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PRE-MKT · 04:35 ET
Market ClerkRecap
Mon Oct 26 · pre-market1 signal on Oct 2494 insider buys this week · $48.3MCIRO short report next: Oct 31The week ahead

CNX

CNX Resources Corp
NYSE · ENERGY · CRUDE PETROLEUM & NATURAL GAS
36.54
+0.81 +2.27%
USD · close Oct 23
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MKT CAP $5.4BP/E 6.0DIV YIELD —FCF YIELD 9.73%REV TTM $2.6B +61.9%NET INCOME $949.4M +509.7%NET DEBT $2.2B52W 31.17 – 42.61SEC XBRL · TTM TO Invalid Date

How CNX rewrote its risk factors

10-K ITEM 1A · FY2024 → FY2025
Text kept
40%
of sentences unchanged
Added
437
new sentences
Dropped
432
sentences removed
Length
−196
words, now 43,617

New in FY2025

  • Examples include global events such as the current uncertainties in global financial markets, geopolitical tensions and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, all of which have had an impact on global commodity prices.
  • 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. 2025 Highlights: • Proved developed reserves of 7.0 Tcfe as of December 31, 2025 • Total sales volumes of 629.0 Bcfe • Shale sales volumes of 590.8 Bcfe • Repurchased 16.9 million shares of CNX common stock for $528 million on the open market at an average price of $31.00 (see Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information). • On January 27, 2025, CNX completed the acquisition of Apex Energy II, LLC, (“the Apex Transaction”) for cash consideration of approximately $518 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 more information). 2026 Outlook: • Our 2026 annual sales volumes are expected to be approximately 605 - 620 Bcfe. • Our 2026 capital expenditures are expected to be approximately $556 - $586 million. • CNX’s 2026 capital expenditures includes the first of three annual payments of $16 million associated with an agreement that grants CNX the right to acquire Utica Shale oil and gas rights that sit beneath the legacy Apex Energy footprint.
  • Results of Operations: The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2025 to the year ended December 31, 2024.
  • A similar discussion and analysis that compares year ended December 31, 2024 to the fiscal year ended December 31, 2023 is omitted from this Annual Report on Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated herein by reference.
  • Net Income (Loss) CNX reported net income of $633 million, or earnings per diluted share of $3.98, for the year ended December 31, 2025, compared to a net loss of $90 million, or a loss per diluted share of $0.60, for the year ended December 31, 2024.
  • Included in earnings for the year ended December 31, 2025 was an unrealized gain on commodity derivative instruments of $278 million and a net gain on asset sales and abandonments of $97 million.
  • Non-GAAP Financial Measures Reconciliation For the Years Ended December 31, (Dollars in millions) 2025 2024 Total Revenue and Other Operating Income $ 2,239 $ 1,267 (Deduct) Add: Purchased Gas Revenue (45) (59) (Gain) Loss on Commodity Derivative Instruments - Unrealized (278) 453 Other Revenue and Operating Income (183) (194) Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure $ 1,733 $ 1,467 Total Operating Expense $ 1,348 $ 1,260 Deduct: Depreciation, Depletion and Amortization (DD&A) - Corporate (20) (16) Exploration and Production Related Other Costs (11) (8) Purchased Gas Costs (43) (57) Selling, General and Administrative Costs (140) (146) Other Operating Expense (69) (83) Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 $ 1,065 $ 950 1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
  • Selected Natural Gas, NGL and Oil Production Financial Data The following table presents a summary of our total sales volumes, 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 related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP): For the Years Ended December 31, 2025 2024 Variance in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe Total Sales Volumes (Bcfe)* 629.0 550.8 78.2 Natural Gas, NGL and Oil Revenue $ 1,914 $ 3.06 $ 1,186 $ 2.09 $ 728 $ 0.97 (Loss) Gain on Commodity Derivative Instruments - Cash Settlement (181) (0.31) 281 0.57 (462) (0.88) Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure 1,733 2.75 1,467 2.66 266 0.09 Lease Operating Expense 97 0.15 70 0.13 27 0.02 Production, Ad Valorem, and Other Fees 31 0.05 28 0.05 3 — Transportation, Gathering and Compression 383 0.61 382 0.69 1 (0.08) Depreciation, Depletion and Amortization (DD&A) 554 0.88 470 0.85 84 0.03 Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1,065 1.69 950 1.72 115 (0.03) Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure $ 668 $ 1.06 $ 517 $ 0.94 $ 151 $ 0.12 *NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
  • The 78.2 Bcfe increase in sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (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) and the timing of when new wells were turned-in-line.
  • The increase in volumes was offset, in part, by normal production declines.
  • Changes in the average costs per Mcfe were primarily related to the following items: • 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.
  • The increases were offset, in part, by the overall increase in total sales volumes. • Transportation, gathering and compression expense decreased on a per unit basis primarily due to the overall increase in total sales volumes, a decrease in processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes.
  • The per unit decreases were offset, in part, by higher repairs and maintenance expense. • Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate.
  • The increases were offset, in part, by the overall increase in total sales volumes.
  • Average Realized Price Reconciliation The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives: For the Years Ended December 31, in thousands (unless noted) 2025 2024 Variance Percent Change LIQUIDS NGL: Sales Volume (MMcfe) 47,440 52,949 (5,509) (10.4) % Sales Volume (Mbbls) 7,907 8,825 (918) (10.4) % Gross Price ($/Bbl) $ 21.30 $ 21.60 $ (0.30) (1.4) % Gross NGL Revenue $ 168,574 $ 190,374 $ (21,800) (11.5) % Oil/Condensate: Sales Volume (MMcfe) 919 943 (24) (2.5) % Sales Volume (Mbbls) 153 157 (4) (2.5) % Gross Price ($/Bbl) $ 55.26 $ 61.56 $ (6.30) (10.2) % Gross Oil/Condensate Revenue $ 8,461 $ 9,675 $ (1,214) (12.5) % NATURAL GAS Sales Volume (MMcf) 580,601 496,921 83,680 16.8 % Sales Price ($/Mcf) $ 2.99 $ 1.98 $ 1.01 51.0 % Gross Gas Revenue $ 1,736,693 $ 986,028 $ 750,665 76.1 % Hedging Impact ($/Mcf) $ (0.31) $ 0.57 $ (0.88) (154.4) % (Loss) Gain on Commodity Derivative Instruments - Cash Settlement $ (181,020) $ 281,195 $ (462,215) (164.4) % The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the 83.7 Bcf increase in natural gas sales volumes and the $1.01 per Mcf increase in natural gas sales price, when excluding the impact of hedging.
  • These increases were offset, in-part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 5.5 Bcfe decrease in NGL sales volumes and the $0.30 per barrel decrease in NGL prices.
  • SEGMENT ANALYSIS for the year ended December 31, 2025 compared to the year ended December 31, 2024: For the Year Ended Difference to Year Ended December 31, 2025 December 31, 2024 (in millions) Shale CBM Other Total Shale CBM Other Total Natural Gas, NGLs and Oil Revenue $ 1,764 $ 148 $ 2 $ 1,914 $ 684 $ 43 $ 1 $ 728 (Loss) Gain on Commodity Derivative Instruments (170) (11) 278 97 (430) (32) 731 269 Purchased Gas Revenue — — 45 45 — — (14) (14) Other Revenue and Operating Income 69 — 114 183 1 — (12) (11) Total Revenue and Other Operating Income 1,663 137 439 2,239 255 11 706 972 Lease Operating Expense 73 24 — 97 25 2 — 27 Production, Ad Valorem, and Other Fees 25 6 — 31 3 — — 3 Transportation, Gathering and Compression 317 64 2 383 1 — — 1 Depreciation, Depletion and Amortization 488 60 26 574 83 — 5 88 Exploration and Production Related Other Costs — — 11 11 — — 3 3 Purchased Gas Costs — — 43 43 — — (14) (14) Selling, General and Administrative Costs — — 140 140 — — (6) (6) Other Operating Expense — — 69 69 — — (14) (14) Total Operating Costs and Expenses 903 154 291 1,348 112 2 (26) 88 Other Expense — — 14 14 — — 20 20 Gain on Asset Sales and Abandonments, net — — (97) (97) — — (72) (72) Loss on Debt Extinguishment — — 1 1 — — (6) (6) Interest Expense — — 170 170 — — 19 19 Total Other Expenses — — 88 88 — — (39) (39) Total Costs and Expenses 903 154 379 1,436 112 2 (65) 49 Earnings (Loss) Before Income Tax $ 760 $ (17) $ 60 $ 803 $ 143 $ 9 $ 771 $ 923 SHALE SEGMENT The Shale segment had earnings before income tax of $760 million for the year ended December 31, 2025 compared to earnings before income tax of $617 million for the year ended December 31, 2024.
  • For the Years Ended December 31, 2025 2024 Variance Percent Change Shale Gas Sales Volumes (Bcf) 542.6 457.5 85.1 18.6 % NGLs Sales Volumes (Bcfe)* 47.4 53.0 (5.6) (10.6) % Oil/Condensate Sales Volumes (Bcfe)* 0.8 0.9 (0.1) (11.1) % Total Shale Sales Volumes (Bcfe)* 590.8 511.4 79.4 15.5 % Average Sales Price - Gas (per Mcf) $ 2.93 $ 1.92 $ 1.01 52.6 % (Loss) Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) $ (0.31) $ 0.57 $ (0.88) (154.4) % Average Sales Price - NGLs (per Mcfe)* $ 3.55 $ 3.60 $ (0.05) (1.4) % Average Sales Price - Oil/Condensate (per Mcfe)* $ 9.03 $ 10.23 $ (1.20) (11.7) % Total Average Shale Sales Price (per Mcfe) $ 2.70 $ 2.62 $ 0.08 3.1 % Average Shale Lease Operating Expenses (per Mcfe) 0.12 0.09 0.03 33.3 % Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.04 0.04 — — % Average Shale Transportation, Gathering and Compression Costs (per Mcfe) 0.54 0.62 (0.08) (12.9) % Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.83 0.80 0.03 3.7 % Total Average Shale Production Costs (per Mcfe) $ 1.53 $ 1.55 $ (0.02) (1.3) % Total Average Shale Production Margin (per Mcfe) $ 1.17 $ 1.07 $ 0.10 9.3 % *NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
  • The increase in total Shale sales volumes was primarily due to the Apex Transaction that was completed in the first quarter of 2025 (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) and the timing of when new wells were turned-in-line.
  • The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,764 million for the year ended December 31, 2025 compared to $1,080 million for the year ended December 31, 2024.
  • The $684 million increase was due primarily to a 52.6% increase in the average sales price for natural gas and an 18.6% increase in Shale gas sales volumes.
  • These increases were offset, in part, by a 10.6% decrease in NGLs sales volumes and a 1.4% decrease in the average sales price for NGLs.
  • The increase in total average Shale sales price was primarily due to a $1.01 per Mcf increase in average gas sales price.
  • These increases were offset, in part, by a $0.88 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements and a $0.05 per Mcfe decrease in the average NGL sales price.
  • The notional amounts associated with these financial hedges represented approximately 452.6 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 2025 at an average loss of $0.38 per Mcf hedged.
  • For the year ended December 31, 2024, these financial hedges represented approximately 389.7 Bcf at an average gain of $0.67 per Mcf hedged.
  • Total operating costs and expenses for the Shale segment were $903 million for the year ended December 31, 2025 compared to $791 million for the year ended December 31, 2024.
  • The increase in total dollars and decrease in unit costs for the Shale segment were due to the following items: • Shale lease operating expenses were $73 million for the year ended December 31, 2025 compared to $48 million for the year ended December 31, 2024.
  • The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions, higher well tending expense and higher repairs and maintenance expense.
  • The increase in unit costs was offset, in part, by the increase in total Shale sales volumes. • Shale production, ad valorem and other fees were $25 million for the year ended December 31, 2025 compared to $22 million for the year ended December 31, 2024.
  • The increase in total dollars was primarily due to increased realized prices on natural gas and a change in production mix by state.
  • Unit costs remained flat in the period-to-period comparison due to the overall increase in volumes. • Shale transportation, gathering and compression costs were $317 million for the year ended December 31, 2025 compared to $316 million for the year ended December 31, 2024.
  • The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes.
  • The decrease in unit costs was due to the increase in total Shale sales volumes. • Depreciation, depletion and amortization costs attributable to the Shale segment were $488 million for the year ended December 31, 2025 compared to $405 million for the year ended December 31, 2024.
  • These amounts included depletion on a unit of production basis of $0.72 per Mcfe and $0.68 per Mcfe, respectively.
  • The Shale segment had other revenue and operating income of $69 million for the year ended December 31, 2025 compared to $68 million for the year ended December 31, 2024.
  • COALBED METHANE (CBM) SEGMENT The CBM segment had a loss before income tax of $17 million for the year ended December 31, 2025 compared to a loss before income tax of $26 million for the year ended December 31, 2024.
  • For the Years Ended December 31, 2025 2024 Variance Percent Change CBM Gas Sales Volumes (Bcf) 37.8 39.1 (1.3) (3.3) % Average Sales Price - Gas (per Mcf) $ 3.91 $ 2.69 $ 1.22 45.4 % (Loss) Gain on Commodity Derivative Instruments - Cash Settlement - Gas (per Mcf) $ (0.30) $ 0.53 $ (0.83) (156.6) % Total Average CBM Sales Price (per Mcf) $ 3.61 $ 3.21 $ 0.40 12.5 % Average CBM Lease Operating Expenses (per Mcf) 0.64 0.56 0.08 14.3 % Average CBM Production, Ad Valorem and Other Fees (per Mcf) 0.17 0.14 0.03 21.4 % Average CBM Transportation, Gathering and Compression Costs (per Mcf) 1.69 1.65 0.04 2.4 % Average CBM Depreciation, Depletion and Amortization Costs (per Mcf) 1.56 1.52 0.04 2.6 % Total Average CBM Production Costs (per Mcf) $ 4.06 $ 3.87 $ 0.19 4.9 % Total Average CBM Production Margin (per Mcf) $ (0.45) $ (0.66) $ 0.21 31.8 % The CBM segment had natural gas revenue of $148 million for the year ended December 31, 2025 compared to $105 million for the year ended December 31, 2024.
  • The $43 million increase was primarily due to a 45.4% increase in the average sales price for natural gas in the current period offset, in part, by a 3.3% decrease in CBM sales volumes due to normal production declines.
  • The total average CBM sales price increased $0.40 per Mcf due to a $1.22 per Mcf increase in average gas sales price, offset, in part, by a $0.83 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlements.

and 397 more.

Gone since FY2024

  • 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.
  • 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.
  • New Technologies Update 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.
  • 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. 2024 Highlights: • Proved developed reserves of 6.1 Tcfe as of December 31, 2024 • Total sales volumes of 550.8 Bcfe • Shale sales volumes of 511.4 Bcfe • Repurchased 7.2 million shares of CNX common stock for $179 million on the open market at an average price of $24.68. 2025 Outlook: • 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. • 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. • Our 2025 annual sales volumes are expected to be approximately 605-620 Bcfe. • Our 2025 capital expenditures are expected to be approximately $450-$500 million. • Our 2025 sales of environmental attributes, net of corresponding fees, are expected to be approximately $75 million.
  • However, our ability to sell environmental attributes can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in "Item 1A.
  • Results of Operations: The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 2024 to the year ended December 31, 2023.
  • A similar discussion and analysis that compares year ended December 31, 2023 to the fiscal year ended December 31, 2022 is omitted from this Form 10-K and may be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of our Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.
  • Net (Loss) Income 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.
  • 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.
  • Non-GAAP Financial Measures Reconciliation For the Years Ended December 31, (Dollars in millions) 2024 2023 Total Revenue and Other Operating Income $ 1,267 $ 3,435 (Deduct) Add: Purchased Gas Revenue (59) (75) Loss (Gain) on Commodity Derivative Instruments - Unrealized 453 (1,765) Other Revenue and Operating Income (194) (130) Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure $ 1,467 $ 1,465 Total Operating Expense $ 1,260 $ 1,192 (Deduct): Depreciation, Depletion and Amortization (DD&A) - Corporate (16) (14) Exploration and Production Related Other Costs (8) (10) Purchased Gas Costs (57) (70) Selling, General and Administrative Costs (146) (125) Other Operating Expense (83) (80) Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 1 $ 950 $ 893 1 Natural Gas, NGL and Oil production costs consists primarily of lease operating expense, production ad valorem and other fees, transportation, gathering and compression and production related depreciation, depletion and amortization.
  • Selected Natural Gas, NGL and Oil Production Financial Data The following table presents a summary of our total sales volumes, 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 related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP): For the Years Ended December 31, 2024 2023 Variance in Millions Per Mcfe in Millions Per Mcfe in Millions Per Mcfe Total Sales Volumes (Bcfe)* 550.8 560.4 (9.6) Natural Gas, NGL and Oil Revenue $ 1,186 $ 2.09 $ 1,302 $ 2.29 $ (116) $ (0.20) Gain on Commodity Derivative Instruments - Cash Settlement 281 0.57 163 0.32 118 0.25 Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure 1,467 2.66 1,465 2.61 2 0.05 Lease Operating Expense 70 0.13 63 0.11 7 0.02 Production, Ad Valorem, and Other Fees 28 0.05 28 0.05 — — Transportation, Gathering and Compression 382 0.69 382 0.68 — 0.01 Depreciation, Depletion and Amortization (DD&A) 470 0.85 420 0.75 50 0.10 Natural Gas, NGL and Oil Production Costs, a Non-GAAP Financial Measure 950 1.72 893 1.59 57 0.13 Natural Gas, NGL and Oil Production Margin, a Non-GAAP Financial Measure $ 517 $ 0.94 $ 572 $ 1.02 $ (55) $ (0.08) *NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL, condensate, and natural gas prices.
  • 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.
  • Changes in the average costs per Mcfe were primarily related to the following items: • 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. • 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.
  • Average Realized Price Reconciliation The following table presents a breakout of liquids and natural gas sales information and settled derivative information to assist in the understanding of the Company’s natural gas production and sales portfolio and information regarding settled commodity derivatives: For the Years Ended December 31, in thousands (unless noted) 2024 2023 Variance Percent Change LIQUIDS NGL: Sales Volume (MMcfe) 52,949 44,461 8,488 19.1 % Sales Volume (Mbbls) 8,825 7,410 1,415 19.1 % Gross Price ($/Bbl) $ 21.60 $ 21.24 $ 0.36 1.7 % Gross NGL Revenue $ 190,374 $ 157,573 $ 32,801 20.8 % Oil/Condensate: Sales Volume (MMcfe) 943 1,236 (293) (23.7) % Sales Volume (Mbbls) 157 206 (49) (23.8) % Gross Price ($/Bbl) $ 61.56 $ 65.88 $ (4.32) (6.6) % Gross Oil/Condensate Revenue $ 9,675 $ 13,577 $ (3,902) (28.7) % NATURAL GAS Sales Volume (MMcf) 496,921 514,669 (17,748) (3.4) % Sales Price ($/Mcf) $ 1.98 $ 2.20 $ (0.22) (10.0) % Gross Gas Revenue $ 986,028 $ 1,131,068 $ (145,040) (12.8) % Hedging Impact ($/Mcf) $ 0.57 $ 0.32 $ 0.25 (78.1) % Gain on Commodity Derivative Instruments - Cash Settlement $ 281,195 $ 163,026 $ 118,169 (72.5) % 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.
  • SEGMENT ANALYSIS for the year ended December 31, 2024 compared to the year ended December 31, 2023: For the Year Ended Difference to Year Ended December 31, 2024 December 31, 2023 (in millions) Shale CBM Other Total Shale CBM Other Total Natural Gas, NGLs and Oil Revenue $ 1,080 $ 105 $ 1 $ 1,186 $ (90) $ (26) $ — $ (116) Gain (Loss) on Commodity Derivative Instruments 260 21 (453) (172) 109 9 (2,218) (2,100) Purchased Gas Revenue — — 59 59 — — (16) (16) Other Revenue and Operating Income 68 — 126 194 1 — 63 64 Total Revenue (Loss) and Other Operating Income 1,408 126 (267) 1,267 20 (17) (2,171) (2,168) Lease Operating Expense 48 22 — 70 4 3 — 7 Production, Ad Valorem, and Other Fees 22 6 — 28 1 (1) — — Transportation, Gathering and Compression 316 64 2 382 — (2) 2 — Depreciation, Depletion and Amortization 405 60 21 486 40 10 2 52 Exploration and Production Related Other Costs — — 8 8 — — (2) (2) Purchased Gas Costs — — 57 57 — — (13) (13) Selling, General and Administrative Costs — — 146 146 — — 21 21 Other Operating Expense — — 83 83 — — 3 3 Total Operating Costs and Expenses 791 152 317 1,260 45 10 13 68 Other (Income) Expense — — (6) (6) — — (15) (15) Gain on Asset Sales and Abandonments, net — — (25) (25) — — 107 107 Loss on Debt Extinguishment — — 7 7 — — 7 7 Interest Expense — — 151 151 — — 8 8 Total Other Expenses — — 127 127 — — 107 107 Total Costs and Expenses 791 152 444 1,387 45 10 120 175 Earnings (Loss) Before Income Tax $ 617 $ (26) $ (711) $ (120) $ (25) $ (27) $ (2,291) $ (2,343) SHALE SEGMENT 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.
  • For the Years Ended December 31, 2024 2023 Variance Percent Change Shale Gas Sales Volumes (Bcf) 457.5 473.8 (16.3) (3.4) % NGLs Sales Volumes (Bcfe)* 53.0 44.5 8.5 19.1 % Oil/Condensate Sales Volumes (Bcfe)* 0.9 1.2 (0.3) (25.0) % Total Shale Sales Volumes (Bcfe)* 511.4 519.5 (8.1) (1.6) % Average Sales Price - Gas (per Mcf) $ 1.92 $ 2.11 $ (0.19) (9.0) % Gain on Commodity Derivative Instruments - Cash Settlement (per Mcf) $ 0.57 $ 0.32 $ 0.25 78.1 % Average Sales Price - NGLs (per Mcfe)* $ 3.60 $ 3.54 $ 0.06 1.7 % Average Sales Price - Oil/Condensate (per Mcfe)* $ 10.23 $ 10.95 $ (0.72) (6.6) % Total Average Shale Sales Price (per Mcfe) $ 2.62 $ 2.54 $ 0.08 3.1 % Average Shale Lease Operating Expenses (per Mcfe) 0.09 0.08 0.01 12.5 % Average Shale Production, Ad Valorem and Other Fees (per Mcfe) 0.04 0.04 — — % Average Shale Transportation, Gathering and Compression Costs (per Mcfe) 0.62 0.61 0.01 1.6 % Average Shale Depreciation, Depletion and Amortization Costs (per Mcfe) 0.80 0.70 0.10 14.3 % Total Average Shale Production Costs (per Mcfe) $ 1.55 $ 1.43 $ 0.12 8.4 % Total Average Shale Production Margin (per Mcfe) $ 1.07 $ 1.11 $ (0.04) (3.6) % *NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs, condensate, and natural gas prices.
  • 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.
  • 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.
  • 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: • 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. • 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. • 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.

and 392 more.

Sentence-level comparison of Item 1A in the two most recent 10-Ks (FY2024 ↗, FY2025 ↗). A reworded sentence counts as one dropped and one added, so heavy edits read as low “kept”. Headings and page furniture are stripped; nothing is summarised by a model.

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