# ANTERO RESOURCES Corp: Form 10-Q for the period ended Mar 31, 2024

- Company: [ANTERO RESOURCES Corp](/companies/ar.md) (CIK 1433270)
- Form: 10-Q
- Filed: 2024-04-24
- Accepted by EDGAR: Apr 24, 2024, 16:18 ET
- Period: 2024-03-31
- Accession: 0001558370-24-005602
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1433270/000155837024005602/ar-20240331x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1433270/000155837024005602/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-01-01 to 2024-03-31 | $1.12bn | us-gaap:Revenues |
| Operating income | 3 months, 2024-01-01 to 2024-03-31 | $65.2m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2024-01-01 to 2024-03-31 | $10.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-01-01 to 2024-03-31 | $48.3m | us-gaap:ProfitLoss |
| Diluted EPS | 3 months, 2024-01-01 to 2024-03-31 | $0.12 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-01-01 to 2024-03-31 | $0.12 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-01-01 to 2024-03-31 | 312,503,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2024-01-01 to 2024-03-31 | $261.6m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Current assets | at 2024-03-31 | $402.7m | us-gaap:AssetsCurrent |
| Total assets | at 2024-03-31 | $13.55bn | us-gaap:Assets |
| Current liabilities | at 2024-03-31 | $1.38bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-03-31 | $6.28bn | us-gaap:Liabilities |
| Long-term debt | at 2024-03-31 | $1.51bn | us-gaap:LongTermDebtNoncurrent |
| Shareholders' equity | at 2024-03-31 | $7.05bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 45,805 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 are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. 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, 2024, we held approximately 517,000 net acres in the Appalachian Basin.

### Market Conditions and Business Trends

### Commodity Markets

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Natural gas benchmark prices decreased significantly while NGLs and oil benchmark prices remained consistent during the three months ended March 31, 2024 as compared to the same period of 2023. As a result of the lower benchmark natural gas prices, we experienced a decrease in price realizations for natural gas and ethane products during 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 and oil prices:

| ​ ​ ​ | ​ ​ | ​ ​ Three Months Ended March 31, 2023 | ​ | ​ 2024 | ​ | ​ ​ ​ |
| --- | --- | ---: | --- | --- | ---: | --- |
| Henry Hub (1) ($/Mcf) | ​ | $3.42 | ​ | ​ | 2.24 | ​ |
| West Texas Intermediate (2) ($/Bbl) | ​ | ​ 76.13 | ​ | ​ | 76.96 | ​ |

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

(2) Energy Information Administration 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, 2023 and 2024, 2% and 1%, respectively, of our production was hedged through fixed price commodity swaps. The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of March 31, 2024, our fixed price NGLs swap positions excluding Martica were as follows:

| ​ ​ ​ Commodity / Settlement Period Propane | ​ ​ ​ ​ | ​ ​ ​ Index ​ | ​ ​ ​ ​ | ​ ​ ​ Contracted Volume ​ | ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Weighted Average Price ​ ​ | ​ ​ | ​ ​ ​ ​ ​ |
| --- | --- | --- | --- | ---: | --- | --- | ---: | --- | --- |
| April-December 2024 | ​ | Mont Belvieu Propane-OPIS TET | ​ | 2,750 | MBbl | ​ | $33.67 | /Bbl | ​ |

As of March 31, 2024, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

| ​ ​ Commodity / Settlement Period Natural Gas | ​ ​ ​ ​ | ​ ​ Index to Basis Differential ​ | ​ ​ ​ | ​ ​ Contracted Volume ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ Weighted Average Hedged Differential ​ ​ | ​ ​ | ​ ​ ​ ​ |
| --- | --- | --- | --- | ---: | --- | --- | ---: | --- | --- |
| April-December 2024 | ​ | NYMEX to TCO | ​ | 14 | Bcf | ​ | $0.530 | /MMBtu | ​ |

We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties. As of March 31, 2024, our call option and embedded put option arrangements were as follows:

| ​ ​ ​ Commodity / Settlement Period Natural Gas | ​ ​ ​ ​ | ​ ​ ​ Index ​ | ​ ​ ​ ​ | ​ ​ ​ Contracted Volume ​ | ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ ​ ​ Call Option Strike Price ​ ​ | ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Embedded Put Option Strike Price ​ ​ | ​ ​ | ​ ​ ​ ​ |
| --- | --- | --- | --- | ---: | --- | --- | --- | --- | --- | --- | --- | --- |
| April-December 2024 | ​ | Henry Hub | ​ | 15 | Bcf | ​ | $2.477 | /MMBtu | ​ | $2.527 | /MMBtu | ​ |
| January-December 2025 | ​ | Henry Hub | ​ | 16 | Bcf | ​ | ​ 2.564 | /MMBtu | ​ | ​ 2.614 | /MMBtu | ​ |
| January-December 2026 | ​ | Henry Hub | ​ | 12 | Bcf | ​ | ​ 2.629 | /MMBtu | ​ | ​ 2.679 | /MMBtu | ​ |
| ​ | ​ | ​ | ​ | 43 | Bcf | ​ | ​ 2.552 | /MMBtu | ​ | ​ 2.602 | /MMBtu | ​ |

As of March 31, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $27 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more information.

#### Martica

Our consolidated VIE, Martica, also maintains 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 are fully attributable to the noncontrolling interests in Martica. As of March 31, 2024, Martica’s fixed price natural gas and oil swap positions were as follows:

| ​ ​ ​ Commodity / Settlement Period Natural Gas | ​ ​ ​ ​ | ​ ​ ​ Index ​ | ​ ​ ​ ​ | ​ ​ ​ Contracted Volume ​ | ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Weighted Average Price ​ ​ | ​ ​ | ​ ​ ​ ​ ​ |
| --- | --- | --- | --- | ---: | --- | --- | --- | --- | --- |
| April-December 2024 | ​ | Henry Hub | ​ | 7 | Bcf | ​ | $2.33 | /MMBtu | ​ |
| January-March 2025 | ​ | Henry Hub | ​ | 1 | Bcf | ​ | ​ 2.53 | /MMBtu | ​ |
| ​ | ​ | ​ | ​ | 8 | Bcf | ​ | ​ 2.37 | /MMBtu | ​ |
| **Oil** | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ | ​ | ​ |
| April-December 2024 | ​ | West Texas Intermediate | ​ | 12 | MBbl | ​ | $44.02 | /Bbl | ​ |
| January-March 2025 | ​ | West Texas Intermediate | ​ | 3 | MBbl | ​ | ​ 45.06 | /Bbl | ​ |
| ​ | ​ | ​ | ​ | 15 | MBbl | ​ | ​ 44.27 | /Bbl | ​ |

As of March 31, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million. See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for more 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 the first quarter of 2024. For example, the Consumer Price Index (“CPI”) for all urban consumers increased 5% from March 2022 to March 2023 and an additional 3% from March 2023 to March 2024 as compared to the Federal Reserve’s stated goal of 2%. 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 March 2024, the Federal Reserve increased the federal funds interest rate by 5.25%. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “—Results of Operations” for more information.

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 on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events.

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 operating 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 the unaudited condensed consolidated financial statements for more information.

### Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2024

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

| ​ ​ ​ ​ ​ ​ Revenue and other: | ​ ​ ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2023 ​ Exploration and Production ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ ​ Marketing ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ Equity Method Investment in Antero Midstream ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ Elimination of Unconsolidated Affiliate ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ Consolidated Total ​ | ​ ​ | ​ ​ ​ ​ ​ ​ ​ |
| --- | --- | --- | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- |
| Natural gas sales | ​ | $668,315 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 668,315 | ​ |
| Natural gas liquids sales | ​ | ​ 495,435 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 495,435 | ​ |
| Oil sales | ​ | ​ 51,811 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 51,811 | ​ |
| Commodity derivative fair value gains | ​ | ​ 126,192 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 126,192 | ​ |
| Gathering, compression and water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 259,475 | ​ | ​ | (259,475) | ​ | ​ | — | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 58,529 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 58,529 | ​ |
| Amortization of deferred revenue, VPP | ​ | ​ 7,533 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 7,533 | ​ |
| Other revenue and income | ​ | ​ 533 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 533 | ​ |
| Total revenue | ​ | ​ 1,349,819 | ​ | ​ | 58,529 | ​ | ​ | 259,475 | ​ | ​ | (259,475) | ​ | ​ | 1,408,348 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Operating expenses: | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Lease operating | ​ | ​ 29,321 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 29,321 | ​ |
| Gathering and compression | ​ | ​ 212,604 | ​ | ​ | — | ​ | ​ | 24,118 | ​ | ​ | (24,118) | ​ | ​ | 212,604 | ​ |
| Processing | ​ | ​ 237,268 | ​ | ​ | — | ​ | ​ | . | ​ | ​ | — | ​ | ​ | 237,268 | ​ |
| Transportation | ​ | ​ 195,300 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 195,300 | ​ |
| Water handling | ​ | ​ — | ​ | ​ | — | ​ | ​ | 33,755 | ​ | ​ | (33,755) | ​ | ​ | — | ​ |
| Production and ad valorem taxes | ​ | ​ 49,276 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 49,276 | ​ |
| Marketing | ​ | ​ — | ​ | ​ | 81,361 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 81,361 | ​ |
| Exploration and mine expenses | ​ | ​ 763 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 763 | ​ |
| General and administrative (excluding equity-based compensation) | ​ | ​ 44,243 | ​ | ​ | — | ​ | ​ | 11,020 | ​ | ​ | (11,020) | ​ | ​ | 44,243 | ​ |
| Equity-based compensation | ​ | ​ 13,018 | ​ | ​ | — | ​ | ​ | 6,327 | ​ | ​ | (6,327) | ​ | ​ | 13,018 | ​ |
| Depletion, depreciation and amortization | ​ | ​ 167,582 | ​ | ​ | — | ​ | ​ | 35,196 | ​ | ​ | (35,196) | ​ | ​ | 167,582 | ​ |
| Impairment of property and equipment | ​ | ​ 15,560 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 15,560 | ​ |
| Accretion of asset retirement obligations | ​ | ​ 878 | ​ | ​ | — | ​ | ​ | 44 | ​ | ​ | (44) | ​ | ​ | 878 | ​ |
| Contract termination, loss contingency and other operating expenses | ​ | ​ 6,012 | ​ | ​ | 23,763 | ​ | ​ | 915 | ​ | ​ | (915) | ​ | ​ | 29,775 | ​ |
| Gain on sale of assets | ​ | ​ (91) | ​ | ​ | — | ​ | ​ | (245) | ​ | ​ | 245 | ​ | ​ | (91) | ​ |
| Total operating expenses | ​ | ​ 971,734 | ​ | ​ | 105,124 | ​ | ​ | 111,130 | ​ | ​ | (111,130) | ​ | ​ | 1,076,858 | ​ |
| Operating income (loss) | ​ | $378,085 | ​ | ​ | (46,595) | ​ | ​ | 148,345 | ​ | ​ | (148,345) | ​ | ​ | 331,490 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Equity in earnings of unconsolidated affiliates | ​ | $17,681 | ​ | ​ | — | ​ | ​ | 24,456 | ​ | ​ | (24,456) | ​ | ​ | 17,681 | ​ |

| ​ ​ ​ ​ ​ ​ Revenue and other: | ​ ​ ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2024 ​ Exploration and Production ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ ​ Marketing ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ Equity Method Investment in Antero Midstream ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ 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 | ​ | ​ 173,054 | ​ | ​ | — | ​ | ​ | 37,095 | ​ | ​ | (37,095) | ​ | ​ | 173,054 | ​ |
| Impairment of property and equipment | ​ | ​ 5,190 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 5,190 | ​ |
| Accretion of asset retirement obligations | ​ | ​ 776 | ​ | ​ | — | ​ | ​ | 44 | ​ | ​ | (44) | ​ | ​ | 776 | ​ |
| Loss on sale of assets | ​ | ​ 188 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 188 | ​ |
| Contract termination, loss contingency and other operating expenses | ​ | ​ 2,056 | ​ | ​ | — | ​ | ​ | 522 | ​ | ​ | (522) | ​ | ​ | 2,056 | ​ |
| Total operating expenses | ​ | ​ 997,298 | ​ | ​ | 59,813 | ​ | ​ | 112,800 | ​ | ​ | (112,800) | ​ | ​ | 1,057,111 | ​ |
| Operating income (loss) | ​ | $76,453 | ​ | ​ | (11,293) | ​ | ​ | 166,251 | ​ | ​ | (166,251) | ​ | ​ | 65,160 | ​ |
| ​ | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
| Equity in earnings of unconsolidated affiliates | ​ | $23,347 | ​ | ​ | — | ​ | ​ | 27,530 | ​ | ​ | (27,530) | ​ | ​ | 23,347 | ​ |

### 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, 2023 ​ ​ | ​ ​ ​ | ​ 2024 ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ Amount of Increase (Decrease) ​ | ​ ​ | ​ ​ ​ ​ ​ | ​ ​ ​ ​ Percent ​ Change ​ ​ ​ |
| --- | --- | ---: | --- | --- | ---: | --- | --- | ---: | --- | ---: |
| Natural gas (Bcf) | ​ | ​ 194 | ​ | ​ | 202 | ​ | ​ | 8 | ​ | 4% |
| C2 Ethane (MBbl) | ​ | ​ 6,141 | ​ | ​ | 6,760 | ​ | ​ | 619 | ​ | 10% |
| C3+ NGLs (MBbl) | ​ | ​ 9,857 | ​ | ​ | 10,564 | ​ | ​ | 707 | ​ | 7% |
| Oil (MBbl) | ​ | ​ 831 | ​ | ​ | 1,035 | ​ | ​ | 204 | ​ | 25% |
| Combined (Bcfe) | ​ | ​ 295 | ​ | ​ | 312 | ​ | ​ | 17 | ​ | 6% |
| Daily combined production (MMcfe/d) | ​ | ​ 3,274 | ​ | ​ | 3,426 | ​ | ​ | 152 | ​ | 5% |
| **Average prices before effects of derivative settlements (3):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ |
| Natural gas (per Mcf) | ​ | $3.45 | ​ | ​ | 2.35 | ​ | ​ | (1.10) | ​ | (32)% |
| C2 Ethane (per Bbl) (4) | ​ | $11.73 | ​ | ​ | 9.32 | ​ | ​ | (2.41) | ​ | (21)% |
| C3+ NGLs (per Bbl) | ​ | $42.95 | ​ | ​ | 43.05 | ​ | ​ | 0.10 | ​ | \* ​ |
| Oil (per Bbl) | ​ | $62.35 | ​ | ​ | 62.53 | ​ | ​ | 0.18 | ​ | \* ​ |
| Weighted Average Combined (per Mcfe) | ​ | $4.13 | ​ | ​ | 3.39 | ​ | ​ | (0.74) | ​ | (18)% |
| **Average realized prices after effects of derivative settlements (3):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ |
| Natural gas (per Mcf) | ​ | $3.38 | ​ | ​ | 2.36 | ​ | ​ | (1.02) | ​ | (30)% |
| C2 Ethane (per Bbl) (4) | ​ | $11.73 | ​ | ​ | 9.32 | ​ | ​ | (2.41) | ​ | (21)% |
| C3+ NGLs (per Bbl) | ​ | $42.89 | ​ | ​ | 43.03 | ​ | ​ | 0.14 | ​ | \* ​ |
| Oil (per Bbl) | ​ | $61.90 | ​ | ​ | 62.39 | ​ | ​ | 0.49 | ​ | 1% |
| Weighted Average Combined (per Mcfe) | ​ | $4.08 | ​ | ​ | 3.39 | ​ | ​ | (0.69) | ​ | (17)% |
| **Average costs (per Mcfe):** | ​ | ​ ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ ​ |
| Lease operating | ​ | $0.10 | ​ | ​ | 0.09 | ​ | ​ | (0.01) | ​ | (10)% |
| Gathering and compression | ​ | $0.72 | ​ | ​ | 0.72 | ​ | ​ | — | ​ | \* ​ |
| Processing | ​ | $0.81 | ​ | ​ | 0.82 | ​ | ​ | 0.01 | ​ | 1% |
| Transportation | ​ | $0.66 | ​ | ​ | 0.62 | ​ | ​ | (0.04) | ​ | (6)% |
| Production and ad valorem taxes | ​ | $0.17 | ​ | ​ | 0.19 | ​ | ​ | 0.02 | ​ | 12% |
| Marketing expense, net | ​ | $0.08 | ​ | ​ | 0.04 | ​ | ​ | (0.04) | ​ | (50)% |
| General and administrative (excluding equity-based compensation) | ​ | $0.15 | ​ | ​ | 0.13 | ​ | ​ | (0.02) | ​ | (13)% |
| Depletion, depreciation, amortization and accretion | ​ | $0.57 | ​ | ​ | 0.56 | ​ | ​ | (0.01) | ​ | (2)% |

\* 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 (but does not include proceeds from the derivative monetizations in 2023), 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, 2023 and 2024 includes $6 million and $2 million, respectively, 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, 2023 and 2024 would have been $10.76 per Bbl and $9.07 per Bbl, respectively.

*Natural gas sales*. Revenues from sales of natural gas decreased from $668 million for the three months ended March 31, 2023 to $474 million for the three months ended March 31, 2024, a decrease of $194 million, or 29%. Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2024 accounted for an approximate $222 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Higher natural gas production volumes accounted for an approximate $28 million increase 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 $495 million for the three months ended March 31, 2023 to $518 million for the three months ended March 31, 2024, an increase of $23 million, or 5%. Higher NGLs production volumes accounted for an approximate $38 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2024 accounted for an approximate $15 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

*Oil sales*. Revenues from sales of oil increased from $52 million for the three months ended March 31, 2023 to $65 million for the three months ended March 31, 2024, an increase of $13 million, or 25%. Higher oil production volumes during the three months ended March 31, 2024 accounted for an approximate $13 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

*Commodity derivative fair value gains.* Our commodity derivatives included fixed price swap contracts, 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 and comprehensive income. For the three months ended March 31, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $126 million and $9 million, respectively. For the three months ended March 31, 2023, commodity derivative fair value gains included $14 million of net cash payments for settled commodity derivative losses and a $202 million cash payment for the early settlement of our swaption. 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.

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. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

*Amortization of deferred revenue, VPP.* Amortization of deferred revenues associated with the VPP decreased from $8 million for the three months ended March 31, 2023 to $7 million for the three months ended March 31, 2024, a decrease of $1 million, or 11%, 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 remained consistent between periods at $29 million for both the three months ended March 31, 2023 and 2024. On a per unit basis, lease operating expense decreased from $0.10 per Mcfe for the three months ended March 31, 2023 to $0.09 per Mcfe for the three months ended March 31, 2024, primarily due to higher production volumes between periods.

*Gathering, compression, processing and transportation expense.* Gathering, compression, processing and transportation expense increased from $645 million for the three months ended March 31, 2023 to $672 million for the three months ended March 31, 2024, an increase of $27 million, or 4%. This fluctuation primarily resulted from higher production volumes between periods and the following:

- Gathering and compression costs on a per unit basis remained relatively consistent at $0.72 per Mcfe for both the three months ended March 31, 2023 and 2024.
- Processing costs increased from $0.81 per Mcfe for the three months ended March 31, 2023 to $0.82 per Mcfe for the three months ended March 31, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.
- Transportation costs decreased from $0.66 per Mcfe for the three months ended March 31, 2023 to $0.62 per Mcfe for the three months ended March 31, 2024 primarily due to lower demand fees and fuel costs as a result of lower commodity prices between periods.

*Production and ad valorem tax expense.* Production and ad valorem taxes increased from $49 million for the three months ended March 31, 2023 to $58 million for the three months ended March 31, 2024, an increase of $9 million, or 18%, primarily due to higher ad valorem taxes and production volumes between periods, partially offset by lower natural gas prices during the three months ended March 31, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 7.4% for the three months ended March 31, 2023 to 12.3% for the three months ended March 31, 2024, primarily as a result of higher ad valorem taxes, which 2024 ad valorem taxes are based on commodity prices during 2022.

*General and administrative expense*. General and administrative expense (excluding equity-based compensation expense) decreased from $44 million for the three months ended March 31, 2023 to $40 million for the three months ended March 31, 2024, a decrease of $4 million, or 10%, primarily due to lower professional service fees between periods. General and administrative expense on a per unit basis (excluding equity-based compensation) decreased from $0.15 per Mcfe for the three months ended March 31, 2023 to $0.13 per Mcfe for the three months ended March 31, 2024 as a result of higher production volumes and lower overall costs between periods.

*Equity-based compensation expense*. Noncash equity-based compensation expense increased from $13 million for the three months ended March 31, 2023 to $16 million for the three months ended March 31, 2024, an increase of $3 million, or 23%. This increase was primarily due to annual equity awards granted in March 2023 that were outstanding for the entire first quarter of 2024 and annual equity awards granted during March 2024, partially offset by prior year awards that were fully vested during the year ended December 31, 2023. See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for more information.

*Depletion, depreciation, and amortization expense (“DD&A expense”)*. DD&A expense increased from $168 million for the three months ended March 31, 2023 to $173 million for the three months ended March 31, 2024, an increase of $5 million, or 3%, primarily due to higher production volumes between periods. On a per unit basis, DD&A expense remained relatively consistent at $0.57 and $0.56 per Mcfe for the three months ended March 31, 2023 and 2024, respectively.

*Impairment of property and equipment.* Impairment of oil and gas properties decreased from $16 million for the three months ended March 31, 2023 to $5 million for the three months ended March 31, 2024, a decrease of $11 million, or 67%, primarily due to lower impairments of expiring leases between periods. 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 utilize.

### 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 decreased from $23 million, or $0.08 per Mcfe, for the three months ended March 31, 2023 to $11 million, or $0.04 per Mcfe, for the three months ended March 31, 2024, primarily due to lower firm transportation commitments.

*Marketing revenue.* Marketing revenue decreased from $59 million for the three months ended March 31, 2023 to $49 million for the three months ended March 31, 2024, a decrease of $10 million, or 17%. This fluctuation primarily resulted from the following:

- Natural gas marketing revenue decreased by $30 million between periods primarily due to lower natural gas prices and marketing volumes. Lower natural gas marketing volumes accounted for a $24 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 natural gas 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).
- Oil marketing revenue increased by $16 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for an $8 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an $8 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).
- NGLs marketing revenues were $3 million for the three months ended March 31, 2024. There were no NGLs marketing revenues for the three months ended March 31, 2023.

*Marketing expense.* Marketing expense decreased from $81 million for the three months ended March 31, 2023 to $60 million for the three months ended March 31, 2024, a decrease of $21 million, or 26%. 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, oil and NGLs purchases decreased $9 million between periods, primarily due to lower natural gas prices and marketing volumes between periods, partially offset by higher oil and NGLs marketing volumes and prices between periods. Firm transportation costs were $29 million for the three months ended March 31, 2023 and $17 million for the three months ended March 31, 2024, a decrease of $12 million due to the reduction in firm transportation commitments between periods.

*Contract termination, loss contingency and other operating expenses.* Contract termination, loss contingency and other operating expenses attributable to our marketing segment for the three months ended March 31, 2023 is due to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline. Our marketing segment did not incur any contract termination loss contingency and other operating expenses for the three months ended March 31, 2024.

### Antero Midstream Segment

*Antero Midstream revenue.* Revenue from the Antero Midstream segment increased from $259 million for the three months ended March 31, 2023 to $279 million for the three months ended March 31, 2024, an increase of $20 million. This increase is primarily due to higher gathering and processing revenues of $28 million as a result of the expiration of the growth incentive fee rebate program on December 31, 2023 and increased throughput between periods, partially offset by lower water handling revenues of $8 million primarily due to decreased water trucking volumes and fewer wells serviced by fresh water deliveries between periods.

*Antero Midstream operating expense.* Total operating expense related to the Antero Midstream segment remained relatively consistent at $111 million and $113 million for the three months ended March 31, 2023 and 2024, respectively.

### Discussion of Items Not Allocated to Segments

*Interest expense.* Interest expense increased from $26 million for the three months ended March 31, 2023 to $30 million for the three months ended March 31, 2024, an increase of $4 million, or 17%, primarily due to higher average Credit Facility borrowings between periods and higher benchmark interest rates during the three months ended March 31, 2024, partially offset by the conversion or inducement of $39 million aggregate principal amount of our 2026 Convertible Notes between periods.

*Income tax expense*. Income tax expense decreased from $62 million for the three months ended March 31, 2023 to $10 million for the three months ended March 31, 2024, a decrease of $52 million, or 84%, primarily due to lower income before taxes of $265 million between periods. Our effective tax rate remained relatively consist for the three months ended March 31, 2023 and 2024 at 19% and 17%, respectively.

### 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 partnership. 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, 2024, 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, 2023 | ​ | ​ 2024 | ​ | ​ ​ |
| --- | --- | ---: | --- | --- | ---: | --- |
| Net cash provided by operating activities | ​ | $343,902 | ​ | ​ | 261,610 | ​ |
| Net cash used in investing activities | ​ | ​ (350,804) | ​ | ​ | (226,810) | ​ |
| Net cash provided by (used in) financing activities | ​ | ​ 6,902 | ​ | ​ | (34,800) | ​ |
| Net increase in cash and cash equivalents | ​ | $— | ​ | ​ | — | ​ |

*Operating activities.* Net cash provided by operating activities was $344 million and $262 million for the three months ended March 31, 2023 and 2024, respectively. Net cash provided by operating activities decreased between periods primarily due to lower natural gas prices, changes in working capital and higher gathering, compression, processing and transportation expenses, partially offset by a $202 million payment for early settlement of our swaption agreement in the three months ended March 31, 2023, higher production volumes and lower net marketing expense 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 $351 million for the three months ended March 31, 2023 to $227 million for the three months ended March 31, 2024, primarily due to a decrease in drilling activity, drilling rig count, completions stages and leasing activity between periods.

*Financing activities.* Net cash provided by financing activities was $7 million for the three months ended March 31, 2023. Net cash used in financing activities was $35 million for the three months ended March 31, 2024. This change between periods is primarily due to lower net borrowings on our Credit Facility of $147 million between periods, partially offset by decreased share repurchases of $75 million and decreased distributions to the noncontrolling interests in Martica of $28 million between periods.

### 2024 Capital Budget and Capital Spending

On February 14, 2024, we announced a net capital budget for 2024 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 2024, we plan to complete 45 to 50 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, 2023, our total consolidated capital expenditures were $342 million, including drilling and completion costs of $267 million, leasehold acquisitions of $72 million and other capital expenditures of $3 million. For the three months ended March 31, 2024, our total consolidated capital expenditures were $219 million, including drilling and completion costs of $187 million, leasehold acquisitions of $26 million and other capital expenditures of $6 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 2023 Form 10-K for information on our senior notes.

### 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 2023 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, 2024, 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, 2023 and 2024.

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 further information on off balance sheet arrangements.

## Market risk

As filed, 8,255 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, 2023 and 2024, 2% and 1%, respectively, of our production was hedged through fixed price commodity swaps. Our financial hedging activities may include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of March 31, 2024, our commodity derivatives included fixed swaps, basis differential swaps, call options and embedded put options at index-based pricing for a portion of our production. See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for more information.

Our financial hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to natural gas, NGLs and oil price fluctuations. 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 embedded options. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity.

Under the Credit Facility, we are permitted to hedge up to 75% of our projected production for the next 60 months. We may enter into hedge contracts with a term greater than 60 months, and for no longer than 72 months, for up to 65% of our estimated production. Based on our production and our derivative instruments that settled during the three months ended March 31, 2024, our revenues would have decreased by $38 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, 2024.

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.”

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, 2023 and March 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability $37 million and $29 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 ($326 million as of March 31, 2024), which we market to energy companies, end users and refineries, and commodity derivative contracts ($11 million as of March 31, 2024).

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. We have commodity hedges in place with four different counterparties, three of which are lenders under the Credit Facility. As of March 31, 2024, we did not have any derivative assets with bank counterparties under our 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, 2024. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of March 31, 2024. Other than as provided by the Credit Facility, 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, 2024, 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, 2024 was 7.8%. We estimate that a 1.0% increase in the applicable average interest rates for the three months ended March 31, 2024 would have resulted in an estimated $1.0 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, 2024 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, 2024 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 2023 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 24, 2024.
Source: SEC EDGAR, the filing index for accession 0001558370-24-005602. Last ingested by Listed: Oct 29, 2026, 05:24 ET. No prices; not investment advice.