SM Energy Co
For the period ended Dec 31, 2024. Filed Feb 20, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 20, 2025
SM$29.92+1.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-22.
0000893538-24-000009
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverview of the CompanyFinancial Results of Operations and Additional Comparative DataComparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021Overview of Liquidity and Capital ResourcesCritical Accounting EstimatesAccounting MattersEnvironmentalNon-GAAP Financial MeasuresCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-20.
0000893538-25-000008
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverview of the CompanyFinancial Results of Operations and Additional Comparative DataComparison of Financial Results and Trends Between 2024 and 2023, and Between 2023 and 2022Overview of Liquidity and Capital ResourcesCritical Accounting EstimatesAccounting MattersEnvironmentalNon-GAAP Financial MeasuresThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 176 previous paragraphs and 163 current paragraphs.
69 unchanged; 76 reworded; 18 added; 25 removed; 6 previous and 0 current paragraphs rearranged.
Tables are not compared: 27 previous and 25 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (18)
Current report
•We expanded our operations into Utah upon the completion of the Uinta Basin Acquisition during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.
Current report
•Our Board of Directors approved an increase to our fixed dividend to $0.80 per share annually, to be paid in quarterly increments of $0.20 per share, which commenced in the fourth quarter of 2024. We paid a net cash dividend of $0.74 per share, an increase from $0.60 per share paid during 2023. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.
Current report
•During the first half of 2024, we repurchased and subsequently retired 1.8 million shares of our common stock at a cost of $84.0 million, excluding excise taxes, commissions, and fees. In June 2024, our Board of Directors re-authorized our existing Stock Repurchase Program, and as of December 31, 2024, $500.0 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion.
Current report
$720.9 million, or 21 percent, of our total 2024 costs incurred. Drilling and completion activities focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.
Current report
In our Uinta Basin program, we averaged three drilling rigs and one completion crew during the fourth quarter of 2024. Average net daily equivalent production volumes totaled 36.1 MBOE for the fourth quarter of 2024, or 9.1 MBOE if calculated over the full year 2024. Costs incurred during 2024 totaled $2.3 billion, or 65 percent, of our total 2024 costs incurred, of which, over $2.1 billion related to acquisition costs. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.
Current report
(2) We acquired these drilled but not completed wells as part of the Uinta Basin Acquisition on October 1, 2024. All drilling and completion activity presented in the table above for the Uinta Basin occurred during the fourth quarter of 2024. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and the definition of the Uinta Basin Acquisition.
Current report
Average net daily equivalent production volumes for the year ended December 31, 2024, increased 12 percent compared with 2023, comprised of a seven percent increase from our Midland Basin assets, a six percent increase from our South Texas assets, and 9.1 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and gas prices, realized prices for oil and gas decreased two percent and 27 percent, respectively, while the realized price for NGLs remained flat. The 13 percent increase in oil, gas, and NGL production revenue is primarily a result of the increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2024, increased 13 percent compared with 2023, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.
Current report
Depletion, depreciation, and amortization
Current report
Interest expense increased 54 percent for the year ended December 31, 2024, compared with 2023, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, an increase in interest expense associated with borrowings under our revolving credit facility, 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 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. Refer to Overview of Liquidity and Capital Resources below, Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Current report
Interest income increased for the year ended December 31, 2024, compared with 2023, primarily due to maintaining a higher average balance of our interest-bearing cash and cash equivalents as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 resulting in excess cash prior to the Closing Date of the Uinta Basin Acquisition. Refer to Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Current report
Our effective tax rate in 2023 benefited from credits claimed as the result of the completion of a multi-year research and development (“R&D”) credit study. Excess tax deficiencies from stock-based compensation awards offset limits on expensing of certain covered individual’s compensation, net apportionment changes and other permanent expense items reduced the rate for each period presented. We benefited from the release of a valuation allowance on certain deferred tax assets in 2022.
Current report
During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Current report
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. 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. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Current report
Refer to Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Current report
During 2024, we redeemed all of the $349.1 million of aggregate principal amount outstanding of our 2025 Senior Notes. Additionally, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Refer to Significant Developments in 2024 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Acquisitionsin Part II, Item 8 of this report for additional discussion and definitions.
Current report
Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion of acquisition activity and the definition of the Uinta Basin Acquisition.
Current report
Net cash provided by financing activities increased during the year ended December 31, 2024, primarily related to net cash proceeds of $1.5 billion from the issuance of our 2029 Senior Notes and 2032 Senior Notes, and net borrowings under our revolving credit facility of $68.5 million, partially offset by $349.1 million of cash paid to redeem our 2025 Senior Notes. Additionally, we paid $86.1 million, including commission and fees, to repurchase and subsequently retire 1.8 million shares of our common stock under the Stock Repurchase Program, and paid $85.0 million of dividends to our stockholders.
Removed paragraphs (25)
Previous report
During 2023, we increased the amount of capital we returned to our stockholders, compared with 2022, through repurchases of our outstanding common stock under our Stock Repurchase Program and our fixed quarterly dividend payments, and we expanded our Midland Basin asset position. During the year ended December 31, 2023, we repurchased and subsequently retired 6.9 million shares of our common stock at a cost of $228.0 million, excluding excise taxes, commissions, and fees; we paid dividends of $0.60 per share, an increase from $0.16 per share paid during the year ended December 31, 2022; and we announced a 20 percent increase to our fixed dividend to $0.72 per share annually, to be paid in quarterly increments of $0.18 per share, beginning in the first quarter of 2024. Additionally, we executed strategic acquisitions, exchanges, and leasing activity in the Midland Basin, enabling us to enhance our capital efficiency by blocking up acreage and maintaining high working interests. Please refer to Note 3 – Equity and Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.
Previous report
(2) Amount relates to additional working interests acquired in drilled but not completed wells during the year ended December 31, 2023.
Previous report
Acquisition Activity. During 2023, we acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. Additionally, in the Midland Basin, we added approximately 9,100 net acres through organic leasing activity, we completed an asset exchange, and we acquired additional working interests in certain wells. Please refer to Note 16 – Acquisitions in Part II, Item 8 of this report for additional discussion.
Previous report
Average net daily equivalent production volumes for the year ended December 31, 2022, increased three percent compared with 2021, comprised of a 37 percent increase from our South Texas assets, partially offset by a 14 percent decrease from our Midland Basin assets. As a result of increases in benchmark commodity prices, realized prices for oil, gas, and NGLs increased 40 percent, 29 percent, and six percent, respectively, resulting in a 29 percent increase in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense for the year ended December 31, 2022, increased 23 percent, compared with 2021, primarily as a result of increased production taxes and LOE.
Previous report
Depletion, depreciation, amortization, and asset retirement obligation liability accretion
Previous report
Impairment
Previous report
No impairment expense was recorded for the year ended December 31, 2023, as a result of fewer actual and anticipated lease expirations and title defects. Impairment expense recorded during the years ended December 31, 2022, and 2021, consisted of unproved property abandonments and impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks.
Previous report
We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.
Previous report
Reserve estimates and related impairments of proved and unproved properties are difficult to predict in a volatile price environment. If commodity prices for the products we produce decline as a result of supply and demand fundamentals associated with geopolitical or macroeconomic events, we may experience proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of February 8, 2024, we do not expect any material oil and gas property impairments in the first quarter of 2024 resulting from commodity price impacts.
Previous report
Other operating expense, net
Previous report
Other operating expense, net, recorded in 2023 and 2021, primarily related to legal matters.
Previous report
Interest expense decreased 24 percent for the year ended December 31, 2023, compared with 2022, as a result of the reduction in the aggregate principal amount of our Senior Notes through various transactions in 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the redemption of our 2025 Senior Secured Notes on June 17, 2022. Total interest expense can vary based on 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 II, Item 8 of this report for additional discussion, including the definition of Senior Notes and 2025 Senior Secured Notes.
Previous report
Interest income increased for the year ended December 31, 2023, compared with 2022, due to an increase in average interest rates on our interest-bearing cash equivalents and a higher average cash and cash equivalents balance during 2023.
Previous report
Our effective tax rate decreased for the year ended December 31, 2023, compared with 2022, primarily due to benefits recognized as a result of a multi-year research and development (“R&D") credit study conducted during 2023, partially offset by the release of the valuation allowance during the year ended December 31, 2023, that lowered the effective tax rate compared to no valuation benefit recognized during the year ended December 31, 2022.
Previous report
The decrease in the effective tax rate for the year ended December 31, 2022, compared with 2021, primarily resulted from the release of the valuation allowance recorded against the derivative deferred tax asset recognized in prior periods. As a result of the increase in income before income taxes for the year ended December 31, 2022, compared with 2021, our permanent items, including excess tax benefits from stock-based compensation and limits on expensing of certain individual’s compensation, had less of an impact on the effective tax rate for the year ended December 31, 2022, compared with 2021.
Previous report
Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit ratings during 2023, citing our ability to consistently generate meaningful cash flows, disciplined capital spending, return of capital to stockholders, debt redemptions during 2022, and sustained strong operational performance, including our established inventory of drilling locations in our Midland Basin and South Texas programs, all of which contribute to our strong liquidity profile.
Previous report
Net cash used in investing activities during the years ended December 31, 2023, 2022, and 2021, was funded by net cash provided by operating activities.
Previous report
During the year ended December 31, 2021, we paid $385.3 million, including net premiums, to fund the Tender Offer and the 2022 Senior Notes Redemption, and we received net cash proceeds of $392.8 million from the issuance of our 2028 Senior Notes. Additionally, we paid $65.5 million to retire our 2021 Senior Secured Convertible Notes and had net repayments under our revolving credit facility of $93.0 million.
Previous report
The Federal Reserve increased short-term interest rates during 2023 and 2022. These increases, and any future increases, are likely to increase the cost of and affect our ability to borrow funds.
Previous report
Unproved oil and gas properties are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and our intent to renew leases. We estimate the fair value of unproved properties using a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by us or other market participants.
Previous report
Please refer to Note 1 – Summary of Significant Accounting Policiesand Note 8 – Fair Value Measurements in Part II, Item 8 of this report for discussion of impairments of oil and gas properties recorded for the years ended December 31, 2022, and 2021.
Previous report
Revenue Recognition. We predominately derive our revenue from the sale of produced oil, gas, and NGLs. Our revenue recognition policy is a critical accounting estimate because revenue is a key component of our results of operations and our forward-looking statements contained in our analysis of liquidity and capital resources. A 10 percent change in our revenue accrual at year-end 2023 would have affected total operating revenues by approximately $17.5 million for the year ended December 31, 2023. Please refer to Note 1 – Summary of Significant Accounting Policiesand Note 2 – Revenue from Contracts with Customersin Part II, Item 8 of this report for additional discussion.
Previous report
Derivative Financial Instruments. We periodically enter into commodity derivative contracts to mitigate a portion of our exposure to oil, gas, and NGL price volatility and location differentials. We recognize all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income
Previous report
(loss). The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The values we report in our consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Please refer to Note 1 – Summary of Significant Accounting Policiesand Note 7 – Derivative Financial Instrumentsin Part II, Item 8 of this report for additional discussion.
Previous report
Income Taxes. We account for deferred income taxes, whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using currently enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. We record deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement as well as significant enacted tax rate changes could have an impact on our results of operations. A one percent change in our effective tax rate would have changed our calculated income tax expense by approximately $9.1 million for the year ended December 31, 2023. Please refer to Note 1 – Summary of Significant Accounting Policiesand Note 4 – Income Taxesin Part II, Item 8 of this report for additional discussion.
Reworded paragraphs (76)
Previous wording
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.
Current wording
The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements.
Previous wording
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 continuing to return value to stockholders through our Stock Repurchase Program and fixed dividend payments, and by focusing on continued operational excellence.
Current wording
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 operational execution and successfully integrating the Uinta Basin assets; generating cash flows that enable us to continue returning value to stockholders through fixed dividend payments, debt repayments, and our Stock Repurchase Program; and expanding our portfolio of top-tier economic drilling inventory through acquisition and exploration.
Previous wording
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that 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, 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.
Current wording
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas, the Maverick Basin of South Texas, and the Uinta Basin of northeastern 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, including 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. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for additional discussion and for the definition of the Uinta Basin Acquisition.
Previous wording
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 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 issues, 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. Please refer to our Definitive Proxy Statement on Schedule 14A for the 2024 annual meeting of stockholders to be filed within 120 days from December 31, 2023, for additional discussion.
Current wording
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 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. Refer to our Definitive Proxy Statement on Schedule 14A for the 2025 annual meeting of stockholders to be filed within 120 days from December 31, 2024, for additional discussion of our compensation programs.
Previous wording
We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. While the rate of inflation in the United States has decreased since the beginning of the year and the average rate of inflation in 2023 was lower than it was in 2022, inflation continues to impact certain aspects of our business. Continued oil production curtailment agreements among 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. Future impacts of these and other events on commodity and financial markets are inherently unpredictable. 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.
Current wording
We are affected 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 OPEC+, fluctuations in oil and gas demand from China, War and Geopolitical Instability, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, tariffs or trade restrictions, 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. Future impacts of these and other events on commodity and financial markets are inherently unpredictable. 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 generating cash flows to enable us to return capital to stockholders and reduce our debt.
Previous wording
We expect our total 2024 capital program to be between $1.16 billion and $1.20 billion, excluding acquisitions, which we expect to fund with cash flows from operations and cash on hand. We plan to focus our 2024 capital program on highly economic oil development projects in both our Midland Basin and South Texas assets, including the assets we acquired during 2023. We expect to repurchase additional shares of our outstanding common stock through our Stock Repurchase Program during 2024, under which $214.9 million remains available for repurchases through December 31, 2024, as of the filing of this report.
Current wording
We expect our total 2025 capital program to be approximately $1.3 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2025 capital program on highly economic oil development projects in our Midland Basin, South Texas, and Uinta Basin assets. Refer to Outlookin Part I, Items 1 and 2 of this report for additional discussion.
Previous wording
During 2022, we redeemed all of the aggregate principal amount outstanding of our 2024 Senior Notes and our 2025 Senior Secured Notes. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.
Current wording
•We issued a combined $1.5 billion of aggregate principal amount of our 2029 Senior Notes and 2032 Senior Notes and redeemed the remaining $349.1 million aggregate principal amount outstanding of our 2025 Senior Notes. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.
Previous wording
Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2023, increased five percent to 152.0 MBOE, compared with 145.1 MBOE for 2022 as a result of an increased number of completions in 2023 compared with 2022. The total increase consisted of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. These changes were a result of the timing of well completions, and the timing of capital expenditures during 2022 and 2023.
Current wording
Financial and Operational Results. Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent to 170.5 MBOE, compared with 152.0 MBOE for 2023, as a result of strong well performance, an increased number of completions, and production from our Uinta Basin assets during the fourth quarter of 2024. The increase primarily consisted of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 9.1 MBOE of production from our Uinta Basin assets.
Previous wording
Realized prices for oil, gas, and NGLs decreased 19 percent, 61 percent, and 35 percent, respectively, for the year ended December 31, 2023, compared with 2022, as a result of decreases in benchmark commodity prices during 2023. Total realized price per BOE decreased 33 percent for the year ended December 31, 2023, compared with 2022, resulting in a 29 percent decrease in oil, gas, and NGL production revenue, which was $2.4 billion for the year ended December 31, 2023, compared with $3.3 billion for 2022. Oil, gas, and NGL production expense of $10.16 per BOE for the year ended December 31, 2023, decreased 13 percent compared with 2022, primarily as a result of decreases in production tax expense per BOE, transportation costs per BOE, and ad valorem tax expense per BOE, partially offset by an increase in LOE per BOE.
Current wording
Realized prices for oil and gas decreased two percent and 27 percent, respectively, for the year ended December 31, 2024, compared with 2023, as a result of decreases in oil and gas benchmark commodity prices. Realized price for NGLs remained flat for the year ended December 31, 2024, compared with 2023. Total realized price per BOE remained flat for the year ended December 31, 2024, compared with 2023, primarily driven by a 24 percent increase in oil production, offset by decreases in oil and gas benchmark commodity prices. Oil, gas, and NGL production revenue increased 13 percent to $2.7 billion for the year ended December 31, 2024, compared with $2.4 billion for 2023, primarily as a result of the timing of well completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil, gas, and NGL production expense of $10.21 per BOE for the year ended December 31, 2024, remained flat, compared with 2023.
Previous wording
We recorded a net derivative gain of $68.2 million for the year ended December 31, 2023, compared to a net derivative loss of $374.0 million for 2022. These amounts include a net derivative settlement gain of $26.9 million for the year ended December 31, 2023, and a net derivative settlement loss of $710.7 million for the year ended December 31, 2022.
Current wording
We recorded net derivative gains of $50.0 million and $68.2 million for the years ended December 31, 2024, and 2023, respectively. These amounts include net derivative settlement gains of $68.7 million and $26.9 million for the years ended December 31, 2024, and 2023, respectively.
Previous wording
•Net cash provided by operating activities of $1.6 billion, compared with $1.7 billion for 2022.
Current wording
•Net cash provided by operating activities of $1.8 billion, compared with $1.6 billion for 2023.
Previous wording
•Net income of $817.9 million, or $6.86 per diluted share, compared with net income of $1.1 billion, or $8.96 per diluted share for 2022.
Current wording
•Net income of $770.3 million, or $6.67 per diluted share, compared with net income of $817.9 million, or $6.86 per diluted share for 2023.
Previous wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $1.7 billion, compared with $1.9 billion for 2022. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Current wording
•Adjusted EBITDAX, a non-GAAP financial measure, of $2.0 billion, compared with $1.7 billion for 2023. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Previous wording
•Total estimated net proved reserves as of December 31, 2023, increased 13 percent from December 31, 2022, to 604.9 MMBOE, of which, 58 percent were liquids (oil and NGLs) and 56 percent were proved developed reserves. The increase primarily consisted of revisions of previous estimates of 113.9 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 55.5 MMBOE of production during 2023. Our proved reserve life index increased to 10.9 years as of December 31, 2023, compared with 10.1 years as of December 31, 2022. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $6.3 billion as of December 31, 2023, compared with $10.0 billion as of December 31, 2022, which was a decrease of 37 percent year-over-year primarily driven by decreases in benchmark commodity prices during 2023. Please refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Current wording
•A 12 percent increase in total estimated net proved reserves as of December 31, 2024, from December 31, 2023, to 678.3 MMBOE, of which, 62 percent were liquids (oil and NGLs) and 60 percent were proved developed reserves. The increase primarily consisted of the acquisition of 103.2 MMBOE of estimated net proved reserves in the Uinta Basin and revisions of previous estimates of 74.7 MMBOE related to infill reserves in both our South Texas and Midland Basin programs, partially offset by 62.4 MMBOE of production during 2024 and the removal of 30.5 MMBOE of certain net proved undeveloped reserves cases that are no longer expected to be developed within the five-year period from initial booking, as a result of the reallocation of capital to include our Uinta Basin assets. Our proved reserve life index remained flat at 10.9 years as of December 31, 2024, and 2023. Refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $7.3 billion as of December 31, 2024, compared with $6.3 billion as of December 31, 2023, which was an increase of 16 percent year-over-year primarily driven by the Uinta Basin Acquisition, partially offset by decreases in oil and gas benchmark commodity prices during 2024. Refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Previous wording
Operational Activities. During 2023, successful operational execution resulted in strong well performance in the RockStar and Sweetie Peck areas of our Midland Basin position, and allowed us to maximize capital efficiency. Our South Texas program benefited from continued successful delineation and development of the Austin Chalk formation in addition to sustained strong performance of our Eagle Ford shale wells. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.
Current wording
Operational Activities. During 2024, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in both our Midland Basin and South Texas programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation. During the fourth quarter of 2024, we began integrating our Uinta Basin assets where we focused on delineation and development.
Previous wording
In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2023. We added a fourth drilling rig at the end of the third quarter to begin drilling on our newly acquired Klondike acreage. We drilled 54 gross (37 net) wells, completed 64 gross (54 net) wells, and acquired additional working interests in five net wells during 2023. Average net daily equivalent production volumes decreased year-over-year by seven percent to 75.4 MBOE. Costs incurred during 2023 totaled $768.1 million, or 62 percent of our total 2023 costs incurred. Drilling and completion activities within our RockStar and Sweetie Peck positions in the Midland Basin were focused primarily on developing the Spraberry and Wolfcamp formations.
Current wording
In our Midland Basin program, we averaged four drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by seven percent to 80.5 MBOE. Costs incurred during 2024 totaled
Previous wording
In our South Texas program, we averaged two drilling rigs and one completion crew during 2023. We drilled 46 gross (46 net) wells and completed 38 gross (37 net) wells during 2023. Average net daily equivalent production volumes increased year-over-year by 20 percent to 76.7 MBOE. Costs incurred during 2023 totaled $423.5 million, or 34 percent of our total 2023 costs incurred. Drilling and completion activities in South Texas during 2023 were primarily focused on delineating and developing the Austin Chalk formation.
Current wording
In our South Texas program, we averaged two drilling rigs and one completion crew during 2024. Average net daily equivalent production volumes increased year-over-year by six percent to 81.0 MBOE. Costs incurred during 2024 totaled $478.3 million, or 14 percent, of our total 2024 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.
Previous wording
(1) Please refer to the caption Costs Incurredin Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report.
Current wording
(1) Refer to the caption Costs Incurredin Supplemental Oil and Gas Information (unaudited)in Part II, Item 8 of this report.
Previous wording
Net equivalent production increased five percent for the year ended December 31, 2023, compared with 2022, comprised of a 20 percent increase from our South Texas assets, partially offset by a seven percent decrease from our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 below for additional discussion of production.
Current wording
Net equivalent production increased 12 percent for the year ended December 31, 2024, compared with 2023, comprised of increases of seven percent and six percent from our Midland Basin and South Texas assets, respectively, and 3.3 MMBOE of production during the fourth quarter of 2024 from our Uinta Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trendsand Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional discussion of production.
Previous wording
Oil prices in 2023 decreased compared with 2022 and increased compared with 2021. Gas and NGL prices in 2023 decreased compared with both 2022 and 2021. 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 oil inventory in storage, and the potential impacts of these issues on global commodity and financial 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. Our realized prices at local sales points may also be affected by infrastructure capacity in the areas of our operations and beyond.
Current wording
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, fluctuations in oil and gas demand from China, War and Geopolitical Instability, changes in global oil inventory in storage, tariffs or trade restrictions, 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 in the areas of our operations and beyond.
Previous wording
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 II, Item 8 of this report and to Commodity Price Riskin Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Current wording
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. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Riskin Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.
Previous wording
(3) Please refer to Note 9 – Earnings Per Sharein Part II, Item 8 of this report for additional discussion.
Current wording
(3) Refer to Note 9 – Earnings Per Sharein Part II, Item 8 of this report for additional discussion.
Previous wording
Average net daily equivalent production for the year ended December 31, 2023, increased five percent compared with 2022, as a result of an increased number of completions. In 2024, we expect total production volumes to increase slightly compared with 2023, and we expect a slight increase in oil as a percentage of total production. Please refer to Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 below for additional discussion.
Current wording
Average net daily equivalent production for the year ended December 31, 2024, increased 12 percent compared with 2023, as a result of an increased number of completions, strong well performance, and production from our Uinta Basin assets during the fourth quarter of 2024. Oil production as a percentage of total production increased to 47 percent in 2024 from 43 percent in 2023, as a result of increased oil production from both our Midland Basin and South Texas assets, in addition to oil production from our Uinta Basin assets. In 2025, we expect total production volumes and oil as a percentage of total production to each increase compared with 2024. Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 below for additional discussion.
Previous wording
Our realized price on a per BOE basis decreased $20.58 for the year ended December 31, 2023, compared with 2022, as a result of decreases in oil, gas, and NGL benchmark prices. For the year ended December 31, 2023, we recognized a net gain on the settlement of our commodity derivative contracts of $0.49 per BOE, compared to a net loss of $13.42 per BOE for the same period in 2022.
Current wording
Our realized price on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, primarily because a 24 percent increase in oil production was offset by decreases in oil and gas benchmark commodity prices. For the years ended December 31, 2024, and 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.10 per BOE and $0.49 per BOE, respectively.
Previous wording
LOE on a per BOE basis increased two percent for the year ended December 31, 2023, compared with 2022, primarily driven by increases in labor costs. For 2024, we expect LOE on a per BOE basis to increase, compared with 2023, primarily as a result of expected increases in certain operating costs associated with both our Midland Basin and South Texas assets. 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, inflation, and industry activity, all of which affect total LOE.
Current wording
LOE on a per BOE basis remained flat for the year ended December 31, 2024, compared with 2023, as increases in labor costs and certain other operating costs were offset by an increase in total net equivalent production and a decrease in workover expense due to the timing of activity. For 2025, we expect LOE on a per BOE basis to increase, compared with 2024, as our product mix continues to shift towards more oil production with our Uinta Basin assets, and as a result of expected increases in certain operating costs associated with our Midland Basin assets. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.
Previous wording
Transportation costs on a per BOE basis decreased 13 percent for the year ended December 31, 2023, compared with 2022, as a result of the expiration of a long-term contract in South Texas on June 30, 2023. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For 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.
Current wording
Transportation costs on a per BOE basis increased nine percent for the year ended December 31, 2024, compared with 2023. This increase was due to a six percent increase in NGL production from our South Texas assets and 3.3 MMBOE of production from our Uinta Basin assets, both of which incur higher transportation costs than our Midland Basin assets. 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 a majority of our transportation costs. For 2025, we expect transportation costs on a per BOE basis to increase, compared with 2024, as a result of the addition of our Uinta Basin assets.
Previous wording
Production tax expense on a per BOE basis for the year ended December 31, 2023, decreased 38 percent compared with 2022, as a result of decreases in realized prices. Our overall production tax rate was 4.4 percent and 4.9 percent for the years ended December 31, 2023, and 2022, respectively. 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.
Current wording
Production tax expense on a per BOE basis for the year ended December 31, 2024, decreased two percent compared with 2023, primarily as a result of a decrease in the realized price of gas. Our overall production tax rate was 4.3 percent and 4.4 percent for the years ended December 31, 2024, and 2023, respectively. 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 a per BOE and absolute 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.
Previous wording
Ad valorem tax expense on a per BOE basis decreased 15 percent for the year ended December 31, 2023, compared with 2022, as we were positively impacted by a property tax relief bill that provided for a one-time benefit during 2023. 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, and can be impacted by changes in tax laws.
Current wording
Ad valorem tax expense on a per BOE basis decreased 16 percent for the year ended December 31, 2024, compared with 2023, as a result of changes to the assessed values of our producing properties due to decreased commodity price assumptions used in the current year valuation, and increased net equivalent production. 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, and can be impacted by changes in tax laws.
Previous wording
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased nine percent for the year ended December 31, 2023, compared with 2022, due to inflation and higher drilling and completion activity in the Midland Basin, partially offset by increased production related to our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. For 2024, we expect DD&A expense per BOE to remain flat, and DD&A expense on an absolute basis to increase slightly, compared with 2023, primarily as a result of expected increased production. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
Current wording
Depletion, depreciation, and amortization (“DD&A”) expense on a per BOE basis increased four percent for the year ended December 31, 2024, compared with 2023, due to a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. For 2025, we expect DD&A expense per BOE and on an absolute basis to increase, compared with 2024, primarily as a result of expected increased production resulting from the addition of our Uinta Basin assets, and a shift in our production mix. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.
Previous wording
General and administrative (“G&A”) expense on a per BOE basis remained relatively flat for the year ended December 31, 2023, compared with 2022, as an increase in G&A expense on an absolute basis related to compensation expense was mostly offset by an increase in production volumes. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability. For 2024, we expect G&A expense per BOE to remain flat, and G&A expense on an absolute basis to increase compared with 2023, primarily as a result of expected increases in compensation expense due to inflation.
Current wording
General and administrative (“G&A”) expense on a per BOE basis increased two percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense, partially offset by a 12 percent increase in average net equivalent production. For 2025, we expect G&A expense on an absolute basis to increase, compared with 2024, primarily as a result of an increase in employee headcount as a result of the Uinta Basin Acquisition and expected increases in compensation expense. We expect G&A expense on a per BOE basis to remain relatively flat, compared with 2024, as the expected increases in G&A expense on an absolute basis are expected to be mostly offset by increases in production. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability. Refer to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Previous wording
Please refer to Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 for additional discussion of operating expenses.
Current wording
Refer to Comparison of Financial Results and Trends Between 2024 and 2023 and Between 2023 and 2022 for additional discussion of operating expenses.
Previous wording
Management’s Discussion and Analysis of Financial Condition and Results of Operationsin Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the SEC on February 23, 2023, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2022, compared with the year ended December 31, 2021.
Current wording
Refer to Comparison of Financial Results and Trends Between 2023 and 2022 and Between 2022 and 2021 in Management’s Discussion and Analysis of Financial Condition and Results of Operationsin Part II, Item 7 of our 2023 Annual Report on Form 10-K, filed with the SEC on February 22, 2024, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2023, compared with the year ended December 31, 2022. Refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 in Management’s Discussion and Analysis of Financial Condition and Results of Operationsin Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the SEC on February 23, 2023, for a detailed discussion of certain comparisons of our financial results and trends for the year ended December 31, 2022, compared with the year ended December 31, 2021.
Previous wording
The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years ended December 31, 2023, and 2022:
Current wording
The following table presents the 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 years ended December 31, 2024, and 2023:
Previous wording
The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the years ended December 31, 2022, and 2021:
Current wording
The following table presents the 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 years ended December 31, 2023, and 2022:
Previous wording
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.
Current wording
Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.
Previous wording
DD&A expense for the year ended December 31, 2023, increased 14 percent, compared with 2022, primarily as a result of inflation and a five percent increase in average net daily equivalent production volumes, partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. DD&A expense for the year ended December 31, 2022, decreased 22 percent, compared with 2021, primarily as a result of increased estimated net proved reserves at the end of 2021 and during 2022, and increased activity in our Austin Chalk program. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.
Current wording
DD&A expense for the year ended December 31, 2024, increased 17 percent compared with 2023, primarily as a result of a combination of increased average net daily equivalent production, including the addition of production from our Uinta Basin assets during the fourth quarter of 2024, and a shift in production mix to our Uinta Basin assets. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. DD&A expense for the year ended December 31, 2023, increased 14 percent compared with 2022, primarily as a result of inflation and a five percent increase in average net daily equivalent production volumes, partially offset by a shift in production mix due to higher activity in our South Texas assets, which have a lower DD&A rate than our Midland Basin assets. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.
Previous wording
Exploration expense increased eight percent for the year ended December 31, 2023, compared with 2022, primarily due to increases in both overhead and geological, geophysical, and other expenses. 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.
Current wording
Exploration expense increased eight percent for the year ended December 31, 2024, compared with 2023, primarily as a result of an increase in geological and geophysical expenses related to our Uinta Basin assets. 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.
Previous wording
G&A expense increased six percent for the year ended December 31, 2023, compared with 2022, primarily as a result of increased compensation expense. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis.
Current wording
G&A expense increased 14 percent for the year ended December 31, 2024, compared with 2023, primarily as a result of increases in certain G&A expenses resulting from the Uinta Basin Acquisition and increased compensation expense. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis, and to Note 17 – Acquisitions in Part II, Item 8 of this report for the definition of the Uinta Basin Acquisition.
Previous wording
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 II, Item 8 of this report for additional discussion.
Current wording
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. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.
Previous wording
$67.2 million, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the unamortized debt discount, and $7.4 million of accelerated expense recognition of the unamortized deferred financing costs. Please refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion, including the definition of 2025 Senior Secured Notes.
Current wording
The redemption of our 2025 Senior Secured Notes during 2022 resulted in a net loss on extinguishment of debt of $67.2 million, which included $33.5 million of premium paid, $26.3 million of accelerated expense recognition of the unamortized debt discount, and $7.4 million of accelerated expense recognition of the unamortized deferred financing costs. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and the definition of 2025 Senior Secured Notes.
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Previous report — wording carried elsewhere
Please refer to Comparison of Financial Results and Trends Between 2022 and 2021 and Between 2021 and 2020 in
Previous report — wording carried elsewhere
Please refer to Critical Accounting Estimates below and Note 8 – Fair Value Measurements in Part II, Item 8 of this report for additional discussion.
Previous report — wording carried elsewhere
The redemption of our 2025 Senior Secured Notes during 2022 resulted in a net loss on extinguishment of debt of
Previous report — wording carried elsewhere
Financial Instruments in Part II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.
Previous report — wording carried elsewhere
$1.1 billion on capital expenditures and on acquisitions of proved and unproved oil and gas properties, including the acquisition of additional working interests in certain wells. This amount differs from the costs incurred amount of $1.2 billion for the year ended December 31, 2023, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Please refer to Costs Incurredin Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.
Previous report — wording carried elsewhere
We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of February 8, 2024, we do not expect any material oil and gas property impairments in the first quarter of 2024 resulting from commodity price impacts.