Permian Resources Corp (PR)

CIK: 0001658566. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-02-26.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1658566. Latest filing source: 0001658566-26-000035.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001658566.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-07. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001658566.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001658566-26-000072.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-07. Report date: 2026-03-31.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, NGLs and natural gas, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, international conflict, inflation, tariffs, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and the 2025 Annual Report; all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Permian Resources Corporation is an independent oil and natural gas company focused on driving returns to our stockholders through the acquisition, optimization and development of high-return oil and natural gas properties. Our assets and operations are located in the Permian Basin, with a concentration in the core of the Delaware Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets, with an overall objective of improving our rates of return and generating sustainable free cash flow. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Permian Resources,” “we,” “us,” or “our” are to Permian Resources Corporation and its consolidated subsidiaries, including Permian Resources Operating, LLC (“OpCo”).

Market Conditions

Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

Oil prices declined through the end of 2025 and into early 2026, reflecting concerns regarding global economic growth, elevated interest rates, persistent inflation, increased global oil supply, and evolving tariffs and international trade policies. While global demand remained relatively strong and geopolitical risks persisted, higher‑than‑anticipated production increases from OPEC and the potential impact on global inventory levels contributed to additional downward pressure on prices during this period. More recently, oil prices have increased, with NYMEX WTI spot prices reaching a high of $102.88 per barrel on March 30, 2026, driven primarily by supply disruptions associated with heightened geopolitical tensions in the Middle East, including disruptions to key shipping routes in the Strait of Hormuz, which have adversely affected global supply conditions.

Throughout 2025 and 2026, natural gas prices in the Permian Basin have been adversely impacted by low demand as a result of pipeline capacity constraints out of the basin, pipeline maintenance, and higher production levels. These factors have led to lower or, during certain periods, negative regional gas prices being realized for natural gas sales at the Waha Hub in West Texas.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations, weather conditions, growth in alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024:

2024

2025

2026

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Crude oil (per Bbl)

$

76.96 

$

80.55 

$

75.16 

$

70.28 

$

71.42 

$

63.71 

$

64.95 

$

59.13 

$

71.93 

Natural gas (per MMBtu)

$

2.41 

$

2.04 

$

2.08 

$

2.42 

$

4.27 

$

3.16 

$

3.07 

$

3.69 

$

4.84 

Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures.

29

Table of Contents

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. The cost of oilfield goods and services are closely linked to commodity price trends, rising when prices increase and decreasing when prices fall. In addition, the U.S. saw higher levels of inflation during 2025 and 2026 due to concerns over international conflicts, tariffs and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.

2026 Highlights

Corporation Reorganization

On January 7, 2026, we completed a corporate reorganization pursuant to which we, among other things, reorganized under a new public holding company (the “Reorganization”). In connection with the Reorganization, the public holding company prior to the Reorganization became a wholly owned subsidiary of the new public holding company, which, following completion of the Reorganization, changed its name to “Permian Resources Corporation,” became the successor issuer of the prior public holding company and replaced the prior public holding company, with its shares of Class A Common Stock continuing to trade on the NYSE on an uninterrupted basis.

In connection with the Reorganization, certain holders of our Class C Common Stock exchanged all of their Common Units for Class A Common Stock on a one-for-one basis (and their corresponding shares of Class C Common Stock were cancelled for no consideration).

Separate from and subsequent to the Reorganization, the remaining Class C Common stockholders exchanged all of their outstanding Common Units for Class A Common Stock, which fully eliminated our noncontrolling interest as of March 31, 2026.

2026 Bolt-On Acquisitions

During the three months ended March 31, 2026, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $204.9 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.

Return of Capital Program

During the three months ended March 31, 2026, we declared and paid quarterly base dividends of $0.16 per share of Class A Common Stock. The cash dividends paid totaled $134.9 million for the three months ended March 31, 2026.

Financing

During the first quarter of 2026, we achieved investment grade corporate and issuer credit ratings from Standard & Poor’s Financial Services LLC (“S&P”). Subsequently, on April 1, 2026, we achieved investment grade corporate and issuer credit ratings from Moody’s Ratings (“Moody’s”). Previously, in July 2025, we achieved investment grade corporate and issuer credit ratings from Fitch Ratings Inc. (“Fitch”). As a result, we are now rated investment grade by all three rating agencies, which we believe reflects the strength of our balance sheet, our disciplined acquisition and capital financing, and our growing scale. We anticipate this achievement will result in reduced interest expense, improved access to capital markets, and enhanced liquidity, among other benefits.

On April 15, 2026, we redeemed all of our outstanding 8.00% senior notes due 2027 at a redemption price equal to 100% of the aggregate principal amount outstanding of $550.0 million plus accrued and unpaid interest up to, but excluding, the redemption date.

On April 30, 2026, OpCo entered into a credit agreement with a syndicate of banks that provides for an unsecured revolving credit facility, maturing in April 2031 (the “New Credit Agreement”). In connection with our entry into the New Credit Agreement, we terminated our existing secured revolving credit facility (the “Credit Agreement”). Refer to Liquidity and Capital Resources for additional information regarding the New Credit Agreement.

30

Table of Contents

Results of Operations

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025

The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:

Three Months Ended March 31,

Increase/(Decrease)

2026

2025

$

%

Net revenues (in thousands):

Oil sales

$

1,227,594 

$

1,109,771 

$

117,823 

11 

%

NGL sales

154,393 

185,022 

(30,629)

(17)

%

Natural gas sales

(18,504)

81,658 

(100,162)

(123)

%

Purchased gas sales, net

24,663 

— 

24,663 

100 

%

Oil and gas sales

$

1,388,146 

$

1,376,451 

$

11,695 

1 

%

Net production:

Oil (MBbls)

17,311 

15,747 

1,564 

10 

%

NGL (MBbls)

9,300 

7,741 

1,559 

20 

%

Natural gas (MMcf)

63,268 

60,605 

2,663 

4 

%

Total (MBoe)(1)

37,156 

33,589 

3,567 

11 

%

Average daily net production:

Oil (Bbls/d)

192,349 

174,967 

17,382 

10 

%

NGL (Bbls/d)

103,338 

86,010 

17,328 

20 

%

Natural gas (Mcf/d)

702,979 

673,388 

29,591 

4 

%

Total (Boe/d)(1)

412,850 

373,209 

39,641 

11 

%

Average sales prices:

Oil (per Bbl)

$

70.91 

$

70.48 

$

0.43 

1 

%

Effect of derivative settlements on average price (per Bbl)

(2.81)

0.97 

(3.78)

(390)

%

Oil including the effects of hedging (per Bbl)

$

68.10 

$

71.45 

$

(3.35)

(5)

%

NGL (per Bbl)

$

16.60 

$

23.90 

$

(7.30)

(31)

%

Natural gas (per Mcf)

$

(0.29)

$

1.35 

$

(1.64)

(121)

%

Effect of derivative settlements on average price (per Mcf)

1.23 

0.10 

1.13 

1,130 

%

Effect of purchased gas sales on average price (per Mcf)

0.39 

— 

0.39 

100 

%

Natural gas including the effects of hedging (per Mcf)

$

1.33 

$

1.45 

$

(0.12)

(8)

%

(1)    Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

31

Table of Contents

Oil and Gas Sales. Total net revenues for the three months ended March 31, 2026 were $11.7 million (or 1%) higher than total net revenues for the three months ended March 31, 2025. Revenues are primarily a function of oil, NGL and natural gas volumes sold and average commodity prices realized.

Net production volumes for oil, NGLs and natural gas increased 10%, 20% and 4%, respectively, between periods. The increase in oil production resulted from additional production added from wells placed online or acquired since the first quarter of 2025. These oil volume increases were partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically result in a high correlation between fluctuations in oil quantities sold and

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-26. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, NGLs and natural gas, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are an independent oil and natural gas company focused on driving returns to our stockholders through the acquisition, optimization and development of high-return oil and natural gas properties. Our assets and operations are located in the Permian Basin, with a concentration in the core of the Delaware Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets, with an overall objective of improving our rates of return and generating sustainable free cash flow.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

Concerns regarding global economic growth, elevated interest rates, inflation, increases in global oil supply, tariffs and international trade policies have resulted in lower oil prices over the past year. Despite recent geopolitical tensions and strong global demand, higher than anticipated supply increases from OPEC and their potential impact to global inventories resulted in further downward pressure on prices through the end of 2025.

Throughout 2024 and 2025, natural gas prices in the Permian Basin were negatively impacted by low demand as a result of pipeline capacity constraints out of the basin, pipeline maintenance, and higher production levels. These factors have led to lower or, during certain periods, negative regional gas prices being realized for natural gas sales at the Waha hub in West Texas resulting in lower gas realizations on our production sold at these regional price points.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations weather conditions, growth in alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2023:

2023

2024

2025

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Crude Oil (per Bbl)

$

76.13 

$

73.78 

$

82.26 

$

78.32 

$

76.96 

$

80.55 

$

75.16 

$

70.28 

$

71.42 

$

63.71 

$

64.95 

$

59.13 

Natural Gas (per MMBtu)

$

2.67 

$

2.12 

$

2.58 

$

2.74 

$

2.41 

$

2.04 

$

2.08 

$

2.42 

$

4.27 

$

3.16 

$

3.07 

$

3.69 

Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement and senior notes. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to such lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the Credit Agreement.

43

Table of Contents

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. The cost of oilfield goods and services are closely linked to commodity price trends, rising when prices increase and decreasing when prices fall. In addition, the U.S. saw higher levels of inflation during 2024 and 2025 due to concerns over international conflicts, tariffs and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.

2025 Highlights and Future Considerations

2025 Bolt-On Acquisitions

On June 16, 2025, we completed an acquisition of approximately 13,000 net leasehold acres with Apache Corporation for an unadjusted purchase price of $608 million. The acreage acquired is predominately located directly offsetting our existing asset position in the core of our New Mexico operating area.

Additionally, during the year ended December 31, 2025, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $471.1 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.

Return of Capital Program

During the year ended December 31, 2025, we declared and paid quarterly base dividends totaling $0.60 per share of Class A Common Stock and distributions totaling $0.60 per share of Class C Common Stock (each of which has an underlying common unit of OpCo (“Common Units”)). The cash dividends and distributions paid totaled $502.9 million for the year ended December 31, 2025.

During the year ended December 31, 2025, we paid a total of $73.7 million to repurchase 4.4 million shares of our Class A Common Stock and 2.0 million Class C Common Stock at a weighted average price of $11.57 per share as part of our Repurchase Program. The shares that were repurchased were subsequently canceled.

Financing

During September 2025, we completed the redemption of all of our outstanding 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”) for a combination of shares of Class A Common Stock and cash (the “Redemption”). The Redemption resulted in the issuance of 30.6 million shares of our Class A Common Stock at a 179.9208 conversion rate per $1,000 principal amount of the Convertible Senior Notes as well as a cash payment of $0.1 million.

During June 2025, we repurchased $2.7 million of our senior notes due 2026 (the “2026 Senior Notes”) at a price equal to 99.7% of the principal amount paid plus accrued and unpaid interest up to, but excluding, the repurchase date. Subsequently, during September 2025, we redeemed all remaining 2026 Senior Notes at a price equal to 100% of the aggregate principal amount outstanding of $286.7 million plus accrued and unpaid interest up to, but excluding, the redemption date.

During January 2025, we redeemed $175 million of our senior notes due 2031 (the “2031 Senior Notes”) at a redemption price equal to 109.875% of the aggregate principal amount redeemed plus accrued and unpaid interest up to, but excluding, the redemption date. Following the redemption, the remaining aggregate principal amount of the 2031 Senior Notes outstanding was $325 million.

Corporation Reorganization

On January 7, 2026, we completed a corporate reorganization pursuant to which we, among other things, reorganized under a new public holding company (the “Reorganization”). In connection with the Reorganization, the public holding company prior to the Reorganization became a wholly owned subsidiary of the new public holding company, which, following completion of the Reorganization, changed its name to “Permian Resources Corporation,” became the successor issuer of the prior public holding company and replaced the prior public holding company, with its shares of Class A Common Stock continuing to trade on the NYSE on an uninterrupted basis.

In connection with the Reorganization, certain holders of our Class C Common Stock exchanged all of their Common Units for Class A Common Stock on a one-for-one basis (and their corresponding shares of Class C Common Stock were cancelled for no consideration). This resulted in approximately 35.5 million shares of Class C Common Stock remaining outstanding, reducing the noncontrolling interest ownership of OpCo to approximately 4% immediately following the Reorganization. Refer to Note 16—Subsequent Events under Part II, Item 8 of this Annual Report for additional information on the Reorganization that occurred after the reporting period.

44

Table of Contents

Results of Operations

For the Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024

The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:

Year Ended December 31,

Increase/(Decrease)

2025

2024

$

%

Net revenues (in thousands):

Oil sales

$

4,251,193 

$

4,362,965 

$

(111,772)

(3)

%

NGL sales

658,515 

637,529 

20,986 

3 

%

Natural gas sales

131,663 

240 

131,423 

54,760 

%

Purchased gas sales, net

23,840 

— 

23,840 

100 

%

Oil and gas sales

$

5,065,211 

$

5,000,734 

$

64,477 

1 

%

Net production:

Oil (MBbls)

66,364 

58,276 

8,088 

14 

%

NGL (MBbls)

35,773 

30,636 

5,137 

17 

%

Natural gas (MMcf)

247,045 

220,900 

26,145 

12 

%

Total (MBoe)(3)

143,311 

125,730 

17,581 

14 

%

Average daily net production:

Oil (Bbls/d)

181,819 

159,225 

22,594 

14 

%

NGL (Bbls/d)

98,008 

83,706 

14,302 

17 

%

Natural gas (Mcf/d)

676,835 

603,551 

73,284 

12 

%

Total (Boe/d)(3)

392,633 

343,523 

49,110 

14 

%

Average sales prices:

Oil (per Bbl)

$

64.06 

$

74.87 

$

(10.81)

(14)

%

Effect of derivative settlements on average price (per Bbl)

2.40 

0.03 

2.37 

7,900 

%

Oil including the effects of hedging (per Bbl)

$

66.46 

$

74.90 

$

(8.44)

(11)

%

NGL (per Bbl)

$

18.41 

$

20.81 

$

(2.40)

(12)

%

 Natural gas (per Mcf)

$

0.53 

$

— 

$

0.53 

100 

%

Effect of derivative settlements on average price (per Mcf)

0.48 

0.34 

0.14 

41 

%

Effect of purchased gas sales on average price (per Mcf)

0.10 

— 

0.10 

100 

%

Natural gas including the effects of hedging (per Mcf)

$

1.11 

$

0.34 

$

0.77 

226 

%

(1)    Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

Oil, NGL and Natural Gas Sales Revenues. Total net revenues for the year ended December 31, 2025 increased by $64.5 million, or 1%, compared to the year ended December 31, 2024. Revenues are a function of oil, NGL and natural gas volumes sold and average commodity prices realized.

Net production volumes for oil, NGLs and natural gas increased 14%, 17% and 12%, respectively, between periods. The increase in oil production resulted from additional production added from wells placed online or acquired since the fourth quarter of 2024. These oil volume increases were partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically result in a high correlation between fluctuations in oil quantities sold and NGL and natural gas quantities sold, driving the respective 17% and 12% increases in NGL and gas volumes, respectively, between periods.

Total net revenues increases were also driven by higher average realized sales prices of natural gas for the year ended December 31, 2025 compared to the same 2024 period. This increase was the result of higher regional and national average index gas prices between periods.

45

Table of Contents

These increases were partially offset by lower average realized sale prices for oil and NGLs, which decreased 14% and 12%, respectively, for the year ended December 31, 2025 compared to the same 2024 period. The 14% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods. The 12% decrease in the average realized NGL price between periods was primarily attributable to lower Mont Belvieu spot prices for plant products for the year ended December 31, 2025 compared to the same 2024 period.

Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:

Year Ended December 31,

Increase/(Decrease)

2025

2024

Change

%

Operating costs (in thousands):

Lease operating expenses

$

753,119 

$

685,172 

$

67,947 

10 

%

Severance and ad valorem taxes

390,255 

377,731 

12,524 

3 

%

Gathering, processing, and transportation expense

200,103 

183,602 

16,501 

9 

%

Operating cost metrics:

Lease operating expenses (per Boe)

$

5.26 

$

5.45 

$

(0.19)

(3)

%

Severance and ad valorem taxes (% of revenue)

7.7 

%

7.6 

%

0.1 

%

1 

%

Gathering, processing, and transportation expense (per Boe)

1.40 

1.46 

(0.06)

(4)

%

Lease Operating Expenses. Lease operating expenses (“LOE”) per Boe for the year ended December 31, 2025 was $5.26, which represents a 3% decrease compared to the same 2024 period. This decrease in our LOE per Boe rate was primarily driven by lower water disposal rates and wellhead chemicals that resulted from operational efficiencies. While LOE per Boe decreased period over period, total LOE for the year ended December 31, 2025 increased by $67.9 million compared to the year ended December 31, 2024 and was the direct result of our higher well count between periods primarily due to additional wells placed on production or acquired since December 31, 2024.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 2025 increased $12.5 million compared to the year ended December 31, 2024. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. The increase in severance and ad valorem tax expense for the year ended 2025 compared to the same 2024 period is due to an increase in severance taxes and is primarily related to higher NGL and natural gas revenues between periods.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) on a per Boe basis decreased from $1.46 for the year ended December 31, 2024 to $1.40 per Boe for the year ended December 31, 2025. This decrease in rate was mainly attributable to lower GP&T rates based on the location of new wells placed on production since the fourth quarter of 2024. While our GP&T per Boe was lower period versus period, total GP&T for the year ended December 31, 2025 increased $16.5 million compared to the year ended December 31, 2024. This increase in expense was mainly attributable to higher NGL and natural gas volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and gathering costs being incurred.

Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: 

Year Ended December 31,

(in thousands, except per Boe data)

2025

2024

Depreciation, depletion and amortization

$

2,032,507 

$

1,776,673 

Depreciation, depletion and amortization per Boe

$

14.18 

$

14.13 

For the year ended December 31, 2025, DD&A expense amounted to $2.0 billion, an increase of $255.8 million from 2024. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods, which increased DD&A expense by $248.4 million period over period, while marginally higher DD&A rates between periods increased DD&A expense by $7.4 million.

DD&A per Boe was $14.18 for the year ended December 31, 2025 compared to $14.13 for the same period in 2024. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.

46

Table of Contents

General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:

Year Ended December 31,

(in thousands, except per Boe data)

2025

2024

Cash general and administrative expenses

$

119,513 

$

116,387 

Stock-based compensation expense

66,958 

58,243 

General and administrative expenses

$

186,471 

$

174,630 

Cash general and administrative expenses per Boe

$

0.83 

$

0.93 

G&A expenses for the year ended December 31, 2025 were $186.5 million compared to $174.6 million for the year ended December 31, 2024. Stock-based compensation increased $8.7 million primarily related to additional grants of performance stock units and restricted stock since the fourth quarter of 2024. This was partially offset by less expenses associated with accelerated vestings of equity awards that occurred during the year ended of December 31, 2024 that did not reoccur during the same 2025 period. Cash G&A was $3.1 million higher between periods mainly related to increased employee expenses and consulting and professional services related to our increased headcount and overall corporate growth.

While cash G&A increased between periods, on a per Boe basis our cash G&A rate decreased 11% from $0.93 per Boe during the year ended December 31, 2024 to $0.83 per Boe during the year ended December 31, 2025. This per Boe rate decrease was the result of focus on controlling costs and growing production.

Other Income and Expense. 

Interest Expense. The following table summarizes interest expense for the periods indicated:

Year Ended December 31,

(in thousands)

2025

2024

Credit Facility

$

9,536 

$

16,062 

5.375% Senior Notes due 2026

11,153 

15,556 

7.75% Senior Notes due 2026

— 

14,016 

6.875% Senior Notes due 2027

— 

6,397 

8.00% Senior Notes due 2027

44,000 

44,000 

3.25% Convertible Senior Notes due 2028

1,382 

5,524 

5.875% Senior Notes due 2029

41,124 

41,124 

9.875% Senior Notes due 2031

33,198 

49,376 

7.00% Senior Notes due 2032

70,000 

70,000 

6.25% Senior Notes due 2033

62,500 

25,347 

Amortization of debt issuance costs, debt discount and debt premium

8,023 

6,563 

Other interest expense

2,146 

2,206 

Total

$

283,062 

$

296,171 

Interest expense was $13.1 million lower for the year ended December 31, 2025 compared to the year ended December 31, 2024 mainly due to (i) $45.1 million less interest incurred between periods due to various redemptions and repurchases of our senior notes during the 2024 and 2025 periods (refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding these transactions); and (ii) less interest expense incurred on our credit facility due to lower weighted average borrowings outstanding during the 2025 period. These decreases were partially offset by $37.2 million in additional interest incurred on our 6.25% Senior Notes due 2033 that were issued in July 2024.

47

Table of Contents

Loss on extinguishment of debt. The loss on extinguishment of debt incurred during the year ended December 31, 2025 of $270.1 million was primarily related to the Redemption of our Convertible Senior Notes. This loss was determined based on the difference in the value of our Class A Common Stock issued and cash paid for the Redemption and the carrying amount of the Convertible Senior Notes less professional fees incurred in connection with the Redemption. The 2025 loss was greater than prior debt redemption losses as the Convertible Notes were redeemed mainly by issuing Class A Common Stock, which has risen significantly in value since the Convertible Senior Notes were issued in 2021. Refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding the redemption.

During the year ended December 31, 2024, we recognized $8.6 million of loss on extinguishment of debt related to the redemptions of our 7.75% senior notes due 2026 and 6.875% senior notes due 2027.

Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.

The following table presents gains and losses on our derivative instruments for the periods indicated:

Year Ended December 31,

(in thousands)

2025

2024

Realized cash settlement gains (losses)

$

277,245 

$

77,203 

Non-cash mark-to-market derivative gain (loss)

168,479 

17,783 

Total

$

445,724 

$

94,986 

Income Tax Expense: The following table summarizes our pre-tax income and income tax expense for the periods indicated:

Year Ended December 31,

(in thousands)

2025

2024

Income before income taxes

$

1,383,115 

$

1,550,851 

Income tax expense

(284,179)

(300,342)

For the year ended December 31, 2025 we generated pre-tax net income of $1.4 billion and recorded income tax expense of $284.2 million. Our provision for income tax expense for the year ended December 31, 2025 was less than the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our noncontrolling interest partners that is not taxable to the Company; and (ii) general business tax credits generated during the year. These decreases were partially offset by an increase in our unrecognized tax benefit recognized during the year ended December 31, 2025.

For the year ended December 31, 2024, we generated pre-tax net income of $1.6 billion and recorded income tax expense of $300.3 million. The primary factor decreasing our 2024 tax expense below the statutory U.S. federal income tax rate was the portion of pre-tax income that was attributable to our noncontrolling interest partners and not taxable to the Company.

For the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023

Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023.

48

Table of Contents

Liquidity and Capital Resources

Overview

Our primary sources of liquidity have been cash flows from operations, borrowings under our revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.

We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for drilling and development activity during the year ended December 31, 2025 were $1.97 billion. We expect our total drilling, completion and facilities capital expenditures budget for 2026 to be between $1.75 billion to $1.95 billion. We funded our capital expenditures for 2025 entirely from cash flows from operations, and we expect to fund our 2026 capital expenditures budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place.

We are the operator of a high percentage of our acreage and can control the amount and timing of our capital expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas; (ii) oil and gas storage or transportation constraints; (iii) the success of our drilling activities; (iv) the availability of necessary equipment, infrastructure and capital; (v) the receipt and timing of required regulatory permits and approvals; (vi) seasonal conditions; (vii) property or land acquisition costs; and (viii) the level of participation by other working interest owners.

We plan to return capital to shareholders primarily through our base dividend, in addition to opportunistic share repurchases. During the year ended December 31, 2025, we declared and paid quarterly base dividends totaling $0.60 per share of Class A Common Stock and distributions totaling $0.60 per share of Class C Common Stock (each of which has an underlying Common Unit of OpCo). The cash dividends and distributions paid to common unitholders totaled $502.9 million for the year ended December 31, 2025. Additionally, we repurchased 4.4 million shares of Class A Common Stock for $46.8 million and 2.0 million shares of Class C Common Stock for $26.9 million under our Repurchase Program during the year ended December 31, 2025.

Our Repurchase Program can be used to reduce our shares of common stock outstanding. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt agreements and other factors.

In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise. During the year ended December 31, 2025, we (i) redeemed an aggregate principal amount of $175 million of our 2031 Senior Notes at a price equal to 109.875% of the aggregate principal amount; (ii) repurchased and redeemed an aggregate principal amount of $289.4 million of our 2026 Senior Notes; and (iii) redeemed the aggregate principal amount of $170 million of our Convertible Senior Notes for 30.6 million shares of our Class A Common Stock at a conversion rate of 179.9208 shares per $1,000 principal amount of Convertible Senior Notes as well as a cash payment of $0.1 million.

Although we cannot provide any assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we will have sufficient capital available to fund our capital expenditure requirements through the 12-month period following the filing of this Annual Report and the long-term.

Analysis of Cash Flow Changes

The following table summarizes our cash flows for the periods indicated:

Year Ended December 31,

(in thousands)

2025

2024

2023

Net cash provided by operating activities

$

3,607,541 

$

3,411,968 

$

2,213,499 

Net cash used in investing activities

(2,873,454)

(3,104,195)

(1,578,379)

Net cash (used in) provided by financing activities

(1,059,740)

97,706 

(631,188)

49

Table of Contents

Cash Flows from 2025 Compared to 2024. For the year ended December 31, 2025, we generated $3.6 billion of cash from operating activities, an increase of $195.6 million from 2024. Cash provided by operating activities increased primarily due to (i) higher production volumes, realized derivative gains and realized prices for gas, (ii) lower merger and integration and interest expense, and (iii) the timing of payments to our suppliers for the year ended December 31, 2025 as compared to the same 2024 period. These increasing factors were partially offset by lower realized prices for oil and NGLs, higher costs including lease operating expenses, GP&T expense, severance and ad valorem taxes and cash G&A as well as the timing of our receivable collections for the year ended December 31, 2025 as compared to the same 2024 period. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating expenses between periods.

For the year ended December 31, 2025, cash flows from operating activities, cash on hand and proceeds of $176.7 million primarily from the sale of oil and natural gas gathering systems that were acquired during a prior year acquisition were used to (i) fund $1.97 billion of drilling and development cash expenditures; (ii) fund acquisitions of oil and gas properties of approximately $1.1 billion; (iii) pay $502.9 million in dividends and cash distributions to shareholders and holders of our Common Units; (iv) redeem $464.5 million of our senior notes; and (v) repurchase $73.7 million of our Class A and C Common Stock.

Cash Flows from 2024 Compared to 2023. For the year ended December 31, 2024, we generated $3.4 billion of cash from operating activities, an increase of $1.2 billion from 2023. Cash provided by operating activities increased primarily due to higher production volumes and lower merger and integration expense for the year ended December 31, 2024 as compared to the same 2023 period. These increasing factors were partially offset by lower realized prices for oil and natural gas, higher costs including lease operating expenses, severance and ad valorem taxes, interest expense, GP&T expense, and cash G&A as well as the timing of our receivable collections for the year ended December 31, 2024 as compared to the same 2023 period.

For the year ended December 31, 2024, cash flows from operating activities, proceeds from the issuance of our 6.25% Senior Notes due 2033 and proceeds from an underwritten public offering of 26.5 million Class A Common Stock were used to: (i) fund $2.1 billion of drilling and development cash capital expenditures; (ii) fund acquisitions of oil and gas properties of approximately $1.0 billion; (iii) redeem $656.4 million of our senior notes; (iv) pay $560.9 million in dividends and cash distributions to our shareholders and holders of our Common Units; and (v) repurchase $61.0 million of our Class C Common Stock.

Credit Agreement

OpCo, our consolidated subsidiary, has a secured revolving Credit Agreement with a syndicate of banks maturing in February 2028 that, as of December 31, 2025, had a borrowing base of $4.0 billion and elected commitments of $2.5 billion. As of December 31, 2025, we had no borrowings outstanding and $2.5 billion in available borrowing capacity. The elected commitments and borrowing base were reaffirmed during the spring and fall 2025 borrowing base redeterminations.

The Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.

The Credit Agreement also requires OpCo to maintain compliance with the following financial ratios:

(i) a current ratio, which is the ratio of OpCo’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

(ii) a leverage ratio, which is the ratio of total funded debt to consolidated EBITDAX (with such terms defined within the Credit Agreement) for the most recent quarter annualized, of not greater than 3.5 to 1.0.

The Credit Agreement includes fall away covenants, lower interest rates and reduced collateral requirements that OpCo may elect if OpCo is assigned an Investment Grade Rating (as defined within the Credit Agreement). OpCo was in compliance with the covenants and financial ratios under the Credit Agreement described above through the filing of this Annual Report. For further information on the Credit Agreement, refer to Note 5—Long-Term Debt under Item 8 of this Annual Report.

Senior Notes

OpCo has $3.5 billion in debt outstanding as of December 31, 2025, consisting of senior unsecured notes with maturity dates ranging from 2027 to 2033. For further information on our Senior Unsecured Notes, refer to Note 5—Long-Term Debt under Part II, Item 8 of this Annual Report.

50

Table of Contents

Obligations and Commitments

We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, among others, in the ordinary course of business. The following table summarizes our obligations and commitments as of December 31, 2025, to make future payments under long-term contracts for the time periods specified below.

(in thousands)

2026

2027

2028

2029

2030

Thereafter

Total

Operating leases(1)

$

82,790 

$

40,462 

$

12,194 

$

2,483 

$

2,202 

$

1,885 

$

142,016 

Finance leases(2)

791 

754 

718 

685 

653 

12,712 

16,313 

Purchase obligations(3)

50,507 

15,251 

13,233 

724 

— 

— 

79,715 

Firm transportation(4)

28,885 

78,282 

107,169 

118,033 

118,032 

769,179 

1,219,580 

Development obligation(5)

20,000 

— 

— 

— 

— 

— 

20,000 

Asset retirement obligations(6)

22,503 

2,841 

2,827 

1,447 

467 

159,265 

189,350 

Long term debt obligations(7)

— 

550,000 

— 

700,000 

— 

2,325,000 

3,575,000 

Cash interest expense on long-term debt obligations(8)

259,094 

227,927 

206,969 

185,270 

164,594 

220,683 

1,264,537 

Total

$

464,570 

$

915,517 

$

343,110 

$

1,008,642 

$

285,948 

$

3,488,724 

$

6,506,511 

(1)    Operating leases consist of our office rental agreements, drilling rig contracts and other wellhead equipment. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our operating lease commitments.

(2)     Finance leases consist of our ground lease related to the office building we purchased in Midland, Texas. The lease term is ninety-nine years and as a result, the commitments above have been shown at their current present value. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our finance lease commitments.

(3)    Consists of energy purchase agreements to buy a minimum amount of electricity at a fixed price or pay for underutilization as well as a take-or-pay agreement to purchase a minimum volume of frac sand at a fixed price. The obligations reported above represent our remaining minimum financial commitments pursuant to the terms of these contracts as of December 31, 2025, however actual expenditures may exceed the minimum commitments presented above. Please refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for details on these agreements.

(4)    Consists of firm transportation commitment agreements that guarantee volumetric capacity on pipelines for gas transportation. Please refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for details on these agreements.

(5)    Consists of obligations that are tied to our future drilling, completion and water connection activity in Reeves County, Texas that will require repayment if certain performance obligations through September 2026 are not met.

(6)    Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells and the related land restoration in accordance with applicable laws and regulations.

(7)    Long-term debt consists of the principal amounts of our senior notes due as of December 31, 2025.

(8)    Cash interest expense on our senior notes is estimated assuming no principal repayment until the maturity of the instruments. Cash interest expense on the Credit Agreement includes unused commitment fees and assumes no additional principal borrowings, repayments or changes to commitments under the agreement through the instrument due date.

Recently Issued Accounting Standards

Refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this annual report for a discussion of recently issued accounting standards and their anticipated effect on our business.

51

Table of Contents

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as, the disclosure of contingent assets, contingent liabilities and commitments as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, commodity prices, production performance, drilling results, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies can be found in Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Item 8 of this Annual Report.

We have outlined certain of our accounting policies below which require the application of significant judgment by our management.

Oil and Natural Gas Reserve Quantities

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil, NGL and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs to our calculation of depletion, evaluation of proved properties for impairment, assessment of the expected realizability of our deferred income tax assets, and the standardized measure of discounted future net cash flows computations.

The process of estimating quantities of proved reserves is inherently imprecise and relies on the following: i) interpretations and judgment of available geological, geophysical, engineering and production data; ii) certain economic assumptions, some of which are mandated by the SEC, such as commodity prices; and iii) assumptions and estimates of underlying inputs such as operating expenses, capital expenditures, plug and abandonment costs and taxes. All of these assumptions may differ substantially from actual results, which could result in a significant change in our estimated quantities of proved reserves and their future net cash flows. We continually make revisions to reserve estimates throughout the year as additional information becomes available, and we make changes to depletion rates in the same reporting period that changes to reserve estimates are made.

Business Combinations

From time to time, we may complete acquisitions that are accounted for as business combinations that require us to recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, forecasted development costs, pricing and cash flows, discount rates, expectations regarding customer contracts and relationships, reserve risk adjustment factors and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition. See Note 2—Business Combinations in Item 8 of this Annual Report on Form 10-K.

Impairment of Oil and Natural Gas Properties

We assess our proved properties for impairment when events or changes in circumstances indicate that the carrying value of such proved property assets may not be recoverable. For purposes of an impairment evaluation, our proved oil and natural gas properties must be grouped at the lowest level for which independent cash flows can be identified. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to its estimated fair value. Fair value for the purpose of measuring impairment write-downs are calculated using the present value of expected future cash flows that are estimated to be generated from the asset group. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment write-down is being measured. However, such future cash flow estimates are based on numerous assumptions that can materially affect our estimates, and such assumptions are subject to change with variations in commodity prices, production performance, drilling results, operating and development costs, underlying oil and gas reserve quantities, and other internal or external factors.

Unproved properties consist of the costs we incur to acquire undeveloped leasehold acreage and unproved reserves. Unproved properties are periodically assessed for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Changes in our assessment or these factors could result in additional impairment charges of our undeveloped leases.

52

Table of Contents