of current R&D credits claimed and we expect to continue to recognize benefits from R&D activities for the remainder of 2024. Based on current projections, we estimate that after utilization of a portion of the R&D credits, between $25.0 million and $35.0 million of full-year 2024 income tax expense will be current. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion. 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. Effective for tax years beginning after December 31, 2022, the Inflation Reduction Act of 2022 provides for a 15 percent corporate alternative minimum tax (“CAMT”) on corporations with average adjusted financial statement income over $1.0 billion for any three-year period preceding the tax year. Final proposed regulations regarding the CAMT may impact our calculation and the CAMT could become applicable to us beginning in 2025. Please refer to Overview of Liquidity and Capital Resources below and to the Risk Factors section in Part 1, Item 1A of our 2023 Form 10-K . 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, 2024, we funded our capital expenditures and return of capital program with cash flows from operating activities and cash on hand. For the remainder of 2024, we expect to fund our capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for the remainder of 2024, 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 certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. 35 During the third quarter of 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. Please see below for discussion on how the net proceeds received were used, and refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Subsequent to September 30, 2024, one major credit rating agency upgraded our credit ratings following the close of the Uinta Basin Acquisition on October 1, 2024, citing our increased size and scale, increased inventory, increased oil percentage of expected production, strong operational performance, our priority of improving our leverage metrics, our ability to consistently generate cash flows, and our use of financial derivative instruments as part of our financial risk management program. 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 financial 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, 2024, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively. Subsequent to September 30, 2024, we entered into the Second Amendment with our lenders. The Second Amendment amended certain provisions of the Credit Agreement to, among other things, increase the aggregate revolving lender commitments available under the Credit Agreement from $1.25 billion to $2.0 billion and extend the Stated Maturity Date to October 1, 2029. On October 11, 2024, our lenders completed the semi-annual borrowing base redetermination, which resulted in an increase to our borrowing base to $3.0 billion and reaffirmed the aggregate revolving lender commitment at the existing amount of $2.0 billion. 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. The next borrowing base redetermination date is scheduled to occur on April 1, 2025. 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, 2024, and through the filing of this report. We had no revolving credit facility borrowings during the nine months ended September 30, 2024, or at any time during 2023. Subsequent to September 30, 2024, we borrowed under our revolving credit facility to fund a portion of the Uinta Basin Acquisition as discussed in Note 11 - Acquisitions in Part I, Item 1 of this report. 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. 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 24, 2024, September 30, 2024, and December 31, 2023. 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, and the non-cash amortization of deferred financing costs. 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, 2024 June 30, 2024 September 30, 2024 September 30, 2023 Weighted-average interest rate 7.3 % 7.1 % 7.2 % 7.1 % Weighted-average borrowing rate 6.8 % 6.4 % 6.6 % 6.4 % 36 Our weighted-average interest and weighted-average borrowing rate each increased sequentially and YTD 2024-over-YTD 2023 as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes, which have greater outstanding aggregate principal balances and higher interest rates than our 2025 Senior Notes that we redeemed during the third quarter of 2024. Our weighted-average interest rate was further impacted by an increase in the non-cash amortization of deferred financing costs related to the 2029 Senior Notes and 2032 Senior Notes, which was only partially offset by a decrease related to the 2025 Senior Notes. We expect our weighted-average interest rate and weighted-average borrowing rate to increase for the full-year 2024 compared with 2023. The rates disclosed in the table above for the three and nine months ended September 30, 2024, do not reflect the $9.0 million fee paid to secure the Bridge Facility in connection with the Uinta Basin Acquisition. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. 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 under our revolving credit facility. Additionally, our weighted-average interest rate is 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 redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs, because these amounts are netted against the associated gain or loss on extinguishment of debt. The 2025 Senior Notes were redeemed on August 26, 2024. After this date, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs related to the 2025 Senior Notes. 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, debt obligations, including interest and early repayments or redemptions, dividends, and for repurchases of shares of our outstanding 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, 2024, we spent $957.2 million on capital expenditures. This amount differs from the costs incurred amount of $956.8 million for the nine months ended September 30, 2024, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts. The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, 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 2024 capital program is expected to be between $1.24 billion and $1.26 billion, including capital expenditures related to the development of our recently acquired Uinta Basin assets, but excluding acquisitions. 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. On August 26, 2024, we redeemed all of the $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. 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, 2024, and 2023, we repurchased and subsequently retired 1.8 million and 6.3 million shares, respectively, of our common stock at a cost of $84.0 million and $205.1 million, respectively, excluding excise taxes, commissions, and fees. As of September 30, 2024, $500.0 million was available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion. During the nine months ended September 30, 2024, and 2023, we paid $62.1 million and $54.2 million, respectively, in dividends to our stockholders. In the second quarter of 2024, our Board of Directors approved an increase to our fixed dividend policy, pursuant to which we intend to pay $0.80 per share annually, in quarterly increments of $0.20 per share, beginning in the fourth 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 remain at the discretion of our Board of Directors. On October 1, 2024, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, a portion of the Cash Deposit, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Please refer to Note 5 - Long-Term Debt and Note 11 - Acquisitions in Part I, Item 1 of this report for additional discussion. 37 Changes in federal income tax laws could increase our corporate income tax rate and could eliminate or reduce current tax deductions. The CAMT could become applicable to us beginning in 2025. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended September 30, 2024, and June 30, 2024, and Between the Nine Months Ended September 30, 2024, and 2023 above for additional discussion. Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2024, and 2023 The following tables present changes in cash flows between the nine months ended September 30, 2024, and 2023, 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. Operating activities For the Nine Months Ended September 30, Amount Change Between Periods 2024 2023 (in millions) Net cash provided by operating activities $ 1,204.6 $ 1,097.9 $ 106.7 Net cash provided by operating activities increased for the nine months ended September 30, 2024, compared with the same period in 2023, primarily as a result of a $125.0 million increase in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes, partially offset by an increase of $40.6 million in cash paid on settled derivative trades and an increase of $34.2 million in cash paid for G&A expense. 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 2024 2023 (in millions) Net cash used in investing activities $ (957.9) $ (875.4) $ (82.5) Net cash used in investing activities increased for the nine months ended September 30, 2024, compared with the same period in 2023, as a result of a $190.4 million increase in capital expenditures, partially offset by a $109.3 million decrease in cash paid to acquire proved and unproved oil and gas properties in the Midland Basin. Financing activities For the Nine Months Ended September 30, Amount Change Between Periods 2024 2023 (in millions) Net cash provided by (used in) financing activities $ 974.4 $ (265.5) $ 1,239.9 Net cash provided by (used in) financing activities for the nine months ended September 30, 2024, primarily related to the net cash proceeds of $1.48 billion received from the issuance of our 2029 Senior Notes and 2032 Senior Notes, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes, $84.0 million of cash paid, including commissions and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program, and $62.1 million of dividends paid to our stockholders. Net cash used in financing activities for the nine months ended September 30, 2023, 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 to our stockholders. Interest Rate Risk We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance under 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 of 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 38 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, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 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. Commodity Price Risk The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, 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+, lower than expected oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, 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 fluctuations 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, 2024, 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 $150.5 million, $16.4 million, and $16.7 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the nine months ended September 30, 2024, would have offset the declines in oil, gas, and NGL production revenue by approximately $24.3 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, 2024, 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 $54.3 million, $26.7 million, and $3.4 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, 2024, 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 2023 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 2023 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. 39 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 (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, 2024 September 30, 2023 September 30, 2024 September 30, 2023 (in thousands) Net income (GAAP) $ 240,523 $ 222,343 $ 582,015 $ 570,769 Interest expense 50,682 23,106 94,362 67,713 Interest income (18,017) (4,106) (31,120) (13,802) Income tax expense (benefit) 57,127 (45,979) 142,786 51,619 Depletion, depreciation, amortization, and asset retirement obligation liability accretion 202,942 189,353 548,781 501,374 Exploration (1) 10,759 9,071 44,121 40,612 Stock-based compensation expense 6,587 6,038 17,393 14,519 Net derivative (gain) loss (86,283) 75,355 (70,256) 12,352 Net derivative settlement gain (loss) 16,491 (314) 46,288 20,398 Other, net 706 698 2,126 1,625 Adjusted EBITDAX (non-GAAP) 481,517 475,565 1,376,496 1,267,179 Interest expense (50,682) (23,106) (94,362) (67,713) Interest income 18,017 4,106 31,120 13,802 Income tax (expense) benefit (57,127) 45,979 (142,786) (51,619) Exploration (1) (2) (10,456) (8,912) (34,892) (31,566) Amortization of deferred financing costs 2,182 1,371 4,925 4,114 Deferred income taxes 45,615 (51,075) 116,522 43,171 Other, net (8,843) (8,041) (36,945) (22,160) Net change in working capital 32,040 (52,893) (15,433) (57,329) Net cash provided by operating activities (GAAP) $ 452,263 $ 382,994 $ 1,204,645 $ 1,097,879 ____________________________________________ (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, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial. For the three and nine months ended September 30, 2023, amounts exclude certain capital expenditures primarily related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase. 40