What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-11-01 compared with 2024-08-08 · 213 added, 182 removed, 339 unchanged (54% of the section changed)

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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 March 31, 2024, filed with the SEC on May 3, 2024.

Throughout the following discussion, we explain changes between the three months ended June 30, 2024, and the three months ended March 31, 2024 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the six months ended June 30, 2024, and the six months ended June 30, 2023 (“YTD 2024-over-YTD 2023”).

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

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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 and continuing to return value to stockholders through our Stock Repurchase Program and fixed dividend payments.

Our asset portfolio is currently comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that 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, including the recently announced pending XCL Acquisition, and continued development and optimization of our existing assets.

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.

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We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility.

While inflation continues to affect certain aspects of our business, the extent of its impact decreased in the first half of 2024 compared with 2023.

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, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, and changes in global oil inventory in storage 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.

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.

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Our Midland Basin assets are comprised of approximately 110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”).

In the second 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.

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 second 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.

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

includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.

Second Quarter 2024 Overview and Outlook for the Remainder of 2024

During the second quarter of 2024:

• We entered into the XCL Acquisition Agreement to purchase the Uinta Basin Assets and, subsequent to June 30, 2024, exercised the option to purchase the Option Assets as discussed in Note 11 - Acquisitions in Part I, Item I of this report.

Full-year 2024 trends discussed below do not reflect our expectations related to the pending XCL Acquisition.

• Our Board of Directors re-authorized our existing Stock Repurchase Program, which authorizes us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2027.

• Our Board of Directors approved an increase to our fixed dividend policy, pursuant to which we intend to pay $0.20 per share per quarter, beginning in the fourth quarter of 2024.

• 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 1.1 million shares of our outstanding common stock at a cost of $51.2 million, excluding excise taxes, commissions, and fees, and paying a quarterly dividend of $0.18 per share totaling $20.7 million.

Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion.

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 June 30, 2024, increased nine percent sequentially to 158.5 MBOE, consisting of a 12 percent increase from our South Texas assets and a seven percent increase from our Midland Basin assets.

These increases were a result of production from new wells which more than offset the natural decline in production from existing wells during the second quarter of 2024.

Realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), increased four percent sequentially.

During the second quarter of 2024, the oil benchmark price increased, and gas and NGL benchmark prices decreased.

These changes resulted in a sequential quarterly increase in oil realized price of six percent, partially offset by a decrease in gas realized price of 36 percent.

The NGL realized price remained flat sequentially.

As a result of the increase in average net daily equivalent production volumes, oil, gas, and NGL production revenue increased 13 percent sequentially to $633.5 million for the three months ended June 30, 2024, compared with $559.6 million for the three months ended March 31, 2024.

Oil, gas, and NGL production expense of $9.47 per BOE for the three months ended June 30, 2024, decreased nine percent sequentially, primarily as a result of decreases in lease operating expense (“LOE”) per BOE, transportation costs per BOE, and ad valorem tax expense per BOE.

We recorded a net derivative gain of $12.1 million and a net derivative loss of $28.1 million for the three months ended June 30, 2024, and March 31, 2024, respectively.

Included within these amounts are net derivative settlement gains of $16.5 million and $13.3 million for the three months ended June 30, 2024, and March 31, 2024, respectively.

Operational and financial activities during the three months ended June 30, 2024, resulted in the following:

• Net cash provided by operating activities of $476.4 million, compared with $276.0 million for the three months ended March 31, 2024.

• Net income of $210.3 million, or $1.82 per diluted share, compared with net income of $131.2 million, or $1.13 per diluted share, for the three months ended March 31, 2024.

• Adjusted EBITDAX, a non-GAAP financial measure, of $485.9 million, compared with $409.0 million for the three months ended March 31, 2024.

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 June 30, 2024, and March 31, 2024, and Between the Six Months Ended June 30, 2024, and 2023 below for additional discussion.

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 $1.14 billion and $1.18 billion, excluding acquisitions, and excluding any expected capital expenditures related to the Uinta Basin Assets and the Option Assets.

Our capital program remains focused on highly economic oil development projects in both our Midland Basin and South Texas assets.

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.

In our Midland Basin program, we operated an average of four drilling rigs and averaged two completion crews, drilled 24 gross (21 net) wells, and completed 32 gross (26 net) wells during the second quarter of 2024.

Average net daily equivalent production volumes increased sequentially by seven percent to 79.7 MBOE.

Costs incurred during the three months ended June 30, 2024, totaled $202.4 million, or 61 percent of our total costs incurred for the period.

We anticipate operating four drilling rigs and between one and two completion crews 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 10 gross (10 net) wells, and completed 10 gross (10 net) wells during the second quarter of 2024.

Average net daily equivalent production volumes increased sequentially by 12 percent to 78.8 MBOE.

Costs incurred during the three months ended June 30, 2024, totaled $117.9 million, or 36 percent of our total costs incurred for the period.

We anticipate operating two drilling rigs and averaging one completion crew for the remainder of 2024, 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 six months ended June 30, 2024:

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.

Midland Basin South Texas (1)

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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

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(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 $331.9 million and $652.1 million for the three and six months ended June 30, 2024, respectively, and were primarily incurred in our Midland Basin and South Texas programs as discussed in Operational Activities above.

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.

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 Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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:

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Amounts may not calculate due to rounding.

Oil, Gas, and NGL Prices

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While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the three months ended June 30, 2024, March 31, 2024, and June 30, 2023:

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

June 30, 2024 March 31, 2024 June 30, 2023

September 30, 2024 June 30, 2024 September 30, 2023

Oil (per Bbl):

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Realized prices reflect our actual product mix.

Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, 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 further inflation, supply chain disruptions, fluctuations 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.

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 second quarter of 2024, and we expect that to continue during the third quarter of 2024;

however, a portion of any negative impact to the realized price would be mitigated by our commodity derivative contracts, which are discussed below.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of July 31, 2024, and June 30, 2024:

As of July 31, 2024 As of June 30, 2024

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

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Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended June 30, 2024, and the preceding three quarters:

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

June 30, March 31, December 31, September 30,

September 30, June 30, March 31, December 31,

2024 2024 2024 2023

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For the Three Months Ended

June 30, March 31, December 31, September 30,

September 30, June 30, March 31, December 31,

2024 2024 2024 2023

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Overview of Selected Production and Financial Information, Including Trends

For the Three Months Ended Amount Change Between Periods Percent Change Between Periods For the Six Months Ended Amount Change Between Periods Percent Change Between Periods

June 30, March 31, June 30, June 30,

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

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

(2) Net derivative settlements for the three months ended June 30, 2024, and for the six months ended June 30, 2024, and 2023, are included within the net derivative (gain) loss line item in the accompanying statements of operations.

(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 June 30, 2024, increased nine percent sequentially, consisting of a 12 percent increase from our South Texas assets and a seven percent increase from our Midland Basin assets.

These increases were a result of production from new wells which more than offset the natural decline in production from existing wells during the second quarter of 2024.

Average net daily equivalent production remained flat YTD 2024-over-YTD 2023, as a five percent increase from our Midland Basin assets, was mostly offset by a three percent decrease from our South Texas assets.

We expect a slight increase in total net equivalent production for the full-year 2024, compared with 2023, driven by well performance and increased development pace, excluding the effects of the pending XCL Acquisition.

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 do not reflect our expectations related to the pending XCL Acquisition.

Our realized price on a per BOE basis increased $1.53 sequentially and $2.16 YTD 2024-over-YTD 2023, primarily as a result of an increase in oil benchmark prices.

For the three months ended June 30, 2024, and March 31, 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.15 per BOE and $1.01 per BOE, respectively.

For the six months ended June 30, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.08 per BOE and $0.76 per BOE, respectively.

LOE on a per BOE basis decreased 13 percent sequentially and increased two percent YTD 2024-over-YTD 2023.

The sequential quarterly decrease was a result of increased average net daily equivalent production and a decrease in workover expense due to timing of activity.

The YTD 2024-over-YTD 2023 increase was primarily driven by increases in labor costs and certain other operating costs, partially 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 increase, compared with 2023, primarily as a result of expected increases in labor costs and certain other operating costs associated with both our Midland Basin and South Texas assets.

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 decreased six percent sequentially as the 12 percent increase in net equivalent production from our South Texas assets consisted primarily of increased oil production which incurs lower transportation costs than gas production.

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, where we incur a majority of our transportation costs.

For the full-year 2024, we expect transportation costs on a per BOE basis to decrease compared with 2023, as a result of the expiration of the long-term contract in South Texas previously discussed.

Production tax expense on a per BOE basis remained flat sequentially and increased three percent YTD 2024-over-YTD 2023, primarily as a result of an increase in total realized price per BOE.

Our overall production tax rate for the three and six months ended June 30, 2024, was 4.3 percent and 4.4 percent, respectively, compared with 4.5 percent for each of the three months ended March 31, 2024, and the six months ended 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 eight percent sequentially and increased five percent YTD 2024-over-YTD 2023, as a result of changes to the assessed values of our producing properties.

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 remained flat sequentially.

DD&A expense on a per BOE basis increased nine 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.

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 to remain relatively flat and DD&A expense on an absolute basis to increase slightly, compared with 2023, primarily as a result of expected increased production.

General and administrative (“G&A”) expense on a per BOE basis decreased six percent sequentially primarily as a result of increased net equivalent production volumes.

G&A expense on a per BOE basis increased nine percent YTD 2024-over-YTD 2023 as a result of increased compensation expense due to inflation.

For the full-year 2024, we expect G&A expense to remain relatively flat

per BOE, and G&A expense on an absolute basis to increase compared with 2023, primarily as a result of increases in compensation expense due to inflation.

Please refer to Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2024, and March 31, 2024, and Between the Six Months Ended June 30, 2024, and 2023 below for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between the Three Months Ended June 30, 2024, and March 31, 2024, and Between the Six Months Ended June 30, 2024, and 2023

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.

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 June 30, 2024, and March 31, 2024:

Average Net Equivalent Production

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Production Expense

Increase (Decrease)

(MBOE per day) (in millions) (in millions)

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Amounts may not calculate due to rounding.

Average net daily equivalent production volumes increased nine percent, consisting of increases of 12 percent and seven percent from our South Texas and Midland Basin assets, respectively.

Total realized price per BOE increased four percent.

As a result of the increase in average net daily equivalent production volumes, oil, gas, and NGL production revenue increased 13 percent.

Oil, gas, and NGL production expense remained flat, as increases in production tax expense and transportation costs were offset by a decrease in LOE.

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.

Average Net Equivalent Production Increase (Decrease) Oil, Gas, and NGL

Average Net Equivalent Production

Increase Oil, Gas, and NGL

Production Revenue

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Amounts may not calculate due to rounding.

Average net daily equivalent production volumes remained flat, as a five percent increase from our Midland Basin assets was mostly offset by a three percent decrease from our South Texas assets.

Total realized price per BOE increased five percent and, combined with increases in oil and NGL benchmark commodity prices, resulted in a seven 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 increases in LOE and production tax expense.

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.

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

For the Three Months Ended For the Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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 eight percent sequentially and 11 percent YTD 2024-over-YTD 2023.

The sequential quarterly increase was primarily driven by an increase in average net daily equivalent production.

The YTD 2024-over-YTD 2023 increase resulted from 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.

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.

For the Three Months Ended For the Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

For the Three Months Ended For the Nine Months Ended

September 30, 2024 June 30,

2024 September 30, 2024 September 30, 2023

(in millions)

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Total $ 12.1 $ 17.1 $ 47.8 $ 43.6

Exploration expense decreased eight percent sequentially primarily as a result of expenses incurred related to one well deemed non-commercial, which primarily affected the three months ended March 31, 2024, partially offset by an increase in exploration overhead expense.

The YTD 2024-over-YTD 2023 increase of seven percent was primarily due to an increase in geological and geophysical expense.

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 Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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 three percent sequentially and 11 percent YTD 2024-over-YTD 2023 as a result of increases in compensation expense, and inflation.

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 Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

For the Three Months Ended For the Nine Months Ended

September 30, 2024 June 30,

2024 September 30, 2024 September 30, 2023

(in millions)

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Interest expense

For the Three Months Ended For the Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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 remained flat sequentially and decreased two percent YTD 2024-over-YTD 2023.

Total interest expense can vary based on 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.

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 Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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)

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Effective tax rate 19.2 % 20.3 % 19.7 % 8.3 %

The sequential quarterly increase in the effective tax rate is primarily due to the effect of higher forecast net income.

The YTD 2024-over-YTD 2023 decrease in the effective tax rate is primarily due to the benefit recognized from anticipated qualified R&D credit claims in 2024.

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.

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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.

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 , and Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on July 18, 2024, for additional discussion.

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

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Sources of Cash

For the six months ended June 30, 2024, we funded our capital expenditures and return of capital program with cash flows from operating activities and cash on hand, and we expect that to continue for the remainder of 2024.

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.

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.

Subsequent to June 30, 2024, we issued our New Senior Notes.

Please see below for discussion on the intended use of the net proceeds received, and refer to Note 5 - Long-Term Debt in Part I, Item I of this report for additional discussion.

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.

Any future downgrades in our credit ratings could make it more difficult or expensive 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.

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Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion.

As of June 30, 2024, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively.

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 scheduled borrowing base redetermination date is October 1, 2024.

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 June 30, 2024, 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 July 31, 2024, June 30, 2024, and December 31, 2023.

We had no revolving credit facility borrowings during the six months ended June 30, 2024, or at any time during 2023.

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

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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 Six Months Ended

June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023

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 %

Our weighted-average interest rate and our weighted-average borrowing rate each remained flat both sequentially and YTD 2024-over-YTD 2023.

We expect our weighted-average interest rate and weighted-average borrowing rate to remain relatively flat for the full-year 2024 compared with 2023.

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.

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.

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.

We use cash for the development, exploration, and acquisition of oil and gas properties;

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Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources.

During the six months ended June 30, 2024, we spent $655.0 million on capital expenditures.

This amount differs from the costs incurred amount of $652.1 million for the six months ended June 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.

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, which we expect to fund with cash flows from operations, is expected to be between $1.14 billion and $1.18 billion, excluding acquisitions, and excluding any expected capital expenditures related to the Uinta Basin Assets and the Option Assets.

Upon execution of the XCL Acquisition Agreement on June 27, 2024, we deposited with an escrow agent a cash deposit of $102.0 million equal to five percent of our undivided 80 percent of the XCL Purchase Price.

On July 25, 2024, we issued a redemption notice irrevocably obligating us to redeem all of our outstanding 2025 Senior Notes.

We intend to use a portion of the net proceeds from our New Senior Notes to redeem all of our outstanding 2025 Senior Notes, and the remaining net proceeds from the New Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund the balance of the XCL Purchase Price.

Please refer to Note 5 - Long-Term Debt and Note 11 - Acquisitions in Part I, Item I of this report for additional discussion.

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.

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The amounts involved in any such transaction may be material.

During the six months ended June 30, 2024, and 2023, we repurchased and subsequently retired 1.8 million and 4.0 million shares, respectively, of our common stock at a cost of $84.0 million and $108.8 million, respectively, excluding excise taxes, commissions, and fees.

Additionally, in the second quarter of 2024, our Board of Directors re-authorized our existing Stock Repurchase Program, authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2027.

As of June 30, 2024, following the re-authorization of our existing Stock Repurchase Program, $500.0 million was available under the Stock Repurchase Program.

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 six months ended June 30, 2024, and 2023, we paid $41.5 million and $36.4 million, respectively, in dividends to our stockholders.

Additionally, our Board of Directors approved an increase to our fixed dividend policy, pursuant to which we intend to pay $0.80 per share annually, to be paid in quarterly increments of $0.20 per share, beginning in the fourth quarter of 2024.

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.

Changes in federal income tax laws could increase our corporate income tax rate and could eliminate or reduce current tax deductions.

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The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding.

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2024, and 2023

The following tables present changes in cash flows between the six months ended June 30, 2024, and 2023, for our operating, investing, and financing activities.

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 Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended September 30, Amount Change Between Periods

(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 six months ended June 30, 2024, compared with the same period in 2023, primarily as a result of a $46.6 million increase in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and a decrease of $34.4 million in cash paid on settled derivative trades, partially offset by an increase of $20.3 million in cash paid for G&A expense.

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 Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended September 30, Amount Change Between Periods

(in millions)

Net cash used in investing activities $ (957.9) $ (875.4) $ (82.5)

Net cash used in investing activities increased for the six months ended June 30, 2024, compared with the same period in 2023, as a result of a $105.0 million increase in capital expenditures, partially offset by an $88.8 million decrease in cash paid to acquire proved and unproved oil and gas properties in the Midland Basin.

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 Six Months Ended June 30, Amount Change Between Periods

For the Nine Months Ended September 30, Amount Change Between Periods

(in millions)

Net cash used in financing activities $ (123.7) $ (143.4) $ 19.7

Net cash used in financing activities for the six months ended June 30, 2024, primarily related to $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 $41.5 million of dividends paid to our stockholders.

Net cash used in financing activities for the six months ended June 30, 2023, related to $108.9 million of cash paid, including commissions and fees, to repurchase and subsequently retire 4.0 million shares of our common stock under the Stock Repurchase Program and $36.4 million of dividends paid to our stockholders.

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 on our revolving credit facility.

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 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 June 30, 2024, our outstanding principal amount of fixed-rate debt totaled $1.6 billion, and we had no floating-rate debt outstanding.

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.

As a result of the United States Federal Reserve’s current monetary policy, short-term interest rates could remain elevated longer than expected, which could increase the cost of and affect our ability to borrow funds.

Commodity Price Risk

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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+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, and the potential impacts of these issues on global commodity and financial markets.

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 six months ended June 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 $97.3 million, $11.3 million, and $10.7 million, respectively.

If commodity prices had been 10 percent lower, our net derivative settlements for the six months ended June 30, 2024, would have offset the declines in oil, gas, and NGL production revenue by approximately $16.4 million.

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 June 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 $51.7 million, $28.1 million, and $5.6 million, respectively.

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

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If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements.

We have not been involved in any unconsolidated SPE transactions during the six months ended June 30, 2024, or through the filing of this report.

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

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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 Six Months Ended

2024 June 30,

2023 June 30,

2024 June 30,

For the Three Months Ended For the Nine Months Ended

September 30,

2024 September 30,

2023 September 30,

2024 September 30,

(in thousands)

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Interest income (18,017) (4,106) (31,120) (13,802)

Income tax expense 53,590 42,092 85,659 97,598

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

3 unchanged sentences

Net derivative (gain) loss (86,283) 75,355 (70,256) 12,352

Net derivative settlement gain 16,523 15,636 29,797 20,712

Net derivative settlement gain (loss) 16,491 (314) 46,288 20,398

Other, net 706 698 2,126 1,625

2 unchanged sentences

Interest income 18,017 4,106 31,120 13,802

Income tax expense (53,590) (42,092) (85,659) (97,598)

Income tax (expense) benefit (57,127) 45,979 (142,786) (51,619)

Exploration (1) (2)

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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 six months ended June 30, 2024, amounts exclude certain capital expenditures primarily related to one well deemed non-commercial.

For the three and six months ended June 30, 2023, amounts exclude certain capital expenditures primarily related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase.

(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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis