EQT Corp (EQT) FY 2024 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and the notes thereto included in Item 8., "Financial Statements and Supplementary Data."
Recent and Significant Events
Midstream Joint Venture Transaction
On December 30, 2024, in connection with the completion of the Midstream Joint Venture Transaction, the Midstream Joint Venture received $3.5 billion of cash consideration, net of certain transaction fees and expenses, from a third-party investor in exchange for a noncontrolling equity interest in the Midstream Joint Venture. We used the proceeds from the Midstream Joint Venture Transaction to repay outstanding borrowings under the Bridge Credit Facility (defined in Note 10 to the Consolidated Financial Statements) and the Term Loan Facility and a portion of outstanding borrowings under EQT's revolving credit facility. Borrowings under the Bridge Credit Facility were used to fund the redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer (defined in Note 10 to the Consolidated Financial Statements).
NEPA Non-Operated Asset Divestitures and NEPA Gathering System Acquisition
Results of operations for 2024 include the results of our operation of assets received as consideration for the First NEPA Non-Operated Asset Divestiture, which closed on May 31, 2024. Such assets received included the remaining 16.25% equity interest in the NEPA Gathering System (defined in Note 6 to the Consolidated Financial Statements) (which was the sole remaining minority interest following our acquisition of a 33.75% equity interest in the NEPA Gathering System Acquisition (defined in Note 6 to the Consolidated Financial Statements) on April 11, 2024), resulting in our 100% ownership of the NEPA Gathering System. See Note 7 to the Consolidated Financial Statements.
In addition, on December 31, 2024, we completed the Second NEPA Non-Operated Asset Divestiture. See Note 7 to the Consolidated Financial Statements. We used the proceeds from the Second NEPA Non-Operated Asset Divestiture of $1.25 billion, subject to customary post-closing purchase price adjustments and transaction costs, to repay a portion of outstanding borrowings under EQT's revolving credit facility.
Equitrans Midstream Merger
Results of operations for 2024 include the results of our operation of assets acquired in the Equitrans Midstream Merger, which closed on July 22, 2024. Following the completion of the Equitrans Midstream Merger, we own a gathering system with 1,975 miles of gathering lines (including gathering lines owned prior to the Equitrans Midstream Merger) and a transmission and storage system with approximately 950 miles of FERC-regulated, interstate pipelines. See Note 6 to the Consolidated Financial Statements.
For the period from July 22, 2024 through December 31, 2024, our consolidated gathering expense decreased due to our ownership of the gathering and transmission assets acquired in the Equitrans Midstream Merger. Our ownership of such assets will continue to positively impact our Production segment's gathering expense, with a corresponding increase to our Production segment's affiliate transportation and processing expense, which is eliminated in consolidation. This relationship will be prominent for full year 2025 results and beyond.
Tug Hill and XcL Midstream Acquisition
Results of operations for 2024 and the second half of 2023 include the results of our operation of assets acquired in the Tug Hill and XcL Midstream Acquisition (defined in Note 6 to the Consolidated Financial Statements), which closed on August 22, 2023.
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Trends and Uncertainties
On March 4, 2024, we announced our decision to strategically curtail approximately 1.0 Bcfe per day of gross production (the Strategic Curtailment) beginning on February 24, 2024 in response to the low natural gas price environment resulting from warm winter weather and elevated storage inventories. The Strategic Curtailment resulted in total decreased sales volume of 107 Bcfe for 2024. In addition, certain operators of wells in which we have a non-operating working interest also curtailed production in 2024. For 2024, we estimate that our total expected sales volume was negatively impacted by approximately 130 to 140 Bcfe of curtailments, including our Strategic Curtailment of 107 Bcfe and curtailments by certain operators of wells in which we have a non-operating working interest.
Low natural gas prices or volatility in the natural gas market may result in adjustments to our 2025 planned development schedule or the development schedule of non-operated wells in which we have a working interest. Further, we cannot control or otherwise influence the development schedule of non-operated wells in which we have a working interest. Adjustments to our 2025 planned development schedule or the development schedule of non-operated wells in which we have a working interest, including due to declines in natural gas prices, the pace of well completions, access to sand and water to conduct drilling operations, access to sufficient pipeline takeaway capacity, unscheduled downtime at processing facilities or otherwise, could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.
In connection with the recent U.S. election and corresponding inauguration of President Trump on January 20, 2025, the President executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the institution of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. A changing regulatory environment could increase our costs to comply with such regulations or make us susceptible to lawsuits or fines for failure to comply with such regulations. Further, tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the price of natural gas, increase the price of supplies and raw materials that we rely on to conduct our business, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.
Lastly, we expect commodity prices to be volatile through 2025 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical tensions, including developments pertaining to Russia's invasion of Ukraine, conflicts in the Middle East and potential further imposition of domestic and foreign tariffs. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for natural gas and, to a lesser extent, NGLs and oil.
Consolidated Results of Operations
Net income attributable to EQT Corporation for 2024 was $231 million, $0.45 per diluted share, compared to $1,735 million, $4.22 per diluted share, for 2023. The decrease was attributable primarily to a lower gain on derivatives, increased depreciation, depletion and amortization, increased other operating expenses and increased net interest expense, partly offset by the gains on the NEPA Non-Operated Asset Divestitures, decreased income tax expense, increased pipeline revenues and decreased transportation and processing expense.
See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference, for discussion and analysis of consolidated results of operations for the year ended December 31, 2022.
We did not recast our discussion and analysis of financial condition and results of operations for the year ended December 31, 2022 for our change in reportable segments as such change does not materially change our historic comparative discussion of our financial condition and results of operations for the years ended December 31, 2023 and 2022 included within the 2023 Annual Report. Prior to the Equitrans Midstream Merger, we operated our business as a single segment and did not generate material third-party gathering operating income. Further, in our judgment, we do not believe such a recast is necessary to an understanding of our business, financial condition, changes in financial condition and results of operations. See Note 2 to the Consolidated Financial Statements for financial information by business segment, including our profit and loss metric and capital expenditures for the year ended December 31, 2022 and segment assets as of December 31, 2022.
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See "Average Realized Price Reconciliation" for a discussion and calculation of our average realized price, which is based on our Production segment's adjusted operating revenues (Production adjusted operating revenues), a non-GAAP supplemental financial measure that has been reconciled from total Production operating revenues in "Non-GAAP Financial Measures Reconciliation." See "Business Segment Results of Operations" for a discussion of segment operating revenues and expenses and "Other Income Statement Items" for a discussion of other income statement items. See "Investing Activities" under "Capital Resources and Liquidity" for a discussion of capital expenditures, including by business segment.
Average Realized Price Reconciliation
The following table presents detailed natural gas and liquids operational information to assist in the understanding of our consolidated operations, including the calculation of our average realized price ($/Mcfe), which is based on Production adjusted operating revenues, a non-GAAP supplemental financial measure. Production adjusted operating revenues is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Production adjusted operating revenues should not be considered as an alternative to total Production operating revenues. See "Non-GAAP Financial Measures Reconciliation" for a reconciliation of Production adjusted operating revenues from total Production operating revenues, the most directly comparable financial measure calculated in accordance with United States generally accepted accounting principles (GAAP).
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| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| (Thousands, unless otherwise noted) | ||||||
| NATURAL GAS | ||||||
| Sales volume (MMcf) | 2,086,441 | 1,907,343 | ||||
| NYMEX price ($/MMBtu) | $ | 2.30 | $ | 2.74 | ||
| Btu uplift | 0.13 | 0.14 | ||||
| Natural gas price ($/Mcf) | $ | 2.43 | $ | 2.88 | ||
| Basis ($/Mcf) (a) | $ | (0.41) | $ | (0.51) | ||
| Cash settled basis swaps ($/Mcf) | (0.07) | (0.03) | ||||
| Average differential, including cash settled basis swaps ($/Mcf) | $ | (0.48) | $ | (0.54) | ||
| Average adjusted price ($/Mcf) | $ | 1.95 | $ | 2.34 | ||
| Cash settled derivatives ($/Mcf) | 0.64 | 0.34 | ||||
| Average natural gas price, including cash settled derivatives ($/Mcf) | $ | 2.59 | $ | 2.68 | ||
| Natural gas sales, including cash settled derivatives | $ | 5,401,642 | $ | 5,112,278 | ||
| LIQUIDS | ||||||
| NGLs, excluding ethane: | ||||||
| Sales volume (MMcfe) (b) | 87,564 | 64,859 | ||||
| Sales volume (Mbbl) | 14,594 | 10,810 | ||||
| NGLs price ($/Bbl) | $ | 39.13 | $ | 36.39 | ||
| Cash settled derivatives ($/Bbl) | (0.30) | (1.27) | ||||
| Average NGLs price, including cash settled derivatives ($/Bbl) | $ | 38.83 | $ | 35.12 | ||
| NGLs sales, including cash settled derivatives | $ | 566,808 | $ | 379,663 | ||
| Ethane: | ||||||
| Sales volume (MMcfe) (b) | 44,586 | 34,441 | ||||
| Sales volume (Mbbl) | 7,431 | 5,740 | ||||
| Ethane price ($/Bbl) | $ | 6.03 | $ | 6.00 | ||
| Ethane sales | $ | 44,806 | $ | 34,417 | ||
| Oil: | ||||||
| Sales volume (MMcfe) (b) | 9,568 | 9,630 | ||||
| Sales volume (Mbbl) | 1,595 | 1,605 | ||||
| Oil price ($/Bbl) | $ | 58.67 | $ | 59.93 | ||
| Oil sales | $ | 93,551 | $ | 96,191 | ||
| Total liquids sales volume (MMcfe) (b) | 141,718 | 108,930 | ||||
| Total liquids sales volume (Mbbl) | 23,620 | 18,155 | ||||
| Total liquids sales | $ | 705,165 | $ | 510,271 | ||
| TOTAL | ||||||
| Total natural gas and liquids sales, including cash settled derivatives (c) | $ | 6,106,807 | $ | 5,622,549 | ||
| Total sales volume (MMcfe) | 2,228,159 | 2,016,273 | ||||
| Average realized price ($/Mcfe) | $ | 2.74 | $ | 2.79 |
(a)Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with our firm transportation agreements, and the NYMEX natural gas price.
(b)NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel.
(c)Also referred to in this report as Production adjusted operating revenues, a non-GAAP supplemental financial measure.
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Non-GAAP Financial Measures Reconciliation
The table below reconciles Production adjusted operating revenues, a non-GAAP supplemental financial measure, from total Production operating revenues, the most comparable financial measure calculated in accordance with GAAP. See Note 2 to the Consolidated Financial Statements for a reconciliation of total Production operating revenues to EQT Corporation operating revenues as reported in the Statements of Consolidated Operations.
Production adjusted operating revenues (also referred to in this report as total natural gas and liquids sales, including cash settled derivatives) is presented because it is an important measure we use to evaluate period-to-period comparisons of earnings trends. Production adjusted operating revenues is defined as total Production operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and Production net marketing services and other revenues. We believe that Production adjusted operating revenues provides useful information to investors regarding our financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods. Production adjusted operating revenues reflects only the impact of settled derivative contracts; thus, the measure excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The measure also excludes Production net marketing services and other revenues, which consists of costs of, and recoveries on, pipeline capacity releases and other revenues.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| (Thousands, unless otherwise noted) | ||||||
| Total Production operating revenues | $ | 5,009,833 | $ | 6,896,358 | ||
| (Deduct) add: | ||||||
| Production gain on derivatives | (67,880) | (1,838,941) | ||||
| Net cash settlements received on derivatives (a) | 1,217,895 | 900,650 | ||||
| Premiums paid for derivatives that settled during the period | (45,454) | (322,869) | ||||
| Production net marketing services and other | (7,587) | (12,649) | ||||
| Production adjusted operating revenues, a non-GAAP financial measure | $ | 6,106,807 | $ | 5,622,549 | ||
| Total sales volume (MMcfe) | 2,228,159 | 2,016,273 | ||||
| Average sales price ($/Mcfe) | $ | 2.21 | $ | 2.50 | ||
| Average realized price ($/Mcfe) | $ | 2.74 | $ | 2.79 |
(a)For the years ended December 31, 2024 and 2023, composed of net cash settlements received on NYMEX natural gas hedge positions of approximately $1,374 million and $976 million , respectively, and net cash settlements paid on basis and liquids hedge positions of $157 million and $76 million, respectively. Net cash settlements received on derivatives are included in average realized price but may not be included in operating revenues.
Business Segment Results of Operations
Operating segments are revenue-producing components of an entity for which separate financial information is produced internally and reviewed by the chief operating decision maker to measure financial performance and allocate resources.
Prior to the completion of the Equitrans Midstream Merger, we reported our results of operations as a single consolidated segment. Thereafter, and as a result thereof, we adjusted our internal reporting structure and our chief operating decision maker changed the manner in which he measures financial performance and allocates resources to incorporate the gathering and transmission assets we acquired in the Equitrans Midstream Merger. Hence, our operations expanded to comprise three discrete segments reflective of our three lines of business of Production, Gathering and Transmission. Accordingly, the manner in which we report our operations has been changed retrospectively, with certain prior period amounts recast between our Production segment and Gathering segment.
The following sections summarize operating income and certain operational measures by our three reportable segments. We believe this information is useful to investors for evaluating our financial condition, results of operations and trends and uncertainties of our segments. See Note 2 to the Consolidated Financial Statements for financial information by business segment.
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Certain amounts, including cash and cash equivalents, debt, income taxes and other amounts related to our headquarters function as well as amounts related to our energy transition initiatives are managed on a consolidated basis and, as such, have not been allocated to our reportable segments. Changes to these amounts are discussed under "Other Income Statement Items."
PRODUCTION
| Years Ended December 31, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2024 | 2023 | Change | % Change | ||||||||||
| (Thousands, unless otherwise noted) | |||||||||||||
| Total sales volume (MMcfe) | 2,228,159 | 2,016,273 | 211,886 | 10.5 | |||||||||
| Average daily sales volume (MMcfe/d) | 6,088 | 5,524 | 564 | 10.2 | |||||||||
| Average sales price ($/Mcfe) | $ | 2.21 | $ | 2.50 | $ | (0.29) | (11.6) | ||||||
| Operating revenues: | |||||||||||||
| Sales of natural gas, NGLs and oil | $ | 4,934,366 | $ | 5,044,768 | $ | (110,402) | (2.2) | ||||||
| Gain on derivatives | 67,880 | 1,838,941 | (1,771,061) | (96.3) | |||||||||
| Pipeline, net marketing services and other | 7,587 | 12,649 | (5,062) | (40.0) | |||||||||
| Total operating revenues | 5,009,833 | 6,896,358 | (1,886,525) | (27.4) | |||||||||
| Operating expenses: | |||||||||||||
| Transportation and processing: | |||||||||||||
| Gathering | 775,114 | 1,282,402 | (507,288) | (39.6) | |||||||||
| Transmission | 846,563 | 642,688 | 203,875 | 31.7 | |||||||||
| Processing | 293,939 | 232,170 | 61,769 | 26.6 | |||||||||
| Transportation and processing to affiliate (a) | 704,094 | 148,830 | 555,264 | 373.1 | |||||||||
| Total transportation and processing | 2,619,710 | 2,306,090 | 313,620 | 13.6 | |||||||||
| LOE | 196,771 | 143,274 | 53,497 | 37.3 | |||||||||
| Production taxes | 180,236 | 95,727 | 84,509 | 88.3 | |||||||||
| Exploration | 2,735 | 3,330 | (595) | (17.9) | |||||||||
| Selling, general and administrative (b) | 244,450 | 236,171 | 8,279 | 3.5 | |||||||||
| Production depletion | 2,013,120 | 1,702,198 | 310,922 | 18.3 | |||||||||
| Other depreciation and depletion | 3,550 | 3,113 | 437 | 14.0 | |||||||||
| (Gain) loss on sale/exchange of long-lived assets | (764,431) | 17,445 | (781,876) | (4,481.9) | |||||||||
| Impairment and expiration of leases | 97,368 | 109,421 | (12,053) | (11.0) | |||||||||
| Other operating expenses | 12,696 | 9,177 | 3,519 | 38.3 | |||||||||
| Total operating expenses | 4,606,205 | 4,625,946 | (19,741) | (0.4) | |||||||||
| Operating income | $ | 403,628 | $ | 2,270,412 | $ | (1,866,784) | (82.2) | ||||||
| Per Unit ($/Mcfe): | |||||||||||||
| Gathering | $ | 0.35 | $ | 0.64 | $ | (0.29) | (45.3) | ||||||
| Transmission | 0.38 | 0.32 | 0.06 | 18.8 | |||||||||
| Processing | 0.13 | 0.12 | 0.01 | 8.3 | |||||||||
| Transportation and processing to affiliate (a) | 0.32 | 0.07 | 0.25 | 357.1 | |||||||||
| LOE | 0.09 | 0.07 | 0.02 | 28.6 | |||||||||
| Production taxes | 0.08 | 0.05 | 0.03 | 60.0 | |||||||||
| Selling, general and administrative (b) | 0.11 | 0.12 | (0.01) | (8.3) | |||||||||
| Production depletion | 0.90 | 0.84 | 0.06 | 7.1 |
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(a)Transportation and processing to affiliate represents intercompany transactions with our Gathering and Transmission segments, which are eliminated in consolidation.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
Sales of natural gas, NGLs and oil. Sales of natural gas, NGLs and oil decreased for 2024 compared to 2023 by approximately $110 million, of which approximately $640 million was attributable to lower average sales price, which was partly offset by approximately $530 million attributable to increased sales volumes. The average sales price decreased for 2024 compared to 2023 due to a lower NYMEX price, partly offset by lower basis spreads and higher NGLs price. Sales volume increased for 2024 compared to 2023 primarily as a result of sales volume increases of 164 Bcfe from the assets acquired in the Tug Hill and XcL Midstream Acquisition as well as increases from wells turned-in-line, partly offset by sales volume decreases of 107 Bcfe from the Strategic Curtailment and net decreases of 21 Bcfe due to the First NEPA Non-Operated Asset Divestiture. The increase in sales volume had a favorable impact on per unit costs for 2024 compared to 2023.
Production gain on derivatives. For 2024, we recognized a gain on derivatives of approximately $68 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $377 million due to decreases in NYMEX forward prices, partly offset by decreases in the fair market value of our basis swaps of approximately $309 million. For 2023, we recognized a gain on derivatives of approximately $1,839 million related primarily to increases in the fair market value of our NYMEX swaps and options of approximately $1,830 million due to decreases in NYMEX forward prices as well as increases in the fair market value of our basis swaps of approximately $9 million.
Transportation and processing
Gathering. Gathering expense decreased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture.
Transmission. Transmission expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to capacity charges related to the in service of the MVP (which commenced long-term firm capacity obligations on July 1, 2024) of approximately $165 million, additional contracted capacity on the Columbia Gas and Transco pipelines of an aggregate approximate $47 million and credits received in 2023 from pipeline credits of approximately $14 million. We record our equity earnings from our investment in the MVP Joint Venture in income from investments in our Statements of Consolidated Operations.
Processing. Processing expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to increased processing expense from the liquids-rich properties acquired in the Tug Hill and XcL Midstream Acquisition of approximately $40 million and increased volumes of gas requiring processing from wells that we turned-in-line in 2024.
Transportation and processing to affiliate. Affiliate transportation and processing expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to our Gathering segment's ownership of the gathering assets acquired in the Equitrans Midstream Merger, our Transmission segment's ownership of the transmission and storage assets acquired in the Equitrans Midstream Merger and our Gathering segment's ownership of the additional interest in the NEPA Gathering System acquired in the NEPA Gathering System Acquisition and as consideration for the First NEPA Non-Operated Asset Divestiture. In addition, affiliate transportation and processing expense increased on a per Mcfe basis for 2024 compared to 2023 due to our Gathering segment's ownership of the gathering assets acquired in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023.
LOE. LOE increased on an absolute and per Mcfe basis for 2024 compared to 2023 due primarily to increased LOE from the operation and maintenance of our assets, including assets acquired in the Tug Hill and XcL Midstream Acquisition and the Equitrans Midstream Merger and water assets internally-developed in the prior year, as well as increased salt water disposal costs.
Production taxes. Production tax expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due to increased property tax expense of approximately $63 million primarily from the assets acquired in the Tug Hill and XcL Midstream Acquisition and higher price as well as increased severance tax expense of approximately $24 million from increased sales volume in West Virginia.
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Selling, general and administrative. Selling, general and administrative expense increased on an absolute basis for 2024 compared to 2023 due primarily to higher legal and professional services costs as well as higher personnel costs due to increased workforce headcount. In addition, we did not recast selling, general and administrative expense for periods prior to the Equitrans Midstream Merger closing date and, upon the Equitrans Midstream Merger closing date, we adjusted our basis for selling, general and administrative expense allocation for multi-segment reporting.
Depreciation and depletion. Production depletion expense increased on an absolute and per Mcfe basis for 2024 compared to 2023 due to increased sales volume and higher annual depletion rate.
(Gain) loss on sale/exchange of long-lived assets. During 2024, we recognized a gain on the First NEPA Non-Operated Asset Divestiture of approximately $299 million and a gain on the Second NEPA Non-Operated Asset Divestiture of approximately $463 million. See Note 7 to the Consolidated Financial Statements. During 2023, we recognized a loss on sale/exchange of long-lived assets of approximately $17 million related to acreage trade agreements where the carrying value of the acres traded exceeded the fair value of the acres received.
Impairment and expiration of leases. During 2024 and 2023, we recognized impairment and expiration of leases related to leases that we no longer expect to extend or develop prior to their expiration based on our development plan.
Other operating expenses. We recognized approximately $13 million and $9 million of other operating expenses for 2024 and 2023, respectively. Other operating expenses increased for 2024 compared to 2023 due primarily to increased rig release expense and increased legal and environmental reserves, including from settlements, partly offset by proceeds received in 2024 from business interruption insurance claim recoveries. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.
GATHERING
| Years Ended December 31, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2024 | 2023 | Change | % Change | ||||||||||
| (Thousands, unless otherwise noted) | |||||||||||||
| Gathered volume (BBtu/d): | |||||||||||||
| Firm capacity | 5,277 | — | 5,277 | 100 | |||||||||
| Volumetric-based services | 4,234 | 976 | 3,258 | 334 | |||||||||
| Total gathered volume | 9,511 | 976 | 8,535 | 874 | |||||||||
| Operating revenues: | |||||||||||||
| Loss on derivatives | $ | (16,763) | $ | — | $ | (16,763) | 100 | ||||||
| Firm reservation fee revenue | 313,987 | — | 313,987 | 100 | |||||||||
| Volumetric-based fee revenue (a) | 452,476 | 161,395 | 291,081 | 180 | |||||||||
| Total operating revenues | 749,700 | 161,395 | 588,305 | 365 | |||||||||
| Operating expenses: | |||||||||||||
| Operating and maintenance | 89,897 | 15,699 | 74,198 | 473 | |||||||||
| Selling, general and administrative (b) | 38,837 | — | 38,837 | 100 | |||||||||
| Depreciation | 89,513 | 17,066 | 72,447 | 425 | |||||||||
| Gain on sale/exchange of long-lived assets | (22) | — | (22) | 100 | |||||||||
| Total operating expenses | 218,225 | 32,765 | 185,460 | 566 | |||||||||
| Operating income | $ | 531,475 | $ | 128,630 | $ | 402,845 | 313 |
(a)For agreements structured with MVCs, includes volumes up to the contractual MVC; volumes in excess of the contractual MVC are reported under volumetric-based services.
(b)Selling, general and administrative expense incurred prior to the Equitrans Midstream Merger closing date was not recast as the necessary information is not available and the cost to develop such information would be excessive.
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Gathering revenues and expenses increased for 2024 compared to 2023 primarily from the gathering assets acquired in the Equitrans Midstream Merger during the third quarter of 2024 and in the Tug Hill and XcL Midstream Acquisition during the third quarter of 2023. Prior to the completion of the Equitrans Midstream Merger, we did not own gathering assets that provided firm gathering services.
TRANSMISSION
Prior to the completion of the Equitrans Midstream Merger, we did not have transmission or storage assets.
| Year Ended December 31, 2024 | ||
|---|---|---|
| (Thousands, unless otherwise noted) | ||
| Transmission pipeline throughput (BBtu/d): | ||
| Firm capacity (a) | 3,695 | |
| Interruptible capacity | 24 | |
| Total transmission pipeline throughput | 3,719 | |
| Average contracted firm transmission reservation commitments (BBtu/d) | 4,779 | |
| Operating revenues: | ||
| Firm reservation fee revenue | $ | 183,088 |
| Volumetric-based fee revenue | 34,968 | |
| Other revenues | 237 | |
| Total operating revenues | 218,293 | |
| Operating expenses: | ||
| Operating and maintenance | 20,496 | |
| Selling, general and administrative | 17,183 | |
| Depreciation | 33,505 | |
| Amortization of intangible assets | 5,901 | |
| Loss on sale/exchange of long-lived assets | 409 | |
| Total operating expenses | 77,494 | |
| Operating income | $ | 140,799 |
(a)Includes all volumes associated with firm capacity contracts, including volumes in excess of firm capacity.
Other Income Statement Items
Other operating expenses. We recognized $337.2 million and $74.9 million of corporate other operating expenses for 2024 and 2023, respectively. Corporate other operating expenses increased for 2024 compared to 2023 due primarily to transaction costs related to the Equitrans Midstream Merger of $304.8 million and higher legal reserves, partly offset by lower transaction costs related to the Tug Hill and XcL Midstream Acquisition. See Note 1 to the Consolidated Financial Statements for a summary of consolidated other operating expenses.
Total transaction costs related to the Equitrans Midstream Merger recognized during 2024 included severance and other termination benefits and stock-based compensation costs of $165.4 million, of which $60.8 million was cash and $104.6 million was non-cash.
Income from investments. Income from investments increased for 2024 compared to 2023 due primarily to equity earnings from our investment in the MVP Joint Venture of $78.8 million, partly offset by a decrease in the fair value of our investment in the Investment Fund (defined in Note 11 to the Consolidated Financial Statements).
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Other income. Other income increased for 2024 compared to 2023 due to proceeds received from insurance claim recoveries of $19.1 million related to the assets acquired in the Tug Hill and XcL Midstream Acquisition and dividends received from our investment in the Investment Fund.
Loss on debt extinguishment. During 2024, we recognized a loss on debt extinguishment of $68.3 million due primarily to premiums and financing costs paid on our redemption and repurchase of certain of EQM's senior notes, including pursuant to the EQM Tender Offer, and non-cash losses related to our write off of the unamortized fair value adjustments of those redeemed and repurchased EQM senior notes and unamortized deferred issuance costs of the Term Loan Facility. See Note 10 to the Consolidated Financial Statements.
Interest expense, net. Net interest expense increased for 2024 compared to 2023 due primarily to interest expense on EQM's senior notes, increased interest expense on our borrowings under EQT's revolving credit facility, interest expense on EQT's 5.750% senior notes issued in January 2024, lower interest income earned on cash on hand and interest expense on Eureka Midstream, LLC's (Eureka) borrowings under its revolving credit facility, partly offset by decreased interest expense from our repayment and repurchase of certain of EQT's senior notes as well as higher capitalized interest from the assets acquired in the Tug Hill and XcL Midstream Acquisition. See Note 10 to the Consolidated Financial Statements.
Income tax expense. See Note 9 to the Consolidated Financial Statements.
Net income (loss) attributable to noncontrolling interests. During 2024, we recognized $11.4 million of net income attributable to noncontrolling interests of Eureka Midstream Holdings, a consolidated joint venture in which we acquired an equity interest as a result of the Equitrans Midstream Merger. Sees Note 1 and 6 to the Consolidated Financial Statements.
Capital Resources and Liquidity
Although we cannot provide any assurance, we believe cash flows from operating activities and availability under EQT's revolving credit facility should be sufficient to meet our cash requirements, including, but not limited to, normal operating needs, debt service obligations, planned capital expenditures and commitments for at least the next twelve months and, based on current expectations, for the long term.
Purchase Obligations
We have commitments to pay demand charges under long-term contracts and binding precedent agreements with various pipelines as well as charges for processing capacity to extract heavier liquid hydrocarbons from the natural gas stream. In addition, we have commitments to pay for services related to our operations, including electric hydraulic fracturing services and purchase equipment, materials and sand. See Note 15 to the Consolidated Financial Statements for a summary of aggregated future payments for these commitments.
Unrecognized Tax Benefits
As of December 31, 2024, we had a total reserve for unrecognized tax benefits of $9.0 million and an additional reserve of $60.4 million that was offset against deferred tax assets for general business tax credit carryforwards and net operating losses (NOLs). We settled our consolidated U.S. federal income tax liability with the IRS through 2019 in September 2024. We are currently unable to make reasonably reliable estimates of the period of cash settlement of these potential liabilities with taxing authorities. See Note 9 to the Consolidated Financial Statements for further discussion.
Planned Capital Expenditures and Sales Volume
In 2025, we expect to spend approximately $2.3 billion to $2.5 billion on total capital expenditures. We expect to fund our capital expenditures with cash generated from operations and, if required, borrowings under EQT's revolving credit facility. Because we are the operator of a high percentage of our developed acreage, the amount and timing of certain of our capital expenditures is largely discretionary. We could choose to defer a portion of our planned 2025 capital expenditures depending on a variety of factors, including prevailing and anticipated prices for natural gas, NGLs and oil; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; and drilling, completion and acquisition costs. In addition, our gathering and transmission businesses are capital intensive, requiring significant investment to develop new facilities and maintain and upgrade existing operations. In 2025, we expect our sales volume to be 2,175 Bcfe to 2,275 Bcfe.
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Material Cash Requirements
We have contractual commitments under our debt agreements, including interest payments and principal repayments. See Note 10 to the Consolidated Financial Statements for a summary of such contractual commitments, including maturity dates.
Operating Activities
Net cash provided by operating activities was $2,827 million and $3,179 million for 2024 and 2023, respectively. The decrease was due primarily to changes in working capital from movements in the market price for natural gas and timing of payments as well as higher cash operating expenses (including from transaction costs related to the Equitrans Midstream Merger), higher net interest expense and higher share-based compensation expense. Such decreases were partly offset by higher net cash settlements received on derivatives, lower net premiums paid on derivatives, higher cash operating revenues (including from pipeline revenues on assets acquired in the Equitrans Midstream Merger) and higher distributions from equity method investments (including approximately $53 million from our investment in the MVP Joint Venture).
Our cash flows from operating activities, including changes in working capital, are affected by movements in the market price for commodities. We are unable to predict such movements outside of the current market view as reflected in forward strip pricing. For a discussion of potential commodity market risks, refer to Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."
Investing Activities
Net cash used in investing activities was $1,580 million and $4,314 million for 2024 and 2023, respectively. The decrease was attributable primarily to the proceeds received from the NEPA Non-Operated Asset Divestitures in 2024 and lower cash paid for acquisitions in 2024 (primarily for the NEPA Gathering System Acquisition) compared to 2023 (primarily for the Tug Hill and XcL Midstream Acquisition), partly offset by increased capital expenditures and capital contributions made to our investment in the MVP Joint Venture of approximately $145 million.
The following table summarizes our capital expenditures by business segment.
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| (Millions) | ||||||
| Production: | ||||||
| Reserve development (a) | $ | 1,653 | $ | 1,587 | ||
| Land and lease | 156 | 130 | ||||
| Other production infrastructure | 71 | 63 | ||||
| Capitalized interest, capitalized overhead and other | 124 | 98 | ||||
| Total Production | 2,004 | 1,878 | ||||
| Gathering | 202 | 32 | ||||
| Transmission | 31 | — | ||||
| Other corporate items | 29 | 15 | ||||
| Total capital expenditures | 2,266 | 1,925 | ||||
| (Deduct) add: Non-cash items (b) | (12) | 94 | ||||
| Total cash capital expenditures | $ | 2,254 | $ | 2,019 |
(a)Capital expenditures for reserve development included capital expenditures for water infrastructure of $79.8 million and $35.9 million for 2024 and 2023, respectively.
(b)Represents the net impact of non-cash capital expenditures, including the effect of timing of receivables from working interest partners, accrued capital expenditures, transfers to or from inventory as assets are completed or assigned to a project and capitalized share-based compensation costs. The impact of accrued capital expenditures includes the current period estimate, net of the reversal of the prior period accrual.
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Financing Activities
Net cash used in financing activities was $1,126 million and $243 million for 2024 and 2023, respectively. For 2024, the primary uses of financing cash flows were our repayment and retirement of debt, repayment of EQM's revolving credit facility, payment of dividends and cash paid for taxes to net settle share-based incentive awards. For 2024, the primary sources of financing cash flows were net proceeds from the sale of units of the Midstream Joint Venture, proceeds from the issuance of EQT's 5.750% senior notes, net borrowings under EQT's revolving credit facility and proceeds from the net settlement of the Capped Call Transactions (defined in Note 10 to the Consolidated Financial Statements). For 2023, the primary uses of financing cash flows were our repayment and retirement of debt, payment of dividends and repurchase and retirement of EQT common stock, and the primary source of financing cash flows was proceeds from the Term Loan Facility borrowings.
See Note 10 to the Consolidated Financial Statements for further discussion of our debt.
On February 6, 2025, our Board of Directors declared a quarterly cash dividend of $0.1575 per share of EQT common stock, payable on March 3, 2025, to shareholders of record at the close of business on February 18, 2025.
Depending on our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may from time to time seek to redeem or repurchase our outstanding debt or equity securities through tender offers or other cash purchases in the open market or privately negotiated transactions. The amounts involved in any such transactions may be material. See Note 10 to the Consolidated Financial Statements for discussion of redemptions and repurchases of debt and Note 12 to the Consolidated Financial Statements for discussion of repurchases of EQT common stock.
Security Ratings and Financing Triggers
Our credit ratings and rating outlooks are subject to revision or withdrawal at any time by the assigning rating agency, and each rating should be evaluated independently from any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a rating agency if, in the rating agency's judgment, circumstances so warrant. See Note 4 to the Consolidated Financial Statements for a description of what is deemed investment grade.
The table below reflects the credit ratings and rating outlooks assigned to EQT's debt instruments as of February 14, 2025.
| Rating agency | Senior notes | Outlook | ||
|---|---|---|---|---|
| Moody's Investors Service, Inc. (Moody's) | Baa3 | Negative | ||
| S&P Global Ratings (S&P) | BBB– | Stable | ||
| Fitch Ratings Service (Fitch) | BBB– | Stable |
The table below reflects the credit ratings and rating outlooks assigned to EQM's debt instruments as of February 14, 2025.
| Rating agency | Senior notes | Outlook | ||
|---|---|---|---|---|
| Moody's | Ba2 | Stable | ||
| S&P | BBB– | Stable | ||
| Fitch | BB+ | Stable |
Changes in credit ratings may affect our access to the capital markets, the cost of short-term debt through interest rates and fees under our revolving credit facilities, the interest rate on our senior notes with adjustable rates, the rates available on new debt, our pool of investors and funding sources, the borrowing costs and margin deposit requirements on our OTC derivative instruments and credit assurance requirements, including collateral, in support of our midstream service contracts, joint venture arrangements or construction contracts. Margin deposits on our OTC derivative instruments are also subject to factors other than credit rating, such as natural gas prices and credit thresholds set forth in the agreements between us and our hedging counterparties.
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Our debt agreements and other financial obligations contain various provisions that, if not complied with, could result in default or event of default under EQT's revolving credit facility and Eureka's revolving credit facility, mandatory partial or full repayment of amounts outstanding, reduced loan capacity or other similar actions. The most significant covenants and events of default under our debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. EQT's revolving credit facility contains financial covenants that require us to have a total debt to total capitalization ratio no greater than 65%. As of December 31, 2024, we were in compliance with all EQT, Eureka and EQM debt provisions and covenants under our debt agreements.
See Note 10 to the Consolidated Financial Statements for a discussion of borrowings under EQT's revolving credit facility and Eureka's revolving credit facility.
Commodity Risk Management
The substantial majority of our commodity risk management program is related to hedging sales of our produced natural gas. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The derivative commodity instruments that we use are primarily swap, collar and option agreements. The following table summarizes the approximate volume and prices of our NYMEX hedge positions as of February 14, 2025. The difference between the fixed price and NYMEX price is included in average differential presented in our price reconciliation in "Average Realized Price Reconciliation." The fixed price natural gas sales agreements can be physically or financially settled.
| Q1 2025(a) | Q2 2025 | Q3 2025 | Q4 2025 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Hedged Volume (MMDth) | 332 | 336 | 281 | 281 | ||||||||||
| Hedged Volume (MMDth/d) | 3.7 | 3.7 | 3.1 | 3.1 | ||||||||||
| Swaps – Short | ||||||||||||||
| Volume (MMDth) | 250 | 290 | 281 | 95 | ||||||||||
| Avg. Price ($/Dth) | $ | 3.49 | $ | 3.11 | $ | 3.26 | $ | 3.27 | ||||||
| Calls – Short | ||||||||||||||
| Volume (MMDth) | 188 | 46 | — | 137 | ||||||||||
| Avg. Strike ($/Dth) | $ | 4.19 | $ | 3.48 | $ | — | $ | 5.49 | ||||||
| Puts – Long | ||||||||||||||
| Volume (MMDth) | 82 | 46 | — | 186 | ||||||||||
| Avg. Strike ($/Dth) | $ | 3.19 | $ | 2.83 | $ | — | $ | 3.30 | ||||||
| Option Premiums | ||||||||||||||
| Cash Settlement of Deferred Premiums (millions) | $ | — | $ | — | $ | — | $ | (45) |
(a)January 1 through March 31.
We have also entered into derivative instruments to hedge basis. We may use other contractual agreements to implement our commodity hedging strategy from time to time.
See Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Consolidated Financial Statements for further discussion of our hedging program.
Off-Balance Sheet Arrangements
As of December 31, 2024, we did not have any material off-balance sheet arrangements other than the commitments described in Note 15 to the Consolidated Financial Statements.
Commitments and Contingencies
See Note 15 to the Consolidated Financial Statements for a discussion of our commitments and contingencies.
Recently Issued Accounting Standards
Our recently issued accounting standards are described in Note 1 to the Consolidated Financial Statements.
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Critical Accounting Estimates
Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements. Management's discussion and analysis of the Consolidated Financial Statements and results of operations are based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of the Consolidated Financial Statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The following critical accounting estimates, which were reviewed by the Audit Committee of our Board of Directors, relate to our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements. Actual results could differ from our estimates.
Oil and Gas Reserves. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10, are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.
Our estimates of proved reserves are reassessed annually using geological, reservoir and production performance data. Reserve estimates are prepared by our engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our Consolidated Financial Statements.
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a twelve-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.
We believe oil and gas reserves is a "critical accounting estimate" because we must periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations and the strength of our Consolidated Balance Sheet for any quarterly or annual period could be materially affected by changes in our assumptions. Based on proved reserves as of December 31, 2024, we estimate that a 1% change in proved reserves would decrease or increase 2025 depletion expense by approximately $10 million and $21 million, respectively, based on current production estimates for 2025.
See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position."
Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in our Consolidated Financial Statements or tax returns. See Note 1 to the Consolidated Financial Statements for a discussion of significant accounting policies related to income taxes and Note 9 to the Consolidated Financial Statements for a discussion of deferred tax assets, valuation allowances and the amount of financial statement benefit recorded for uncertain tax positions.
We believe income taxes is a "critical accounting estimate" because we must assess the likelihood that our deferred tax assets will be recovered from future taxable income and exercise judgment on the amount of financial statement benefit recorded for uncertain tax positions. When evaluating whether or not a valuation allowance should be established, we exercise judgment on whether it is more likely than not (a likelihood of more than 50%) that a portion or all of our deferred tax assets will not be realized. To determine whether a valuation allowance is needed, we consider all available evidence, both positive and negative, including carrybacks, tax planning strategies, reversals of deferred tax assets and liabilities and forecasted future taxable income. To determine the amount of financial statement benefit recorded for uncertain tax positions, we consider the amounts and probabilities of outcomes that could be realized upon ultimate settlement of an uncertain tax position using facts, circumstances and information available at the reporting date. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we record an income tax expense or benefit in our Statements of Consolidated Operations.
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Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. A change to future taxable income or tax planning strategies could impact our ability to utilize deferred tax assets, which would increase or decrease our income tax expense and taxes paid. Changes in our assumptions are sensitive to numerous factors; however, based on income before taxes for the years ended December 31, 2024, 2023 and 2022, we estimate that a 1% change in our effective tax rate would decrease or increase income tax expense by approximately $3 million, $21 million and $23 million, respectively.
Derivative Instruments. We enter into derivative commodity instrument contracts primarily to reduce exposure to commodity price risk associated with future sales of our natural gas production. See Note 5 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.
We believe derivative instruments is a "critical accounting estimate" 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" for discussion of a hypothetical increase or decrease of 10% in the market price of natural gas.
Contingencies and Asset Retirement Obligations. We are involved in various legal and regulatory proceedings that arise in the ordinary course of business. We record a liability for contingencies based on our assessment that a loss is probable and the amount of the loss can be reasonably estimated. We consider many factors in making these assessments, including historical experience and matter specifics. Estimates are developed in consultation with legal counsel and are based on an analysis of potential results. See Note 15 to the Consolidated Financial Statements.
We accrue a liability for asset retirement obligations based on an estimate of the amount and timing of settlement. For oil and gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. See Note 1 to the Consolidated Financial Statements.
We believe contingencies and asset retirement obligations is a "critical accounting estimate" because we must assess the probability of loss related to contingencies and the expected amount and timing of asset retirement obligation settlement. In addition, we must determine the estimated present value of future liabilities. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. If we incur losses related to contingencies that are higher than we expect, we could incur additional costs to settle such obligations. If the expected amount and timing of our asset retirement obligations change, we will be required to adjust the carrying value of our liabilities in future periods. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
Business Combinations. Accounting for a business combination requires a company to record the identifiable assets and liabilities acquired at fair value. In the third quarter of 2024, we completed the Equitrans Midstream Merger. See Note 6 to the Consolidated Financial Statements for a discussion of the most significant assumptions used to estimate the fair value of the assets acquired and liabilities assumed in the Equitrans Midstream Merger.
We believe business combinations is a "critical accounting estimate" because the valuation of acquired assets and assumed liabilities involves significant judgment about future events. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
Property, Plant and Equipment (Including Gas, NGLs and Oil Producing Properties). We use the successful efforts method of accounting for gas, NGLs and oil producing activities. See Note 1 to the Consolidated Financial Statements for a discussion of the fair value measurement and any impairment of our oil and gas properties and other property, plant and equipment as well as our evaluation of the recoverability of capitalized costs of unproved oil and gas properties.
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We believe the accounting for our property, plant and equipment, including our gas, NGLs and oil producing properties, is a "critical accounting estimate" because the evaluations of impairment of proved properties involve significant judgment about future events, including future sales prices of natural gas and NGLs, future production costs, the amount of natural gas and NGLs recorded and timing of recoveries, as well as discount and inflation rates. In addition, evaluations of impairment of our other property, plant and equipment also involve significant judgement about future events, including assumptions about future cash flows, discount rates and operating levels. Significant changes in these estimates could result in the costs of our property, plant and equipment, including our proved and unproved properties, not being recoverable, which would require us to recognize impairment. An estimate of the sensitivity to changes in our assumptions is not practicable given the numerous assumptions that can materially affect our estimates.
See Note 1 to the Consolidated Financial Statements for additional information on impairment of our proved and unproved oil and gas properties, impairment of other property, plant and equipment. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."
Intangible Assets. Refer to Notes 1 and 6 to the Consolidated Financial Statements for a discussion of our intangible assets. We evaluate our intangible assets for impairment when indicators of impairment are present.
We believe impairment of intangible assets is a "critical accounting estimate" because the determination of whether an indicator of impairment has occurred and if further evaluation of impairment is required involves significant judgment about future events, including shifts in the market price of the assets, changes in the extent or manner in which the assets are being used, changes in legal factors of the business climate that could affect the value of the assets or a more-likely-than-not expectation that the assets will be sold or otherwise disposed of before the end of their previously estimated useful lives.
Investments in Unconsolidated Entities. Refer to Notes 1 and 11 to the Consolidated Financial Statements for a discussion of our investments in unconsolidated entities. We evaluate our investments in unconsolidated entities for impairment when events or changes in circumstances indicate that the investment's fair value is less than its carrying value. The recognition of an impairment loss is required if the impairment is considered other than temporary.
We believe the impairment of investments in unconsolidated entities is a "critical accounting estimate" because evaluations of impairment involve significant judgment about future events, such as our ability to recover the carrying value of our investment or the investee's inability to generate cash flows sufficient to justify the carrying value of our investment.
Goodwill. Goodwill is evaluated for impairment annually as of October 1 or more frequently if indicators of impairment exist. A significant amount of judgement is involved in determining if an indicator of impairment has occurred. Such indicators may include, among others, deterioration in general economic conditions, negative developments in equity and credit markets, adverse changes in the market environments in which we operate, increases in operating costs or other factors that could have a negative effect on earnings and cash flows or a trend of negative or declining cash flows over multiple periods.
We test goodwill for impairment on a qualitative or quantitative basis. When performing a qualitative impairment test, we consider a number of factors in our assessment, such as: general economic conditions, performance equity and credit markets, industry and market conditions, market capitalization, earnings and cash flow trends. When performing a quantitative impairment test, we may use a combination of the income and market approach to estimate the fair value of our reporting units.
Refer to Note 1 to the Consolidated Financial Statements for further discussion of our goodwill impairment assessment process.
We believe the impairment of goodwill is a "critical accounting estimate" because a significant amount of judgement is involved in determining whether an indicator of impairment has occurred. In addition, the estimation of the fair value of a reporting unit involves significant judgment and is sensitive to changes in assumptions, including changes in our stock price, weighted-average cost of capital, forecasted cash flows, terminal growth rates and industry multiples. Changes to assumptions could materially affect the estimated fair value of our reporting units and the resulting conclusion on impairment could materially affect our results of operations and financial position. In addition, future assumptions and estimates may materially differ from current assumptions and estimates.
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