# ANTERO RESOURCES Corp: Form 10-Q for the period ended Mar 31, 2025

- Company: [ANTERO RESOURCES Corp](/companies/ar.md) (CIK 1433270)
- Form: 10-Q
- Filed: 2025-04-30
- Accepted by EDGAR: Apr 30, 2025, 16:16 ET
- Period: 2025-03-31
- Accession: 0001558370-25-006004
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1433270/000155837025006004/ar-20250331x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1433270/000155837025006004/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $1.35bn | us-gaap:Revenues |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | $271.5m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | $54.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | $219.5m | us-gaap:ProfitLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.66 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.67 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 314,798,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $457.7m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 3 months, 2025-01-01 to 2025-03-31 | $10.1m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Current assets | at 2025-03-31 | $574.8m | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $13.05bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $1.49bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $5.64bn | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $1.29bn | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2025-03-31 | $7.22bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 45,179 characters.

*The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.*

*In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.*

### Our Company

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Appalachian Basin. As of March 31, 2025, we held approximately 526,000 net acres in the Appalachian Basin.

### Financing Highlights

### Debt Repurchase Program

During the three months ended March 31, 2025, we redeemed the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest. In addition, we repurchased $19 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of 102.725% of the principal amount thereof, plus accrued and unpaid interest. See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for additional information.

### Share Repurchase Program

During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock. During the three months ended March 31, 2025, we repurchased approximately 0.3 million shares of our common stock through our share repurchase program at a total cost of $10 million. As of March 31, 2025, we have approximately $1.0 billion of capacity remaining under our share repurchase program. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements.

### Market Conditions and Business Trends

### Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and NGLs increased, while benchmark prices for oil decreased during the three months ended March 31, 2025 as compared to the same period of 2024. As a result of the higher benchmark natural gas and NGLs prices during the three months ended March 31, 2025, we experienced increased price realizations for these products between periods, partially offset by the effects of decreased benchmark oil prices on our oil price realizations as compared to the three months ended March 31, 2024. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

The following table details the average benchmark natural gas, NGLs and oil prices:

| ​ ​ ​ | ​ ​ | ​ ​ Three Months Ended March 31, 2024 | ​ | ​ 2025 | ​ | ​ ​ ​ |
| --- | --- | --- | --- | --- | ---: | --- |
| Henry Hub ($/Mcf) (1) | ​ | $2.24 | ​ | ​ | 3.65 | ​ |
| Mont Belvieu Ethane ($/Bbl) (2) | ​ | ​ 8.07 | ​ | ​ | 11.46 | ​ |
| Mont Belvieu C3+ NGLs ($/Bbl) (3) | ​ | ​ 42.75 | ​ | ​ | 43.99 | ​ |
| West Texas Intermediate ($/Bbl) (4) | ​ | ​ 76.96 | ​ | ​ | 71.42 | ​ |

(1) NYMEX first of month average natural gas price.

(2) Intercontinental Exchange, Inc. (“ICE”) settlement ethane Oil Price Information Service (“OPIS”) futures average price for the front month contract as published on the last trading day of the month.

(3) ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month. Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices. Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition.

(4) NYMEX calendar month average settled futures price.

### Hedge Position

#### Antero Resources (Excluding Martica)

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the three months ended March 31, 2024 and 2025, substantially all of our production was unhedged. Assuming our 2025 production is the same as our production in 2024, approximately 2% of our total production for 2025 is hedged through fixed price commodity swaps. As of March 31, 2025, the estimated fair value of our commodity derivative contracts was a net liability of $107 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

#### Martica

Our consolidated VIE, Martica, also maintained a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio were fully attributable to the noncontrolling interests in Martica. During the three months ended March 31, 2025, all of Martica’s derivative contracts expired, and as of March 31, 2025, Martica’s had no derivative instruments. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

### Economic Indicators

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2024. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.0% between September and December 2024. While inflationary pressures in the United States’ economy have begun to subside, it is uncertain what impact recent tariff activity by the United States and foreign governments will have on inflation.

The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs and other global trade restrictions, among others. While our supply chain has not experienced any significant interruptions as a result of such events, there can be no assurance that we will not experience interruptions in the future.

Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

### Results of Operations

We have three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity. See Note 16—Reportable Segments to our unaudited condensed consolidated financial statements for additional information.

### Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2025

The operating results of our reportable segments were as follows (in thousands):

| ​ ​ ​ ​ ​ ​ Revenue and other: | ​ ​ ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2024 ​ Exploration and Production ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ ​ Marketing ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ Equity Method Investment in Antero Midstream (1) ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ Elimination of Unconsolidated Affiliate ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ Consolidated Total ​ | ​ ​ | ​ ​ ​ ​ ​ ​ |
| --- | --- | --- | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- |
| Natural gas sales | ​ | $474,133 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 474,133 | ​ |
| Natural gas liquids sales | ​ | ​ 517,862 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 517,862 | ​ |
| Oil sales | ​ | ​ 64,717 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 64,717 | ​ |
| Commodity derivative fair value gains | ​ | ​ 9,446 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 9,446 | ​ |
| Gathering, compression and water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 279,051 | ​ | ​ | (279,051) | ​ | ​ | — | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 48,520 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 48,520 | ​ |
| Amortization of deferred revenue, VPP | ​ | ​ 6,738 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6,738 | ​ |
| Other revenue and income | ​ | ​ 855 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 855 | ​ |
| Total revenue | ​ | ​ 1,073,751 | ​ | ​ | 48,520 | ​ | ​ | 279,051 | ​ | ​ | (279,051) | ​ | ​ | 1,122,271 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Operating expenses: | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Lease operating | ​ | ​ 29,121 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 29,121 | ​ |
| Gathering and compression | ​ | ​ 223,530 | ​ | ​ | — | ​ | ​ | 26,143 | ​ | ​ | (26,143) | ​ | ​ | 223,530 | ​ |
| Processing | ​ | ​ 255,795 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 255,795 | ​ |
| Transportation | ​ | ​ 192,956 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 192,956 | ​ |
| Water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 27,775 | ​ | ​ | (27,775) | ​ | ​ | — | ​ |
| Production and ad valorem taxes | ​ | ​ 58,168 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 58,168 | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 59,813 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 59,813 | ​ |
| Exploration | ​ | ​ 602 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 602 | ​ |
| General and administrative (excluding equity-based compensation) | ​ | ​ 39,785 | ​ | ​ | — | ​ | ​ | 11,894 | ​ | ​ | (11,894) | ​ | ​ | 39,785 | ​ |
| Equity-based compensation | ​ | ​ 16,077 | ​ | ​ | — | ​ | ​ | 9,327 | ​ | ​ | (9,327) | ​ | ​ | 16,077 | ​ |
| Depletion, depreciation and amortization | ​ | ​ 190,475 | ​ | ​ | — | ​ | ​ | 37,095 | ​ | ​ | (37,095) | ​ | ​ | 190,475 | ​ |
| Impairment of property and equipment | ​ | ​ 5,190 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5,190 | ​ |
| Accretion of asset retirement obligations | ​ | ​ 776 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 776 | ​ |
| Loss on sale of assets | ​ | ​ 188 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 188 | ​ |
| Contract termination, loss contingency, settlements and other operating expenses | ​ | ​ 2,056 | ​ | ​ | — | ​ | ​ | 566 | ​ | ​ | (566) | ​ | ​ | 2,056 | ​ |
| Total operating expenses | ​ | ​ 1,014,719 | ​ | ​ | 59,813 | ​ | ​ | 112,800 | ​ | ​ | (112,800) | ​ | ​ | 1,074,532 | ​ |
| Operating income (loss) | ​ | $59,032 | ​ | ​ | (11,293) | ​ | ​ | 166,251 | ​ | ​ | (166,251) | ​ | ​ | 47,739 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Equity in earnings of unconsolidated affiliates | ​ | $23,347 | ​ | ​ | — | ​ | ​ | 27,530 | ​ | ​ | (27,530) | ​ | ​ | 23,347 | ​ |

(1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

| ​ ​ ​ ​ ​ ​ Revenue and other: | ​ ​ ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 ​ Exploration and Production ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ ​ Marketing ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ Equity Method Investment in Antero Midstream (1) ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ Elimination of Unconsolidated Affiliate ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ Consolidated Total ​ | ​ ​ | ​ ​ ​ ​ ​ ​ |
| --- | --- | --- | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- |
| Natural gas sales | ​ | $780,005 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 780,005 | ​ |
| Natural gas liquids sales | ​ | ​ 561,432 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 561,432 | ​ |
| Oil sales | ​ | ​ 50,335 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 50,335 | ​ |
| Commodity derivative fair value losses | ​ | ​ (71,671) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (71,671) | ​ |
| Gathering, compression and water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 291,129 | ​ | ​ | (291,129) | ​ | ​ | — | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 25,558 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 25,558 | ​ |
| Amortization of deferred revenue, VPP | ​ | ​ 6,230 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6,230 | ​ |
| Other revenue and income | ​ | ​ 818 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 818 | ​ |
| Total revenue | ​ | ​ 1,327,149 | ​ | ​ | 25,558 | ​ | ​ | 291,129 | ​ | ​ | (291,129) | ​ | ​ | 1,352,707 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Operating expenses: | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Lease operating | ​ | ​ 33,986 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 33,986 | ​ |
| Gathering and compression | ​ | ​ 236,134 | ​ | ​ | — | ​ | ​ | 26,193 | ​ | ​ | (26,193) | ​ | ​ | 236,134 | ​ |
| Processing | ​ | ​ 261,155 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 261,155 | ​ |
| Transportation | ​ | ​ 197,728 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 197,728 | ​ |
| Water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 30,637 | ​ | ​ | (30,637) | ​ | ​ | — | ​ |
| Production and ad valorem taxes | ​ | ​ 55,299 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 55,299 | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 42,770 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 42,770 | ​ |
| Exploration | ​ | ​ 668 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 668 | ​ |
| General and administrative (excluding equity-based compensation) | ​ | ​ 47,300 | ​ | ​ | — | ​ | ​ | 10,622 | ​ | ​ | (10,622) | ​ | ​ | 47,300 | ​ |
| Equity-based compensation | ​ | ​ 15,145 | ​ | ​ | — | ​ | ​ | 12,402 | ​ | ​ | (12,402) | ​ | ​ | 15,145 | ​ |
| Depletion, depreciation and amortization | ​ | ​ 186,352 | ​ | ​ | — | ​ | ​ | 32,748 | ​ | ​ | (32,748) | ​ | ​ | 186,352 | ​ |
| Impairment of property and equipment | ​ | ​ 5,618 | ​ | ​ | — | ​ | ​ | 817 | ​ | ​ | (817) | ​ | ​ | 5,618 | ​ |
| Accretion of asset retirement obligations | ​ | ​ 939 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 939 | ​ |
| Gain on sale of assets | ​ | ​ (575) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (575) | ​ |
| Contract termination, loss contingency, settlements and other operating expenses | ​ | ​ (1,284) | ​ | ​ | — | ​ | ​ | 487 | ​ | ​ | (487) | ​ | ​ | (1,284) | ​ |
| Total operating expenses | ​ | ​ 1,038,465 | ​ | ​ | 42,770 | ​ | ​ | 113,906 | ​ | ​ | (113,906) | ​ | ​ | 1,081,235 | ​ |
| Operating income (loss) | ​ | $288,684 | ​ | ​ | (17,212) | ​ | ​ | 177,223 | ​ | ​ | (177,223) | ​ | ​ | 271,472 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Equity in earnings of unconsolidated affiliates | ​ | $28,661 | ​ | ​ | — | ​ | ​ | 28,020 | ​ | ​ | (28,020) | ​ | ​ | 28,661 | ​ |

(1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

### Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment:

| ​ ​ ​ ​ Production data (1) (2): | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2024 ​ ​ | ​ ​ | ​ 2025 ​ | ​ ​ | ​ ​ ​ ​ | ​ Amount of Increase (Decrease) ​ | ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Percent ​ Change ​ ​ ​ | ​ ​ ​ ​ ​ |
| --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- | ---: | --- |
| Natural gas (Bcf) | ​ | ​ 202 | ​ | ​ | 195 | ​ | ​ | (7) | ​ | (3)% | ​ |
| C2 Ethane (MBbl) | ​ | ​ 6,760 | ​ | ​ | 7,442 | ​ | ​ | 682 | ​ | 10% | ​ |
| C3+ NGLs (MBbl) | ​ | ​ 10,564 | ​ | ​ | 10,229 | ​ | ​ | (335) | ​ | (3)% | ​ |
| Oil (MBbl) | ​ | ​ 1,035 | ​ | ​ | 852 | ​ | ​ | (183) | ​ | (18)% | ​ |
| Combined (Bcfe) | ​ | ​ 312 | ​ | ​ | 306 | ​ | ​ | (6) | ​ | (2)% | ​ |
| Daily combined production (MMcfe/d) | ​ | ​ 3,426 | ​ | ​ | 3,397 | ​ | ​ | (29) | ​ | (1)% | ​ |
| **Average prices before effects of derivative settlements (3):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ | ​ |
| Natural gas (per Mcf) | ​ | $2.35 | ​ | ​ | 4.01 | ​ | ​ | 1.66 | ​ | 71% | ​ |
| C2 Ethane (per Bbl) (4) | ​ | $9.32 | ​ | ​ | 12.70 | ​ | ​ | 3.38 | ​ | 36% | ​ |
| C3+ NGLs (per Bbl) | ​ | $43.05 | ​ | ​ | 45.65 | ​ | ​ | 2.60 | ​ | 6% | ​ |
| Oil (per Bbl) | ​ | $62.53 | ​ | ​ | 59.08 | ​ | ​ | (3.45) | ​ | (6)% | ​ |
| Weighted Average Combined (per Mcfe) | ​ | $3.39 | ​ | ​ | 4.55 | ​ | ​ | 1.16 | ​ | 34% | ​ |
| **Average realized prices after effects of derivative settlements (3):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ | ​ |
| Natural gas (per Mcf) | ​ | $2.36 | ​ | ​ | 3.95 | ​ | ​ | 1.59 | ​ | 67% | ​ |
| C2 Ethane (per Bbl) (4) | ​ | $9.32 | ​ | ​ | 12.70 | ​ | ​ | 3.38 | ​ | 36% | ​ |
| C3+ NGLs (per Bbl) | ​ | $43.03 | ​ | ​ | 45.65 | ​ | ​ | 2.62 | ​ | 6% | ​ |
| Oil (per Bbl) | ​ | $62.39 | ​ | ​ | 58.97 | ​ | ​ | (3.42) | ​ | (5)% | ​ |
| Weighted Average Combined (per Mcfe) | ​ | $3.39 | ​ | ​ | 4.52 | ​ | ​ | 1.13 | ​ | 33% | ​ |
| **Average costs (per Mcfe):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ | ​ |
| Lease operating | ​ | $0.09 | ​ | ​ | 0.11 | ​ | ​ | 0.02 | ​ | 22% | ​ |
| Gathering and compression | ​ | $0.72 | ​ | ​ | 0.77 | ​ | ​ | 0.05 | ​ | 7% | ​ |
| Processing | ​ | $0.82 | ​ | ​ | 0.85 | ​ | ​ | 0.03 | ​ | 4% | ​ |
| Transportation | ​ | $0.62 | ​ | ​ | 0.65 | ​ | ​ | 0.03 | ​ | 5% | ​ |
| Production and ad valorem taxes | ​ | $0.19 | ​ | ​ | 0.18 | ​ | ​ | (0.01) | ​ | (5)% | ​ |
| Marketing expense, net | ​ | $0.04 | ​ | ​ | 0.06 | ​ | ​ | 0.02 | ​ | 50% | ​ |
| General and administrative (excluding equity-based compensation) | ​ | $0.13 | ​ | ​ | 0.15 | ​ | ​ | 0.02 | ​ | 15% | ​ |
| Depletion, depreciation, amortization and accretion | ​ | $0.61 | ​ | ​ | 0.61 | ​ | ​ | — | ​ | \* ​ | ​ |

\* Not meaningful

(1) Production data excludes volumes related to the VPP.

(2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value.

(3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

(4) The average realized price for the three months ended March 31, 2024 includes $2 million of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended March 31, 2024 would have been $9.07 per Bbl.

*Natural gas sales*. Revenues from sales of natural gas increased from $474 million for the three months ended March 31, 2024 to $780 million for the three months ended March 31, 2025, an increase of $306 million, or 65%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2025 accounted for an approximate $322 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $16 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

*NGLs sales*. Revenues from sales of NGLs increased from $518 million for the three months ended March 31, 2024 to $561 million for the three months ended March 31, 2025, an increase of $43 million, or 8%. Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2025 accounted for an approximate $51 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Lower C3+ NGLs production volumes accounted for an approximate $14 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price), partially offset by higher ethane production volumes that accounted for an approximate $6 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

*Oil sales*. Revenues from sales of oil decreased from $65 million for the three months ended March 31, 2024 to $50 million for the three months ended March 31, 2025, a decrease of $15 million, or 22%. Lower oil production volumes during the three months ended March 31, 2025 accounted for an approximate $12 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $3 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

*Commodity derivative fair value gains (losses).* Our commodity derivatives included variable price swap contracts, swaptions, basis swap contracts, call options and embedded put options. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment. Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the three months ended March 31, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $9 million and fair value losses of $72 million, respectively. For the three months ended March 31, 2024, commodity derivative fair value gains included $1 million of net cash proceeds on settled commodity derivatives gains. For the three months ended March 31, 2025, commodity derivative fair value losses included $11 million of net cash payments for settled derivative losses.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.

*Amortization of deferred revenue, VPP.* Amortization of deferred revenues associated with the VPP decreased from $7 million for the three months ended March 31, 2024 to $6 million for the three months ended March 31, 2025, a decrease of $1 million or 8%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

*Lease operating expense*. Lease operating expense increased from $29 million, or $0.09 per Mcfe, for the three months ended March 31, 2024 to $34 million, or $0.11 per Mcfe, for the three months ended March 31, 2025, primarily due to higher oilfield service costs and workover expense during the three months ended March 31, 2025, partially offset by lower water disposal costs between periods.

*Gathering, compression, processing and transportation expense.* Gathering, compression, processing and transportation expense increased from $672 million for the three months ended March 31, 2024 to $695 million for the three months ended March 31, 2025, an increase of $23 million, or 3%. This fluctuation was primarily a result of the following:

- Gathering and compression costs on a per unit basis increased from $0.72 per Mcfe for the three months ended March 31, 2024 to $0.77 per Mcfe for the three months ended March 31, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.
- Processing costs on a per unit basis increased from $0.82 per Mcfe for the three months ended March 31, 2024 to $0.85 per Mcfe for the three months ended March 31, 2025, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2025, and higher NGLs transportation fees between periods.
- Transportation costs on a per unit basis increased from $0.62 per Mcfe for the three months ended March 31, 2024 to $0.65 per Mcfe for the three months ended March 31, 2025, primarily due to higher demand fees and higher fuel costs as a result of higher natural gas prices between periods.

*Production and ad valorem tax expense.* Production and ad valorem taxes decreased from $58 million for the three months ended March 31, 2024 to $55 million for the three months ended March 31, 2025, a decrease of $3 million, or 5%, primarily due to lower production volumes between periods, partially offset by higher natural gas prices during the three months ended March 31, 2025. Production and ad valorem taxes as a percentage of natural gas revenues decreased from 12% for the three months ended March 31, 2024 to 7% for the three months ended March 31, 2025, primarily as a result of lower ad valorem taxes, which 2024 West Virginia ad valorem taxes were based on commodity prices during 2022 and 2025 West Virginia ad valorem taxes are based on commodity prices during 2023.

*General and administrative expense*. General and administrative expense (excluding equity-based compensation expense) increased from $40 million for the three months ended March 31, 2024 to $47 million for three months ended March 31, 2025, an increase of $7 million, or 19%, primarily due to higher professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the three months ended March 31, 2024 to $0.15 per Mcfe for the three months ended March 31, 2025 primarily as a result of higher overall costs and lower production volumes between periods.

*Equity-based compensation expense*. Non-cash equity-based compensation expense remained relatively consistent at $16 million and $15 million for the three months ended March 31, 2024 and 2025, respectively. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

*Depletion, depreciation and amortization expense.* DD&A expense remained relatively consistent at $190 million, or $0.61 per Mcfe, and $186 million, or $0.61 per Mcfe, for the three months ended March 31, 2024 and 2025, respectively.

*Impairment of property and equipment.* Impairment of oil and gas properties remained relatively consistent at $5 million for the three months ended March 31, 2024 and $6 million for the three months ended March 31, 2025. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

### Marketing Segment

Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.

Net marketing expense increased from $11 million, or $0.04 per Mcfe, for the three months ended March 31, 2024 to $17 million, or $0.06 per Mcfe, for the three months ended March 31, 2025, primarily due to higher firm transportation tariffs and pipeline maintenance between periods.

*Marketing revenue.* Marketing revenue decreased from $49 million for the three months ended March 31, 2024 to $26 million for the three months ended March 31, 2025, a decrease of $23 million, or 47%. This fluctuation primarily resulted from the following:

- Natural gas marketing revenue decreased by $8 million between periods primarily due to lower natural gas marketing volumes.
- Oil marketing revenue decreased by $14 million between periods primarily due to lower oil marketing volumes and prices. Lower oil marketing volumes accounted for a $8 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for a $6 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).
- NGLs marketing revenue decreased by $1 million between periods primarily due lower C3+ NGLs marketing volumes, partially offset by higher ethane marketing volumes and prices.

*Marketing expense.* Marketing expense decreased from $60 million for the three months ended March 31, 2024 to $43 million for the three months ended March 31, 2025, a decrease of $17 million, or 28%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas, NGLs and oil purchases decreased $7 million, $1 million and $13 million between periods, respectively. The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas, NGLs and oil prices during the three months ended March 31, 2025. Firm transportation costs increased from $17 million for the three months ended March 31, 2024 to $21 million, an increase of $4 million or 23%, for the three months ended March 31, 2025, primarily due to the increase in firm transportation tariffs and pipeline maintenance between periods.

### Antero Midstream Segment

*Antero Midstream revenue.* Revenue from the Antero Midstream segment increased from $279 million for the three months ended March 31, 2024 to $291 million for the three months ended March 31, 2025, an increase of $12 million. This increase is primarily due to higher gathering and processing revenues of $11 million and higher water handling revenues of $1 million. The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The increased water handling revenues between periods is primarily due to higher other fluid handling volumes, cost of service fees for blending and high-rate transfer services and wastewater handling costs, partially offset by decreased fresh water delivery volumes during the three months ended March 31, 2025.

*Antero Midstream operating expense.* Total operating expense related to the Antero Midstream segment remained relatively consistent at $113 million for the three months ended March 31, 2024 and $114 million for the three months ended March 31, 2025.

### Items Not Allocated to Segments

*Interest expense.* Interest expense decreased from $30 million for the three months ended March 31, 2024 to $23 million for the three months ended March 31, 2025, a decrease of $7 million or 23%, primarily due to the redemption or repurchase of $116 million aggregate principal amount of our Senior Notes and the conversion of $26 million aggregate principal amount of our 2026 Convertible Notes between periods and lower average Credit Facility borrowings and interest rates during the three months ended March 31, 2025.

*Income tax expense*. For the three months ended March 31, 2024, we had income tax expense of $6 million, with an effective tax rate of 15%, related to our income before income taxes of $41 million. For the three months ended March 31, 2025, we had an income tax expense of $54 million, with an effective tax rate of 20%, related to our income before income taxes of $274 million. The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense.

### Capital Resources and Liquidity

### Sources and Uses of Cash

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships. Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Based on strip prices as of March 31, 2025, we believe that net cash provided by operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

### Cash Flows

The following table summarizes our cash flows (in thousands):

| ​ ​ ​ | ​ ​ ​ | ​ ​ Three Months Ended March 31, 2024 | ​ | ​ 2025 | ​ | ​ ​ |
| --- | --- | ---: | --- | --- | ---: | --- |
| Net cash provided by operating activities | ​ | $261,610 | ​ | ​ | 457,739 | ​ |
| Net cash used in investing activities | ​ | ​ (226,810) | ​ | ​ | (207,891) | ​ |
| Net cash used in financing activities | ​ | ​ (34,800) | ​ | ​ | (249,848) | ​ |
| Net increase in cash and cash equivalents | ​ | $— | ​ | ​ | — | ​ |

*Operating activities.* Net cash provided by operating activities was $262 million and $458 million for the three months ended March 31, 2024 and 2025, respectively. Net cash provided by operating activities increased between periods primarily due to higher natural gas and NGLs prices and lower interest expense, partially offset by changes in working capital, higher net marketing expense and lower oil revenues between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict.

*Investing activities.* Net cash used in investing activities decreased from $227 million for the three months ended March 31, 2024 to $208 million for the three months ended March 31, 2025, primarily due to lower well completions between periods and decreased drilling activity during the three months ended March 31, 2025.

*Financing activities.* Net cash used in financing activities increased from $35 million for the three months ended March 31, 2024 to $250 million for the three months ended March 31, 2025. The increase in net cash used in financing activities between periods is primarily due to Senior Note redemptions and repurchases of $118 million during the three months ended March 31, 2025, higher net repayments on our Credit Facility of $87 million, share repurchases of $10 million during the three months ended March 31, 2025 and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $7 million, partially offset by decreased distributions to the noncontrolling interests in Martica of $7 million between periods.

### 2025 Capital Budget and Capital Spending

On February 12, 2025, we announced a net capital budget for 2025 of $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2025, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

For the three months ended March 31, 2025, our total consolidated capital expenditures were $188 million, including drilling and completion costs of $157 million, leasehold acquisitions of $30 million and other capital expenditures of $1 million.

### Debt Agreements

See Note 7—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our debt agreements.

### Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements. The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our unaudited condensed consolidated financial statements that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited condensed consolidated financial statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our critical accounting estimates.

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties.

Based on future prices as of March 31, 2025, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the three months ended March 31, 2024 and 2025.

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

### New Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for information on new accounting pronouncements.

### Off-Balance Sheet Arrangements

See Note 13—Commitments to the unaudited condensed consolidated financial statements for information on off balance sheet arrangements.

## Market risk

As filed, 7,832 characters.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices, as well as interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

### Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for oil. Pricing for natural gas, NGLs and oil has, historically, been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between commodity prices at sales points and the applicable index price.

We may enter into financial derivative instruments for a portion of our natural gas, NGLs and oil production when circumstances warrant and management believes that favorable future prices can be secured in order to mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the three months ended March 31, 2024 and 2025, substantially all of our production was unhedged.

Our financial hedging activities may include commodity derivative instruments that are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price risk associated with our production. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty, collars that set a floor and ceiling price for the hedged production, basis differential swaps or call or embedded put options, among others. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of March 31, 2025, our commodity derivatives included fixed swaps, collars, call options and embedded put options at index-based pricing for a nominal portion of our production. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Based on our production and our derivative instruments that settled during the three months ended March 31, 2025, our revenues would have decreased by $37 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices, excluding the effects of changes in the fair value of our derivative positions which remain open as of March 31, 2025.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception or other derivative scope exceptions, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark to market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations and comprehensive income. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as commodity derivative fair value gains (losses) in the unaudited condensed consolidated statements of operations and comprehensive income (loss).

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of December 31, 2024 and March 31, 2025, the estimated fair value of our commodity derivative instruments was a net liability of $47 million and $107 million, respectively, comprised of current and noncurrent assets and liabilities.

### Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($513 million as of March 31, 2025), which we market to energy companies, end users and refineries, and commodity derivative contracts ($1 million as of March 31, 2025).

We are subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs and oil. While we do at times require customers to post letters of credit or other credit support in connection with their obligations, we generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

In addition, we are exposed to the credit risk of our counterparties for our derivative instruments. Credit risk is the potential failure of a counterparty to perform under the terms of a derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions that management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of March 31, 2025, we have commodity hedges in place with five different counterparties, four of which are lenders under the Unsecured Credit Facility. As of March 31, 2025, we did not have any commodity derivative assets with bank counterparties under our Unsecured Credit Facility. The estimated fair value of our commodity derivative assets has been risk-adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) as of March 31, 2025. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of March 31, 2025. We are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of March 31, 2025, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

### Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate. The average annualized interest rate incurred on the Credit Facility for borrowings during the three months ended March 31, 2025 was 6.0%. We estimate that a 1.0% increase in the applicable average interest rates for the three months ended March 31, 2025 would have resulted in an estimated $1 million increase in interest expense.

## Controls and procedures

As filed, 1,602 characters.

### Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025 at a level of reasonable assurance.

### Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 501 characters.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2024 Form 10-K. There have been no material changes to the risks described in such report. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us.

Filed Apr 30, 2025.
Source: SEC EDGAR, the filing index for accession 0001558370-25-006004. Last ingested by Listed: Oct 29, 2026, 05:24 ET. No prices; not investment advice.