CNX Resources Corp
For the period ended Dec 31, 2024. Filed Feb 11, 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 11, 2025
CNX$34.92-1.1%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 2024-02-08.
0001070412-24-000015
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-11.
0001070412-25-000049
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe 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 181 previous paragraphs and 176 current paragraphs.
76 unchanged; 74 reworded; 24 added; 30 removed; 1 previous and 2 current paragraphs rearranged.
Tables are not compared: 17 previous and 17 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 (24)
Current report
On January 3, 2025, the Department of the Treasury issued final rules regarding the Inflation Reduction Act’s Section 45V Hydrogen Production Tax Credit. The Department of Treasury's recognition of captured waste coal mine methane (CMM) as a feedstock for hydrogen production is validation of its inherent environmental and economic benefits and an important step in continuing to monetize the value of this unique asset. The Company has now successfully validated the premium pricing that low-carbon intensity waste methane capture (CMM) blends enjoy in the manufacturing, hydrogen production, and power generation sectors. However, CNX believes that the final 45V implementation rules are overly restrictive across a range of feedstocks and do not currently appear to create sufficient economic incentives for the Company to expand its CMM capture operations for hydrogen end use. Notwithstanding the specifics of the 45V rule, the Company intends to utilize this important validation of the product to pursue other incentive pathways across these sectors, as well as establish similar markets in artificial intelligence (AI) data centers, transportation, aviation, voluntary market platforms, and government/regulatory platforms arenas.
Current report
•Total sales volumes of 550.8 Bcfe
Current report
•Shale sales volumes of 511.4 Bcfe
Current report
•On January 21, 2025, the Company closed on a private offering of $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of their principal amount, plus accrued interest from September 1, 2024 to the date of closing. See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Current report
•On January 27, 2025, the Company completed the acquisition of the natural gas upstream and associated midstream business of Apex Energy II, LLC (“the Apex Transaction") for total cash consideration of approximately $505 million, subject to certain adjustments. See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Current report
Net (Loss) Income
Current report
The 9.6 Bcfe decrease in total sales volumes in the period-to-period comparison was primarily due to a 17.7 Bcfe decrease in natural gas sales volumes resulting from normal production declines and the timing of when new wells were turned-in-line after the 2023 period. The decrease was offset, in part, by an 8.5 Bcfe increase in NGL sales volumes primarily due to an increase in ethane recoveries.
Current report
•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a higher annual depletion rate for 2024. The increase in rate is primarily attributable to downward reserve revisions due to adjustments to the five-year development plan that lowered proved undeveloped reserves, price changes, and the sale of various non-operated producing oil and gas assets.
Current report
(Loss) Gain on Commodity Derivative Instruments - Unrealized
Current report
Other Revenue and Operating Income
Current report
•(Loss) equity income from affiliates represents CNX’s share of earnings and losses from various entities, including interests in various oilfield service companies and an interest in a gas-fired generation facility located within CNX’s CBM field.
Current report
SG&A
Current report
•Other includes several one-time items in the period-to-period comparison, including $2 million of expenses for our previously announced radical transparency program and a $3 million charge related to a prior-year sales and use tax audit settlement that occurred in the current period. Both periods also include various other one-time items, none of which are individually material.
Current report
Other (Income) Expense
Current report
•Right of way sales relate to additional revenue generated from the Company's extensive surface rights. The decrease of $4 million in the period-to-period comparison was due to fewer sales in the current period.
Current report
•Professional services increased in the period-to-period comparison primarily due to higher fees associated with various one-time items such as the Apex Transaction that closed on January 27, 2025 (See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).
Current report
•CNX pursues legal recoveries when certain circumstances arise. The increase in litigation recoveries in the period-to-period comparison was the result of various recoveries that occurred in the current period. No such transactions occurred in the prior period.
Current report
The net gain during the year ended December 31, 2023 primarily relates to a $100 million gain on the sale of various non-operated producing oil and gas assets primarily located in the Appalachian Basin to a third party (See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The remaining gain relates to the sale of various non-core assets (primarily rights-of-way and surface acreage), none of which were individually material.
Current report
•On January 27, 2025, the Company completed the Apex Transaction for total cash consideration of approximately $505 million, subject to certain post-closing adjustments. See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Current report
•Net income decreased $1,811 million in the period-to-period comparison.
Current report
•Capital expenditures decreased $139 million primarily due to a decrease in drilling and completions activity in Marcellus Shale.
Current report
•During the year ended December 31, 2024, debt issuance and financing fees increased $15 million primarily due to amending both the CNX and CNXM Credit Facilities. See Note 10 – Revolving Credit Facilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Current report
On January 21, 2025, the Company closed on a private offering of $200 million aggregate principal amount of additional 7.25% senior notes due 2032 at a price of 100.5% of their principal amount, plus accrued interest from September 1, 2024 to the date of closing. See Note 22 – Subsequent Event in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
Current report
Critical Accounting Estimates
Removed paragraphs (30)
Previous report
As previously disclosed, CNX continues to devote resources to the development of unique, proprietary technologies to further enable vertical and horizontal business growth. This includes the development and use of proprietary technology to enhance and alter manufacturing processes for the extraction and delivery of natural gas through the development and commercialization of emerging technologies, as well as the development and sale of environmental attributes from our operations. CNX is also focusing on forging strategic partnerships for the use of low carbon intensity feedstocks and creation of derivative products.
Previous report
On December 15, 2023, citing delays and increasing uncertainty over implementation rules guiding the use of the 45V hydrogen production tax credit provisions of the Inflation Reduction Act (IRA) and an inability to reach final commercial terms with project developers, CNX announced it had ended coordination with the Adams Fork project. The Company continues to evaluate several viable alternative sites in southern West Virginia for clean hydrogen projects.
Previous report
The Company remains committed to supporting the Appalachian Regional Clean Hydrogen Hub (ARCH2) via use of its local, low cost, low carbon intensity feedstock, which is ideal for affordable, clean hydrogen production in historically disadvantaged energy communities across Appalachia. CNX's final investment decision remains contingent upon the future issuance of tax credit guidance that unambiguously supports low carbon intensity feedstock projects that will facilitate development of the regional clean hydrogen hubs, including ARCH2.
Previous report
•Total sales volumes of 560.4 Bcfe.
Previous report
•Shale sales volumes of 519.5 Bcfe.
Previous report
Net Income (Loss)
Previous report
The 19.8 Bcfe decrease in volumes in the period-to period comparison was primarily due to various operational delays and challenges that occurred in 2022 which impacted current period production due to the timing of wells being turned-in-line. The remaining variance is primarily due to normal production declines offset, in part, by an increase in NGL sales volume from new wells turned-in-line and an increase in ethane recoveries.
Previous report
•Transportation, gathering and compression expense increased on a per unit basis primarily due to increased processing fees, increased electrical compression expense, increased repairs and maintenance expense and lower volumes.
Previous report
•Depreciation, depletion and amortization expense decreased on a per unit basis due to a lower annual depletion rate primarily resulting from low-cost reserve additions from development during the 2022 period.
Previous report
•Shale production, ad valorem and other fees were $21 million for the year ended December 31, 2023 compared to $33 million for the year ended December 31, 2022. The decrease in total dollars was primarily due to decreased realized prices on natural gas.
Previous report
•CBM transportation, gathering and compression costs were $66 million for the year ended December 31, 2023 compared to $49 million for the year ended December 31, 2022. The increases in total dollars and unit cost were primarily due to an increase in electrical compression expense and repairs and maintenance expense.
Previous report
Unrealized Gain (Loss) on Commodity Derivative Instruments
Previous report
Other Operating Income
Previous report
•Equity income from affiliates primarily represents CNX’s share of earnings from a 50% interest in a power plant located within CNX’s CBM field. Power generated from the facility is sold into wholesale electricity markets during times of peak energy consumption. Due to the plant consuming coal mine methane gas, the plant qualifies for Pennsylvania Tier I Renewable Energy Credits.
Previous report
•Seismic activity expense for the prior period primarily relates to the acquisition of three-dimensional seismic data.
Previous report
•Long-term equity-based compensation (non-cash) increased in the period-to-period comparison due to an increase in equity awards.
Previous report
•CNX and its subsidiaries are subject to various lawsuits and claims in the normal course of business. CNX accrues the estimated loss for these lawsuits and claims as litigation settlements when the loss is probable and can be estimated. (See Note 20 – Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). The decrease in litigation settlements in the period-to-period comparison was the result of various items, none of which were individually material.
Previous report
Other Expense
Previous report
•Professional services decreased in the period-to-period comparison primarily due to a decrease in legal fees.
Previous report
•Net income increased $1,863 million in the period-to-period comparison.
Previous report
•Capital expenditures increased $114 million primarily due to an increase in drilling and completions activity and an overall increase in costs related to inflation.
Previous report
•During the year ended December 31, 2022, CNX paid $27 million to repurchase $14 million of the 2026 Convertible Notes at 188.0% of the principal amount. See Note 12 – Long-Term Debt in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Previous report
Critical Accounting Policies
Previous report
The Company believes that accounting estimates related to income taxes are “critical accounting estimates” because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income and exercise judgment regarding the amount of financial statement benefit to record for uncertain tax positions. When evaluating whether or not a valuation allowance must be established on deferred tax assets, the Company exercises judgment in determining whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized. The Company considers all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed, including carrybacks, tax planning strategies and reversal of deferred tax assets and liabilities. In making the determination related to uncertain tax positions, the Company considers the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that an uncertain tax position or valuation allowance is established or increased or decreased during a period, the Company must include an expense or benefit within tax expense in the income statement. Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions.
Previous report
Impairment of Definite-Lived Intangible Assets
Previous report
Definite-lived intangible assets are amortized on a straight-line basis over their estimated economic lives and they are reviewed for impairment when indicators of impairment are present. Impairment tests require that the Company first compare future undiscounted cash flows to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the asset to its estimated fair value is required. There were no impairments related to definite-lived intangible assets in the years ended December 31, 2023 or 2022.
Previous report
The Company believes that the accounting estimates related to the impairment of definite-lived intangible assets are “critical accounting estimates” because the fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. The Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate; however, different assumptions and estimates could materially impact the calculated fair value and the resulting determinations about the impairment of definite-lived intangible assets which could materially impact the Company’s results of operations and financial position. Additionally, future estimates may differ materially from current estimates and assumptions.
Previous report
Derivative Instruments.
Previous report
We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of natural gas production. See Note 18 – Fair Value of Financial Instruments to the Consolidated Financial Statements for a description of the fair value hierarchy. The values reported in the Consolidated Financial Statements change as these estimates are revised to reflect actual results or as market conditions or other factors, many of which are beyond our control, change.
Previous report
We believe derivative instruments are "critical accounting estimates" because our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments due to the volatility of both NYMEX natural gas prices and basis. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. Refer to Item 7A., "Quantitative and Qualitative Disclosures about Market Risk" of this Form 10-K for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.
Reworded paragraphs (74)
Previous wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Form 10-K. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward‑looking statements that are based on the views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from such forward‑looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see “Part I. Item 1A. Risk Factors” and the section entitled “Forward‑Looking Statements.” CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Current wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this Form 10-K. The information provided below supplements, but does not form part of, CNX's financial statements. This discussion contains forward‑looking statements that are based on the views and beliefs of management, as well as assumptions and estimates made by management. Actual results could differ materially from any such forward‑looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact future operating performance or financial condition, please see “Part I. Item 1A. Risk Factors” and the section entitled “Forward‑Looking Statements.” CNX does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Previous wording
CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include global events such as the conflict between Russia and Ukraine and the announcement by the Organization of the Petroleum Exporting Countries (OPEC) to extend production cuts through the first quarter of 2024, both of which have had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-K are not necessarily indicative of future operating results.
Current wording
CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include global events such as the conflict between Russia and Ukraine and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, both of which have had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-K are not necessarily indicative of future operating results.
Previous wording
Heightened levels of inflation, primarily related to steel, diesel fuel and labor, continue to present risk for CNX and the broader natural gas industry. If inflation continues at its current levels or increases further for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, thus having a greater impact on our financial position. Rising interest rates increased our costs on borrowings under our Credit Facility in 2023, but it is currently anticipated that the Federal Reserve will make cuts to relevant interest rates in 2024. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset any additional cost increases from inflation.
Current wording
The inflationary environment over the last few years, primarily related to steel, diesel fuel and labor, continues to present risk for CNX and the broader natural gas industry. If inflation were to increase materially for any extended period of time, and CNX is unable to successfully mitigate the impact, our costs could increase further, thus having a greater impact on our financial position. CNX remains committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset any additional potential cost increases from inflation.
Previous wording
For the year ended December 31, 2023, CNX had $41 million of sales of environmental attributes which includes items such as (but is not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. These sales are included as part of Other Revenue and Operating Income in the Other Segment. For the year ended December 31, 2023, CNX incurred $7 million of environmental attribute fees which represent costs related to the sale of environmental attributes and are included in Other Operating Expense in the Other Segment.
Current wording
For the years ended December 31, 2024 and 2023, CNX recognized $95 million and $41 million of sales of environmental attributes which includes items such as (but is not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. These sales are included as part of Other Revenue and Operating Income in the Other Segment. For the year ended December 31, 2024 and 2023, CNX incurred $15 million and $7 million of environmental attribute fees which represent costs related to the sale of environmental attributes and are included in Other Operating Expense in the Other Segment.
Previous wording
•Proved developed reserves of 6.0 Tcfe.
Current wording
•Proved developed reserves of 6.1 Tcfe as of December 31, 2024
Previous wording
•Repurchased 17.6 million shares of CNX common stock for $322 million on the open market.
Current wording
•Repurchased 7.2 million shares of CNX common stock for $179 million on the open market at an average price of $24.68.
Previous wording
•Our 2024 annual sales volumes are expected to be approximately 570-590 Bcfe (This includes approximately 15-18 Bcfe of CMM. See New Technologies section in “Item 1. Business” of this Form 10-K for additional information).
Current wording
•Our 2025 annual sales volumes are expected to be approximately 605-620 Bcfe.
Previous wording
•Our 2024 capital expenditures are expected to be approximately $575-$625 million.
Current wording
•Our 2025 capital expenditures are expected to be approximately $450-$500 million.
Previous wording
CNX reported net income of $1,721 million, or earnings per diluted share of $8.99, for the year ended December 31, 2023, compared to a net loss of $142 million, or a loss per diluted share of $0.75, for the year ended December 31, 2022.
Current wording
CNX reported a net loss of $90 million, or a loss per diluted share of $0.60, for the year ended December 31, 2024, compared to net income of $1,721 million, or earnings per diluted share of $8.99, for the year ended December 31, 2023.
Previous wording
Included in earnings for the year ended December 31, 2023 was an unrealized gain on commodity derivative instruments of $1,765 million and a net gain on asset sales and abandonments of $132 million. Included in the loss for the year ended December 31, 2022 was an unrealized loss on commodity derivative instruments of $851 million and a net gain on asset sales and abandonments of $9 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the gain on asset sales and abandonments.
Current wording
Included in the net loss for the year ended December 31, 2024 was an unrealized loss on commodity derivative instruments of $453 million and a net gain on asset sales and abandonments of $25 million. Included in earnings for the year ended December 31, 2023 was an unrealized gain on commodity derivative instruments of $1,765 million and a net gain on asset sales and abandonments of $132 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the gain on asset sales and abandonments.
Previous wording
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations (See Note 21 – Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information). These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Current wording
CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGL and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGL and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGL and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations. These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGL and Oil, including cash settlements, Natural Gas, NGL and Oil Production Costs and Natural Gas, NGL and Oil Production Margin (which is derived by subtracting Natural Gas, NGL and Oil Production Costs from Sales of Natural Gas, NGL and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.
Previous wording
•Production, ad valorem and other fees decreased on a per unit basis primarily due to decreased realized prices on natural gas.
Current wording
•Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense.
Previous wording
The decrease in gross revenue was primarily the result of the $4.07 per Mcf decrease in natural gas prices, when excluding the impact of hedging, the $16.92 per Bbl decrease in NGL prices, and the 19.8 Bcfe decrease in sales volume. These decreases were offset, in-part, by the impact of the change in the gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program.
Current wording
The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the impact of the change in the gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 8.5 Bcfe increase in NGL sales volumes and the $0.36 per barrel increase in NGL prices. These increases were offset, in-part, by the $0.22 per Mcf decrease in natural gas sales price, when excluding the impact of hedging, and the 17.7 Bcf decrease in natural gas sales volume.
Previous wording
The Shale segment had earnings before income tax of $642 million for the year ended December 31, 2023 compared to earnings before income tax of $940 million for the year ended December 31, 2022.
Current wording
The Shale segment had earnings before income tax of $617 million for the year ended December 31, 2024 compared to earnings before income tax of $642 million for the year ended December 31, 2023.
Previous wording
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,170 million for the year ended December 31, 2023 compared to $3,335 million for the year ended December 31, 2022. The $2,165 million decrease was due primarily to a 65.9% decrease in the average sales price for natural gas, a 44.3% decrease in the average sales price of NGLs, and a 3.1% decrease in total Shale gas sales volumes. The decrease in total Shale sales volumes was primarily due to various operational delays and challenges that occurred in 2022, which impacted current period production due to the timing of wells being turned-in-line. The remaining variance is primarily due to normal production declines offset, in part, by an increase in NGL sales volume from new wells turned-in-line and an increase in ethane recoveries.
Current wording
The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,080 million for the year ended December 31, 2024 compared to $1,170 million for the year ended December 31, 2023. The $90 million decrease was due primarily to a 9.0% decrease in the average sales price for natural gas and a 3.4% decrease in Shale gas sales volumes primarily due to normal production declines and the timing of when new wells were turned-in-line. The decrease was offset, in part, by a 19.1% increase in NGLs sales volumes due to an increase in ethane recoveries and a 1.7% increase in the average sales price for NGLs.
Previous wording
The decrease in total average Shale sales price was primarily due to a $4.08 per Mcf decrease in average gas sales price and a $2.82 per Mcfe decrease in the average NGL sales price. These decreases were offset in part by a $3.69 per Mcf change in the realized gain (loss) on commodity derivative instruments. The notional amounts associated with these financial hedges represented approximately 399.2 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2023 at an average gain of $0.37 per Mcf hedged. For the year ended December 31, 2022, these financial hedges represented approximately 424.7 Bcf at an average loss of $3.94 per Mcf hedged.
Current wording
The increase in total average Shale sales price was primarily due to a $0.25 per Mcf change in the gain on commodity derivative instruments - cash settlement and a $0.06 per Mcfe increase in the average NGL sales price. These increases were offset in part by a $0.19 per Mcf decrease in average gas sales price. The notional amounts associated with these financial hedges represented approximately 389.7 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2024 at an average gain of $0.67 per Mcf hedged. For the year ended December 31, 2023, these financial hedges represented approximately 399.2 Bcf at an average gain of $0.37 per Mcf hedged.
Previous wording
Total operating costs and expenses for the Shale segment were $746 million for the year ended December 31, 2023 compared to $791 million for the year ended December 31, 2022. The decreases in total dollars and unit costs for the Shale segment were due to the following items:
Current wording
Total operating costs and expenses for the Shale segment were $791 million for the year ended December 31, 2024 compared to $746 million for the year ended December 31, 2023. The increases in total dollars and unit costs for the Shale segment were due to the following items:
Previous wording
•Shale lease operating expenses were $44 million for the year ended December 31, 2023 compared to $50 million for the year ended December 31, 2022. The decrease in total dollars was primarily related to a decrease in water disposal costs as more water was able to be reused in well completions instead of being taken to disposal.
Current wording
•Shale lease operating expenses were $48 million for the year ended December 31, 2024 compared to $44 million for the year ended December 31, 2023. The increase in total dollars was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense.
Previous wording
•Depreciation, depletion and amortization costs attributable to the CBM segment were $50 million for the year ended December 31, 2023 compared to $54 million for the year ended December 31, 2022. The decrease in total dollars and increase in unit costs was primarily due to the lower volumes in the current period. These amounts included depletion on a unit of production basis of $0.64 per Mcfe and $0.65 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Current wording
•Depreciation, depletion and amortization costs attributable to the Shale segment were $405 million for the year ended December 31, 2024 compared to $365 million for the year ended December 31, 2023. These amounts included depletion on a unit of production basis of $0.68 per Mcfe and $0.59 per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily due to a higher annual depletion rate for 2024. The increase in rate is primarily attributable to downward reserve revisions due to adjustments to the five-year development plan that lowered proved undeveloped reserves, price changes, and the sale of various non-operated producing oil and gas assets The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Previous wording
Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $67 million for the year ended December 31, 2023 compared to $69 million for the year ended December 31, 2022. The decrease in the period-to-period comparison was primarily due to lower third-party gathering volumes due to normal production declines.
Current wording
Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $68 million for the year ended December 31, 2024 compared to $67 million for the year ended December 31, 2023. The increase in the period-to-period comparison was primarily due to an increase in third-party gathering volumes.
Previous wording
The CBM segment had earnings before income tax of $1 million for the year ended December 31, 2023 compared to earnings before income tax of $44 million for the year ended December 31, 2022.
Current wording
The CBM segment had a loss before income tax of $26 million for the year ended December 31, 2024 compared to earnings before income tax of $1 million for the year ended December 31, 2023.
Previous wording
The CBM segment had natural gas revenue of $131 million for the year ended December 31, 2023 compared to $315 million for the year ended December 31, 2022. The $184 million decrease was primarily due to a 55.3% decrease in the average sales price for natural gas in the current period and a 7.1% decrease in CBM gas sales volumes due to normal production declines.
Current wording
The CBM segment had natural gas revenue of $105 million for the year ended December 31, 2024 compared to $131 million for the year ended December 31, 2023. The $26 million decrease was primarily due to a 16.5% decrease in the average sales price for natural gas in the current period and a 3.7% decrease in CBM gas sales volumes due to normal production declines.
Previous wording
The total average CBM sales price decreased $0.50 per Mcf due to a $3.98 per Mcf decrease in average gas sales price, offset in part by a $3.46 per Mcf change in the realized gain (loss) on commodity derivative instruments resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 31.9 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2023 at an average gain of $0.36 per Mcf hedged. For the year ended December 31, 2022, these financial hedges represented approximately 35.5 Bcf at an average loss of $3.92 per Mcf hedged.
Current wording
The total average CBM sales price decreased $0.30 per Mcf due to a $0.53 per Mcf decrease in average gas sales price, offset, in part, by a $0.25 per Mcf change in the gain on commodity derivative instruments - cash settlement resulting from the Company's hedging program. The notional amounts associated with these financial hedges represented approximately 30.6 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 2024 at an average gain of $0.67 per Mcf hedged. For the year ended December 31, 2023, these financial hedges represented approximately 31.9 Bcf at an average gain of $0.36 per Mcf hedged.
Previous wording
Total operating costs and expenses for the CBM segment were $142 million for the year ended December 31, 2023 compared to $132 million for the year ended December 31, 2022. The increases in total dollars and unit costs for the CBM segment were due to the following items:
Current wording
Total operating costs and expenses for the CBM segment were $152 million for the year ended December 31, 2024 compared to $142 million for the year ended December 31, 2023. The increase in total dollars and unit costs for the CBM segment were due to the following items:
Previous wording
•CBM lease operating expense was $19 million for the year ended December 31, 2023 compared to $17 million for the year ended December 31, 2022. The increases in total dollars and unit costs were primarily due to increases in water disposal costs and repairs and maintenance expense.
Current wording
•CBM lease operating expense was $22 million for the year ended December 31, 2024 compared to $19 million for the year ended December 31, 2023. The increase in total dollars and unit costs was primarily due to an increase in well tending expense and water disposal costs. The increase in per unit costs was also due to the decrease in total CBM volumes.
Previous wording
•CBM production, ad valorem and other fees were $7 million for the year ended December 31, 2023 compared to $12 million for the year ended December 31, 2022. The decreases in total dollars and unit costs were primarily due to decreased realized prices on natural gas.
Current wording
•CBM production, ad valorem and other fees were $6 million for the year ended December 31, 2024 compared to $7 million for the year ended December 31, 2023. The decreases in total dollars and unit costs were primarily due to decreased realized prices on natural gas.
Previous wording
•Shale transportation, gathering and compression costs were $316 million for the year ended December 31, 2023 compared to $319 million for the year ended December 31, 2022. The decrease in total dollars was primarily related to a decrease in firm transportation expense due to the lower Shale sales volumes. The decrease was offset, in part, by an increase in repairs and maintenance expense and an increase in processing costs due to an increase in ethane extraction and processing rates. The increase in unit costs was due to the decrease in total Shale sales volumes.
Current wording
•CBM transportation, gathering and compression costs were $64 million for the year ended December 31, 2024 compared to $66 million for the year ended December 31, 2023. The decrease in total dollars was primarily due to a decrease in repairs and maintenance expense offset, in part, by an increase in electrical compression expense. The increase in per unit costs was due to the decrease in CBM gas sales volumes.
Previous wording
•Depreciation, depletion and amortization costs attributable to the Shale segment were $365 million for the year ended December 31, 2023 compared to $389 million for the year ended December 31, 2022. These amounts included depletion on a unit of production basis of $0.59 per Mcfe and $0.62 per Mcfe, respectively. The decrease in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a lower annual depletion rate related to low-cost reserve additions from development in the 2022 period. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Current wording
•Depreciation, depletion and amortization costs attributable to the CBM segment were $60 million for the year ended December 31, 2024 compared to $50 million for the year ended December 31, 2023. These amounts included depletion on a unit of production basis of $0.85 per Mcfe and $0.64 per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a higher 2024 annual depletion rate. The increase in rate is primarily attributable to downward reserve revisions due to higher operating costs and price changes. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.
Previous wording
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, New Technologies, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as SG&A, interest expense and income taxes.
Current wording
The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, New Technologies, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative (“SG&A”), interest expense and income taxes.
Previous wording
The Other Segment had earnings before income tax of $1,580 million for the year ended December 31, 2023 compared to a loss before income tax of $1,196 million for the year ended December 31, 2022. The increase in total dollars is discussed below.
Current wording
The Other Segment had a loss before income tax of $711 million for the year ended December 31, 2024 compared to earnings before income tax of $1,580 million for the year ended December 31, 2023. The decrease in total dollars is discussed below.
Previous wording
For the year ended December 31, 2023, the Other Segment recognized an unrealized gain on commodity derivative instruments of $1,765 million. For the year ended December 31, 2022, the Other Segment recognized an unrealized loss on commodity derivative instruments of $851 million, as well as cash settlements paid of $1 million. The unrealized gain or loss on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis. See Note 19 – Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the cash settlements.
Current wording
For the year ended December 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $453 million. For the year ended December 31, 2023, the Other Segment recognized an unrealized gain on commodity derivative instruments of $1,765 million. The unrealized loss or gain on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.
Previous wording
Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $75 million for the year ended December 31, 2023 compared to $186 million for the year ended December 31, 2022. Purchased gas costs were $70 million for the year ended December 31, 2023 compared to $185 million for the year ended December 31, 2022. The period-to-period decrease in purchased gas revenue was due to a decrease in average sales price, offset in part by an increase in purchased gas sales volumes.
Current wording
Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $59 million for the year ended December 31, 2024 compared to $75 million for the year ended December 31, 2023. Purchased gas costs were $57 million for the year ended December 31, 2024 compared to $70 million for the year ended December 31, 2023. The period-to-period decrease in purchased gas revenue was due to a decrease in average sales price.
Previous wording
•Sales of environmental attributes includes items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold.
Current wording
•Sales of environmental attributes includes items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The increase in the period-to-period comparison was due to an increase in the amount of environmental attributes sold.
Previous wording
•Water income decreased in the period-to-period comparison due to fewer third-party sales in the current period.
Current wording
•Water income increased in the period-to-period comparison due to higher third-party sales in the current period.
Previous wording
•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The increase in the year ended December 31, 2023 was primarily due to an increase in the number of leases that were allowed to expire.
Current wording
•Lease expiration costs relate to leases where the primary term expired or will expire within the next 12 months. The decrease in the year ended December 31, 2024 was primarily due to a decrease in the number of acres that were allowed to expire.
Previous wording
SG&A costs include costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.
Current wording
SG&A includes costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also include non-cash long-term equity-based compensation expense.
Previous wording
•Short-term incentive compensation decreased $9 million due to lower projected payouts for the current period.
Current wording
•Short-term incentive compensation increased $12 million due to higher projected payouts for the current period.
Previous wording
•Other increased in the period-to-period comparison primarily due to an increase in professional services and consulting fees related to cyber security, legal matters and regulatory reporting.
Current wording
•Other increased in the period-to-period comparison primarily due to higher professional services and consulting fees, as well as increased software costs.
Previous wording
•Environmental attribute fees represent costs related to the monetization of environmental attributes that are included in Other Operating Income.
Current wording
•Environmental attribute fees represent costs related to the sale of environmental attributes that are included in Other Revenue and Operating Income. The increase in fees in the period-to-period comparison relates to the increase in sales above.
Previous wording
•Virginia flood expense includes the continuing cleanup and repair costs related to flooding that occurred in Buchanan County, Virginia in July 2022.
Current wording
•Virginia flood expense includes costs to cleanup and repair areas that were impacted by flooding that occurred in Buchanan County, Virginia in July 2022. The income in the current period relates to an insurance reimbursement for prior expenses incurred.
Showing the first 40 of 74 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
•Shale transportation, gathering and compression costs were $316 million for both the years ended December 31, 2024 and 2023. The increase in unit costs was due to the decrease in total Shale sales volumes.
Current report — wording carried from elsewhere
Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Selling, General and Administrative (“SG&A”)