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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2025

☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number 001-37697

PERMIAN RESOURCES CORPORATION

(Exact Name of Registrant as Specified in its Charter)


Delaware						47-5381253
(State of Incorporation)						(I.R.S. Employer Identification No.)

300 N. Marienfeld St., Suite 1000

Midland, Texas 79701

(Address of principal executive offices)

(432) 695-4222

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which registered

Class A Common Stock, par value $0.0001 per share

New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

☒

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of October 31, 2025, there were 829,297,592 shares of total common stock outstanding, including 744,919,467 shares of Class A Common Stock, par value $0.0001 per share, and 84,378,125 shares of Class C Common Stock, par value $0.0001 per share.

TABLE OF CONTENTS


		Page
Glossary of Units of Measurements and Industry Terms		3

Cautionary Statement Concerning Forward-Looking Statements		5

Part I—FINANCIAL INFORMATION		8

Item 1.	Financial Statements (Unaudited)	8

	Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024	8

	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2025 and 2024	9

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2025 and 2024	10

	Consolidated Statements of Shareholders’ Equity for the Three and Nine Months Ended September 30, 2025 and 2024	12

	Notes to Consolidated Financial Statements	16

	Note 1—Basis of Presentation and Summary of Significant Accounting Policies	16

	Note 2—Acquisitions	18

	Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses	19

	Note 4—Long-Term Debt	19

	Note 5—Asset Retirement Obligations	22

	Note 6—Stock-Based Compensation	22

	Note 7—Derivative Instruments	24

	Note 8—Fair Value Measurements	27

	Note 9—Shareholders’ Equity and Noncontrolling Interest	29

	Note 10—Earnings Per Share	30

	Note 11—Commitments and Contingencies	31

	Note 12—Revenues	32

	Note 13—Subsequent Events	33

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	51

Part II—OTHER INFORMATION		51

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 5.	Other Information	52

Item 6.	Exhibits	53

Signatures		54

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GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS

Unless the context otherwise indicates, references in this Quarterly Report on Form 10-Q (the “Quarterly Report”) to “Permian Resources,” “we,” “us,” “our” or the “Company” are references to Permian Resources Corporation and its consolidated subsidiaries, including Permian Resources Operating, LLC.

The following are abbreviations and definitions of certain terms used in this Quarterly Report, which are commonly used in the oil and natural gas industry:

Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, NGLs or condensate.

Bbl/d. One Bbl per day.

Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d. One Boe per day.

Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.

Completion. The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to initiate production.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality, gathering, processing and transportation fees and location of oil or natural gas.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Henry Hub price. A natural gas benchmark price quoted at settlement date average.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

MBbl. One thousand barrels of crude oil, NGLs or condensate.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

Mont Belvieu price. An NGLs benchmark price at the Mont Belvieu hub.

NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline that can be collectively removed from produced natural gas, separated in these substances and sold.

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

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Proved reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

Realized price. The price received for selling oil, NGL and natural gas production that reflects various factors including, but not limited to, transportation costs, regional market conditions and contractual differentials.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil or gas property entitling the owner to its share of the production free of costs of exploration, development and production operations.

SOFR. Secured Overnight Funding Rate.

Spot market price. The cash market price without reduction for expected quality, location, transportation and demand adjustments.

Unproved reserves. Reserves attributable to unproved properties with no proved reserves.

Waha Hub. A natural gas benchmark price in West Texas.

Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also called well or borehole.

Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate is a grade of crude oil used as a benchmark in oil pricing.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Annual Report”) and the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (“SEC”). Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties and we can give no assurance that such expectations will prove to have been correct.

Forward-looking statements may include statements about:

•volatility of oil, NGL and natural gas prices or a prolonged period of low oil, NGL or natural gas prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil, NGLs and natural gas;

•political and economic conditions and events in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;

•the effects of a prolonged government shutdown;

•our business strategy and future drilling plans;

•our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;

•our drilling prospects, inventories, projects and programs;

•our financial strategy, return of capital program, leverage, liquidity and capital required for our development program;

•our realized oil, NGL and natural gas prices;

•the timing and amount of our future production of oil, NGLs and natural gas;

•our ability to identify, complete and effectively integrate acquisitions of properties, or businesses;

•our hedging strategy and results;

•our competition;

•our ability to obtain permits and governmental approvals;

•our compliance with government regulations, including those related to environmental, health and safety regulations and liabilities thereunder;

•our pending legal matters;

•the marketing and transportation of our oil, NGLs and natural gas;

•our leasehold or business acquisitions;

•cost of developing or operating our properties;

•our anticipated rate of return;

•general economic conditions;

•weather conditions in the areas where we operate;

•credit markets;

•our ability to make dividends, distributions and share repurchases;

•uncertainty regarding our future operating results; and

•our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, NGLs and natural gas. Factors which could cause our actual results to differ materially from the results contemplated by forward-looking statements include, but are not limited to:

•commodity price volatility (including regional basis differentials);

•uncertainty inherent in estimating oil, NGL and natural gas reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

•geographic concentration of our operations;

•changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements;

•lack of availability of drilling and production equipment and services;

•lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

•risks related to acquisitions we may make from time to time, including the risk that we may fail to integrate such acquisitions on the terms and timing contemplated, or at all, and/or to realize our strategy and plans to achieve the expected benefits of such acquisitions;

•competition in the oil and natural gas industry for assets, materials, qualified personnel and capital;

•drilling and other operating risks;

•environmental and climate related risks, including seasonal weather conditions;

•changes to tax laws or interpretations thereof and the impact of such changes on us, including the One Big Beautiful Bill Act (“OBBBA”);

•regulatory changes, including those that may impact environmental, energy, and natural resources regulation;

•the possibility that the industry in which we operate may be subject to new or volatile local, state, and federal laws, regulations or policies that may affect our business (including additional taxes and changes in regulations and policies related to environmental, health, and safety, climate change, trade policy and tariffs) as a result of existing or developing political, environmental and social movements;

•restrictions on the use of water, including limits on the use of produced water and potential restrictions on the availability of water disposal facilities;

•availability of cash flow and access to capital;

•inflation;

•changes in our credit ratings or adverse changes in interest rates and associated changes in monetary policy;

•changes in the financial strength of counterparties to our credit agreement and hedging contracts;

•the timing of development expenditures;

•political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, including the conflict in Israel, Iran and their surrounding areas, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage and the effects therefrom;

•changes in local, regional, national, and international economic conditions;

•security threats, including evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, third-party service provider failures, malicious software, data privacy breaches by employees, insiders or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•the other risks described in “Item 1A. Risk Factors” in our 2024 Annual Report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

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Should one or more of the risks or uncertainties described in this Quarterly Report, our 2024 Annual Report or our other filings with the SEC occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PERMIAN RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share amounts)


	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	111,805	$	479,343
Accounts receivable, net	571,778		530,452
Derivative instruments	204,988		85,509
Prepaid and other current assets	28,292		26,290
Total current assets	916,863		1,121,594
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties	1,964,138		1,990,441
Proved properties	20,734,450		18,595,780
Accumulated depreciation, depletion and amortization	(6,652,245)		(5,163,124)
Total oil and natural gas properties, net	16,046,343		15,423,097
Other property and equipment, net	56,566		50,381
Total property and equipment, net	16,102,909		15,473,478
Noncurrent assets
Operating lease right-of-use assets	142,281		119,703
Other noncurrent assets	163,420		183,125
TOTAL ASSETS	$	17,325,473	$	16,897,900
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	1,211,441	$	1,198,418
Operating lease liabilities	78,168		57,216

Other current liabilities	81,372		71,703
Total current liabilities	1,370,981		1,327,337
Noncurrent liabilities
Long-term debt, net	3,544,836		4,184,233
Asset retirement obligations	163,698		148,443
Deferred income taxes	851,883		602,379
Operating lease liabilities	66,013		64,288
Other noncurrent liabilities	54,538		52,701
Total liabilities	6,051,949		6,379,381
Commitments and contingencies (Note 11)
Shareholders’ equity
Common stock, $0.0001 par value, 1,500,000,000 shares authorized:
Class A: 750,292,512 shares issued and 744,064,408 shares outstanding at September 30, 2025 and 707,388,380 shares issued and 703,774,082 shares outstanding at December 31, 2024	75		71
Class C: 85,173,966 shares issued and outstanding at September 30, 2025 and 99,599,640 shares issued and outstanding at December 31, 2024	9		10
Additional paid-in capital	8,676,603		8,056,552
Retained earnings (accumulated deficit)	1,349,369		1,081,895
Total shareholders' equity	10,026,056		9,138,528
Noncontrolling interest	1,247,468		1,379,991
Total equity	11,273,524		10,518,519
TOTAL LIABILITIES AND EQUITY	$	17,325,473	$	16,897,900

The accompanying notes are an integral part of these unaudited consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Operating revenues
Oil and gas sales	$	1,321,796	$	1,215,571	$	3,895,843	$	3,704,653
Operating expenses
Lease operating expenses	191,338		173,255		558,937		501,597
Severance and ad valorem taxes	101,481		91,548		304,404		280,784
Gathering, processing and transportation expenses	53,971		50,220		156,375		133,020
Depreciation, depletion and amortization	526,915		453,603		1,507,528		1,290,210
General and administrative expenses	49,963		43,783		142,858		129,885
Merger and integration expense	—		—		—		18,064
Impairment and abandonment expense	2,251		1,380		7,606		7,784
Exploration and other expenses	4,933		6,962		25,243		24,428
Total operating expenses	930,852		820,751		2,702,951		2,385,772
Net gain on sale of long-lived assets	—		329		—		441
Income from operations	390,944		395,149		1,192,892		1,319,322

Other income (expense)
Interest expense	(69,386)		(74,824)		(215,995)		(219,388)
Loss on extinguishment of debt	(264,294)		(5,110)		(270,120)		(8,585)
Net gain (loss) on derivative instruments	105,714		238,533		236,464		131,702
Other income (expense)	5,877		9,247		24,018		9,676
Total other income (expense)	(222,089)		167,846		(225,633)		(86,595)

Income before income taxes	168,855		562,995		967,259		1,232,727
Income tax expense	(87,394)		(106,468)		(250,214)		(237,697)
Net income	81,461		456,527		717,045		995,030
Less: Net income attributable to noncontrolling interest	(22,227)		(70,151)		(121,376)		(226,979)
Net income attributable to Class A Common Stock	$	59,234	$	386,376	$	595,669	$	768,051

Income per share of Class A Common Stock:
Basic	$	0.08	$	0.56	$	0.84	$	1.24
Diluted	$	0.08	$	0.53	$	0.83	$	1.16

The accompanying notes are an integral part of these unaudited consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)


	Nine Months Ended September 30,
	2025		2024
Cash flows from operating activities:
Net income	$	717,045	$	995,030
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,507,528		1,290,210
Stock-based compensation expense	55,344		46,713
Impairment and abandonment expense	7,606		7,784
Deferred tax expense	246,348		228,762
Net (gain) loss on sale of long-lived assets	—		(441)
Non-cash portion of derivative (gain) loss	(88,986)		(91,362)
Amortization of debt issuance costs, discount and premium	6,313		4,752
Loss on extinguishment of debt	270,120		8,585
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(40,230)		52,567
(Increase) decrease in prepaid and other assets	(2,975)		(6,828)
Increase (decrease) in accounts payable and other liabilities	25,101		4,618
Net cash provided by operating activities	2,703,214		2,540,390
Cash flows from investing activities:
Acquisition of oil and natural gas properties, net	(830,278)		(1,016,089)
Drilling and development capital expenditures	(1,485,408)		(1,556,208)
Purchases of other property and equipment	(11,344)		(7,101)
Proceeds from sales of oil and natural gas properties	179,616		15,579
Net cash used in investing activities	(2,147,414)		(2,563,819)
Cash flows from financing activities:
Proceeds from equity offering, net	—		402,211
Proceeds from borrowings under revolving credit facility	—		1,965,000
Repayment of borrowings under revolving credit facility	—		(1,965,000)
Proceeds from issuance of senior notes	—		1,000,000
Redemption of senior notes	(464,548)		(656,351)
Debt issuance and redemption costs	(18,535)		(22,582)
Proceeds from exercise of stock options	219		257
Share repurchases	(73,700)		(61,048)
Dividends paid	(324,201)		(361,402)
Distributions paid to noncontrolling interest owners	(42,573)		(78,889)
Net cash used in financing activities	(923,338)		222,196
Net increase (decrease) in cash, cash equivalents and restricted cash	(367,538)		198,767
Cash, cash equivalents and restricted cash, beginning of period	479,343		73,864
Cash, cash equivalents and restricted cash, end of period	$	111,805	$	272,631

The accompanying notes are an integral part of these unaudited consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)


	Nine Months Ended September 30,
	2025		2024
Supplemental cash flow information
Cash paid for interest	$	264,326	$	239,979
Cash paid (refunded) for income taxes	(589)		6,818
Supplemental non-cash activity
Equity issued to acquire oil and gas properties	—		100,371
Equity issued to redeem Convertible Senior Notes	430,021		—
Accrued capital expenditures included in accounts payable and accrued expenses	272,662		309,607
Asset retirement obligations incurred, including revisions to estimates	12,955		28,011
Dividends payable	12,529		7,394

Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:


	Nine Months Ended September 30,
	2025		2024
Cash and cash equivalents	$	111,805	$	272,026
Restricted cash(1)	—		605
Total cash, cash equivalents and restricted cash	$	111,805	$	272,631

(1) Included in Prepaid and other current assets as of September 30, 2024, in the consolidated balance sheets.

The accompanying notes are an integral part of these unaudited consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

(in thousands)


	Common Stock						Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Total Shareholders’ Equity		Non-controlling Interest		Total Equity
	Class A			Class C
	Shares	Amount		Shares	Amount
Balance at December 31, 2024	707,388	$	71	99,600	$	10	$	8,056,552	$	1,081,895	$	9,138,528	$	1,379,991	$	10,518,519
Restricted stock issued	2,203	—		—	—		—		—		—		—		—
Restricted stock forfeited	(66)	—		—	—		—		—		—		—		—
Stock-based compensation	—	—		—	—		16,929		—		16,929		—		16,929
Stock option exercises	4	—		—	—		21		—		21		—		21
Dividends	—	—		—	—		—		(107,519)		(107,519)		—		(107,519)
Distributions to noncontrolling interest owners	—	—		—	—		—		—		—		(14,940)		(14,940)
Conversion of common shares from Class C to Class A, net of tax	549	—		(549)	—		7,799		—		7,799		(7,825)		(26)
Equity impact from transactions effecting Common Units, net of tax of $0.3 million	—	—		—	—		(880)		—		(880)		1,133		253
Net income	—	—		—	—		—		329,298		329,298		61,265		390,563
Balance at March 31, 2025	710,078	$	71	99,051	$	10	$	8,080,421	$	1,303,674	$	9,384,176	$	1,419,624	$	10,803,800
Restricted stock issued	301	—		—	—		—		—		—		—		—
Restricted stock forfeited	(135)	—		—	—		—		—		—		—		—
Share repurchases - Class A	(4,120)	—		—	—		(43,347)		—		(43,347)		—		(43,347)
Performance stock units vested and issued	118	—		—	—		—		—		—		—		—
Stock-based compensation	—	—		—	—		20,164		—		20,164		—		20,164
Stock option exercises	5	—		—	—		38		—		38		—		38
Dividends	—	—		—	—		—		(107,067)		(107,067)		—		(107,067)
Distributions to noncontrolling interest owners	—	—		—	—		—		—		—		(14,857)		(14,857)
Equity impact from transactions effecting Common Units, net of tax of $0.8 million	—	—		—	—		(2,672)		—		(2,672)		3,438		766
Net income	—	—		—	—		—		207,137		207,137		37,884		245,021
Balance at June 30, 2025	706,247	$	71	99,051	$	10	$	8,054,604	$	1,403,744	$	9,458,429	$	1,446,089	$	10,904,518

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)

(in thousands)


	Common Stock						Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Total Shareholders’ Equity		Non-controlling Interest		Total Equity
	Class A			Class C
	Shares	Amount		Shares	Amount
Restricted stock issued	2,031	—		—	—		—		—		—		—		—
Restricted stock forfeited	(206)	—		—	—		—		—		—		—		—
Share repurchases - Class A	(250)	—		—	—		(3,432)		—		(3,432)		—		(3,432)
Share repurchases - Class C	—	—		(2,000)	—		—		—		—		(26,920)		(26,920)
Stock-based compensation	—	—		—	—		18,251		—		18,251		—		18,251
Stock option exercises	25	—		—	—		160		—		160		—		160
Dividends	—	—		—	—		—		(113,609)		(113,609)		—		(113,609)
Distributions to noncontrolling interest owners	—	—		—	—		—		—		—		(12,776)		(12,776)
Conversion of common shares from Class C to Class A, net of tax	11,877	1		(11,877)	(1)		173,649		—		173,649		(176,836)		(3,187)
Convertible senior notes redemption	30,569	3		—	—		430,018		—		430,021		—		430,021
Equity impact from transactions effecting Common Units, net of tax of $1.0 million	—	—		—	—		3,353		—		3,353		(4,316)		(963)
Net income	—	—		—	—		—		59,234		59,234		22,227		81,461
Balance at September 30, 2025	750,293	$	75	85,174	$	9	$	8,676,603	$	1,349,369	$	10,026,056	$	1,247,468	$	11,273,524

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)

(in thousands)


	Common Stock						Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Total Shareholders’ Equity		Non-controlling Interest		Total Equity
	Class A			Class C
	Shares	Amount		Shares	Amount
Balance at December 31, 2023	544,611	$	54	230,963	$	23	$	5,766,881	$	569,139	$	6,336,097	$	2,893,651	$	9,229,748
Restricted stock issued	1,713	1		—	—		(1)		—		—		—		—
Restricted stock forfeited	(65)	—		—	—		—		—		—		—		—
Share repurchases - Class C	—	—		(2,000)	—		—		—		—		(31,492)		(31,492)
Stock-based compensation	—	—		—	—		9,631		—		9,631		—		9,631
Stock option exercises	7	—		—	—		58		—		58		—		58
Dividends	—	—		—	—		—		(88,784)		(88,784)		—		(88,784)
Distributions to noncontrolling interest owners	—	—		—	—		—		—		—		(28,327)		(28,327)
Conversion of common shares from Class C to Class A, net of tax	41,356	4		(41,356)	(4)		559,584		—		559,584		(533,307)		26,277
Equity impact from transactions effecting Common Units, net of tax of $1.5 million	—	—		—	—		(5,080)		—		(5,080)		6,570		1,490
Net income	—	—		—	—		—		146,575		146,575		83,020		229,595
Balance at March 31, 2024	587,622	$	59	187,607	$	19	$	6,331,073	$	626,930	$	6,958,081	$	2,390,115	$	9,348,196
Restricted stock issued	410	—		—	—		—		—		—		—		—
Issuance of Class A Common Stock	6,242	—		—	—		100,371		—		100,371		—		100,371
Restricted stock forfeited	(352)	—		—	—		—		—		—		—		—
Share repurchases - Class C	—	—		(1,800)	—		—		—		—		(29,556)		(29,556)
Performance stock units vested and issued	457	—		—	—		—		—		—		—		—
Stock-based compensation	—	—		—	—		22,976		—		22,976		—		22,976
Stock option exercises	15	—		—	—		199		—		199		—		199
Dividends	—	—		—	—		—		(126,996)		(126,996)		—		(126,996)
Distributions to noncontrolling interest owners	—	—		—	—		—		—		—		(29,421)		(29,421)
Conversion of common shares from Class C to Class A, net of tax	85,104	9		(85,104)	(9)		1,162,903		—		1,162,903		(1,099,555)		63,348
Equity impact from transactions effecting Common Units, net of tax of $1.9 million	—	—		—	—		(6,470)		—		(6,470)		8,367		1,897
Net income	—	—		—	—		—		235,100		235,100		73,808		308,908
Balance at June 30, 2024	679,498	$	68	100,703	$	10	$	7,611,052	$	735,034	$	8,346,164	$	1,313,758	$	9,659,922

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PERMIAN RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)

(in thousands)


	Common Stock						Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Total Shareholders’ Equity		Non-controlling Interest		Total Equity
	Class A			Class C
	Shares	Amount		Shares	Amount
Restricted stock issued	126	—		—	—		—		—		—		—		—
Equity offering, net of issuance costs	26,500	3		—	—		402,208		—		402,211		—		402,211
Restricted stock forfeited	(148)	—		—	—		—		—		—		—		—
Performance stock units vested and issued	252	—		—	—		—		—		—		—		—
Stock-based compensation	—	—		—	—		14,106		—		14,106		—		14,106
Dividends	—	—		—	—		—		(149,513)		(149,513)		—		(149,513)
Distributions to noncontrolling interest owners		—		—	—		—		—		—		(21,140)		(21,140)
Conversion of common shares from Class C to Class A, net of tax	293	—		(293)	—		3,928		—		3,928		(3,883)		45
Equity impact from transactions effecting Common Units, net of tax of $1.6 million	—	—		—	—		(5,361)		—		(5,361)		6,935		1,574
Net income	—	—		—	—		—		386,376		386,376		70,151		456,527
Balance at September 30, 2024	706,521	$	71	100,410	$	10	$	8,025,933	$	971,897	$	8,997,911	$	1,365,821	$	10,363,732

The accompanying notes are an integral part of these unaudited consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

Permian Resources Corporation is an independent oil and natural gas company focused on the responsible acquisition, optimization and development of crude oil and associated liquids-rich natural gas reserves. The Company’s assets and operations are primarily concentrated in the core of the Permian Basin, and its properties consist of large, contiguous acreage blocks located in West Texas and New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Permian Resources” or the “Company” are to Permian Resources Corporation and its consolidated subsidiaries, including Permian Resources Operating, LLC (“OpCo”).

Principles of Consolidation and Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted or abbreviated. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2024 (the “2024 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the 2024 Annual Report. Certain prior period amounts have been reclassified to conform to the current presentation in the accompanying consolidated financial statements. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.

In the opinion of management, all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. The consolidated financial statements include the accounts of the Company, its subsidiary OpCo and OpCo’s wholly-owned subsidiaries. Noncontrolling interest represents third-party ownership in OpCo and is presented as a component of equity. Refer to Note 9—Shareholders’ Equity and Noncontrolling Interest for a discussion of noncontrolling interest.

Use of Estimates

The preparation of the Company’s consolidated financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and accordingly, actual results could differ from amounts previously established. Additionally, the prices received for oil, NGL and natural gas production can heavily influence the Company’s assumptions, judgments and estimates, and continued volatility of oil and gas prices could have a significant impact on the Company’s estimates.

The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves; (ii) cash flow estimates used in impairment tests for long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (v) asset retirement obligations; (vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vii) accrued revenues and related receivables; (viii) accrued liabilities; (ix) derivative valuations; (x) deferred income taxes; and (xi) determining the fair values of certain stock-based compensation awards.

Leases

The Company has operating leases for drilling rig contracts, office rental agreements and other wellhead equipment and a financing lease for a ground lease for its office building in Midland, Texas. During the nine months ended September 30, 2025, the Company entered into one drilling rig contract with a lease term of three years. A lease right-of-use asset and related liability were recorded for this drilling rig contract based on the present value of the future lease payments of the drilling rig over the lease terms. As of September 30, 2025, the Company recorded in aggregate $10.5 million and $16.2 million of current and noncurrent operating lease liabilities, respectively, related to the new drilling rig contract.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table provides additional information related to the Company’s lease assets and liabilities as presented on the balance sheet for the periods presented:


(in thousands)	Balance Sheet Classification	September 30, 2025		December 31, 2024
Assets
Operating right-of-use assets	Operating lease right-of-use assets	$	142,281	$	119,703
Finance right-of-use asset	Other noncurrent assets	14,916		15,033
Liabilities
Current
Operating lease liabilities	Operating lease liabilities	$	78,168	$	57,216
Finance lease liability	Other current liabilities	786		772
Noncurrent
Operating lease liabilities	Operating lease liabilities	$	66,013	$	64,288
Finance lease liability	Other noncurrent liabilities	15,432		15,168

There have been no other significant changes in leases during the nine months ended September 30, 2025.

Income Taxes

The Company is subject to U.S. federal, state and local income taxes with respect to its allocable share of any taxable income or loss of OpCo, as well as any stand-alone income generated by the Company. OpCo is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, OpCo is not subject to U.S. federal and certain state and local income taxes. Any taxable income generated by OpCo is passed through to and included in the taxable income of its members, including the Company, on a pro rata basis.

Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. OBBBA included multiple provisions applicable to U.S. income taxes for businesses of which those with the most significant impact to the Company include the reinstatement of 100% bonus depreciation for certain capital expenditures and allowing intangible drilling costs as deductions for purposes of computing the corporate alternative minimum tax. The effects of changes in tax law are recognized in the period of enactment, and as a result, OBBBA is currently recognized in the Company’s condensed consolidated financial statements, but did not have a material impact on the Company's effective tax rate for either the three or nine months ended September 30, 2025.

Segment Reporting

The nature of the Company’s operations and geographical location of such are concentrated to exploration and production of oil and natural gas within the Permian Basin. The Company’s chief operating decision maker (“CODM”) is each of its Co-Chief Executive Officers who manage and review the Company’s operations on a consolidated basis. Accordingly, the Company operates in one reportable segment.

The CODM uses consolidated net income to measure profit or loss, assess performance and make key operating decisions. Additionally, the CODM utilizes cash flows to facilitate investment decisions, including determining future levels of developmental capital expenditures, assessing potential acquisitions and divestitures, assessing appropriate returns of capital to shareholders and other strategic sources and uses of capital. The CODM does not generally evaluate performance using asset information. Consolidated net income and all significant expenses are reported within the Company’s consolidated statements of operations while cash flows are presented on the Company’s consolidated statement of cash flows.

Recently Issued Accounting Standards

In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-09, Improvements to Income Tax Disclosures, which requires public business entities to provide additional income tax disclosures including, among others, disaggregation of the effective tax rate reconciliation and information regarding income taxes paid. This ASU will result in additional disclosures in the notes to the Company’s financial statements beginning with the 2025 annual report and interim reporting periods beginning in 2026.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In November 2024, the FASB issued ASU No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures, which requires public business entities to disclose specific expense categories in the notes to the financial statements. This ASU is effective for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027. The Company is currently assessing the impact of this ASU on the Company’s financial statements.

Note 2—Acquisitions

2025 Bolt-On Acquisitions

On June 16, 2025, the Company completed its 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 the Company’s existing asset position in the core of its New Mexico operating area. The acquisition was recorded as an asset acquisition in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations (“ASC 805”). Total consideration paid was $572.3 million after settlement statement adjustments, of which $500.6 million was allocated to proved properties and $80.8 million to unproved properties on a relative fair value basis with the remaining $9.1 million related to liabilities assumed.

During the nine months ended September 30, 2025, the Company completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $225.6 million. These transactions were recorded as asset acquisitions in accordance with ASC 805.

2024 Bolt-On Acquisition

On September 17, 2024, the Company completed its acquisition of oil and gas properties with certain affiliates of Occidental Petroleum Corporation (the “Bolt-On Acquisition”). The Bolt-On Acquisition included approximately 29,500 net leasehold acres and approximately 9,900 net royalty acres that are predominately located directly offsetting the Company’s existing assets in Reeves County, Texas, as well as Eddy County, New Mexico. Refer to Note 2—Business Combinations footnote in the notes to the consolidated financial statements in Item 8 of the Company’s 2024 Annual Report for additional details regarding the Bolt-On Acquisition.

Purchase Price Allocation

The purchase price allocation was finalized during the nine months ended September 30, 2025. The following table represents the final consideration and purchase price of the identifiable assets acquired and the liabilities assumed based on their respective fair value as of the closing date of the Bolt-On Acquisition.


(in thousands, except share and per share data)	Bolt-On Acquisition Consideration
Total cash consideration given	$	775,826

Fair value of assets acquired:	Purchase Price Allocation
Accounts receivable, net	$	1,134
Oil and natural gas properties, net	806,543
Total assets acquired	$	807,677

Fair value of liabilities assumed:
Accounts payable and accrued expenses	$	16,697
Asset retirement obligations	15,154
Total liabilities assumed	$	31,851
Net assets acquired	$	775,826

The pro forma impact of this business combination to revenues and net income is not disclosed as it was deemed not to have a material impact on the Company’s results of operations.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:


(in thousands)	September 30, 2025		December 31, 2024
Accrued oil and gas sales receivable, net	$	273,549	$	326,393
Joint interest billings, net	257,187		188,474
Accrued derivative settlements receivable	30,819		8,585
Other	10,223		7,000
Accounts receivable, net	$	571,778	$	530,452

Accounts payable and accrued expenses are comprised of the following:


(in thousands)	September 30, 2025		December 31, 2024
Accounts payable	$	90,550	$	45,965
Accrued capital expenditures	216,765		267,213
Revenues payable	671,243		589,454
Accrued employee compensation and benefits	24,177		28,550
Accrued interest	64,945		121,204
Accrued expenses and other	143,761		146,032
Accounts payable and accrued expenses	$	1,211,441	$	1,198,418

Note 4—Long-Term Debt

The following table provides information about the Company’s long-term debt as of the dates indicated:


(in thousands)	September 30, 2025		December 31, 2024
Credit Facility	$	—	$	—

Senior Notes
5.375% Senior Notes due 2026	—		289,448
8.00% Senior Notes due 2027	550,000		550,000
3.25% Convertible Senior Notes due 2028	—		170,000
5.875% Senior Notes due 2029	700,000		700,000
9.875% Senior Notes due 2031	325,000		500,000
7.00% Senior Notes due 2032	1,000,000		1,000,000
6.25% Senior Notes due 2033	1,000,000		1,000,000
Unamortized debt issuance costs on Senior Notes	(25,137)		(31,545)
Unamortized debt (discount)/premium	(5,027)		6,330
Senior Notes, net	3,544,836		4,184,233

Total long-term debt, net	$	3,544,836	$	4,184,233

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Credit Agreement

OpCo, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a secured revolving credit facility, maturing in February 2028 (the “Credit Agreement”) that, as of September 30, 2025, had a borrowing base of $4.0 billion and elected commitments of $2.5 billion. As of September 30, 2025, the Company had no borrowings outstanding and $2.5 billion in available borrowing capacity, net of $2.5 million in letters of credit outstanding.

In connection with the spring borrowing base redetermination on April 30, 2025, the Company entered into the ninth amendment to its Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) reaffirmed the borrowing base at $4.0 billion and (ii) reaffirmed the aggregate elected commitments at $2.5 billion. Refer to Note 13—Subsequent Events for additional information regarding the 2025 fall borrowing base redetermination.

The amount available to be borrowed under the Credit Agreement is equal to the lesser of (i) the borrowing base, which is set at $4.0 billion; (ii) aggregate elected revolving commitments, which is set at $2.5 billion; or (iii) $6.0 billion. The borrowing base is redetermined semi-annually in the spring and fall by the lenders in their sole discretion. It also allows for the Company to request two optional borrowing base redeterminations in between the scheduled redeterminations; one at the Borrower’s request and an additional one in connection with any Material Acquisition (as defined in the Credit Agreement). The borrowing base depends on, among other things, the quantities of OpCo’s proved oil and natural gas reserves, estimated cash flows from those reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings outstanding exceed the revised borrowing capacity, OpCo could be required to immediately repay a portion of its debt outstanding in an amount equal to the excess. Borrowings under the Credit Agreement are guaranteed by certain of OpCo’s subsidiaries.

Borrowings under the Credit Agreement may be base rate loans or SOFR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of elected commitments utilized, plus an additional 10 basis point credit spread adjustment. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin, ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. OpCo also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.

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.

OpCo was in compliance with the covenants and the applicable financial ratios described above as of September 30, 2025.

Convertible Senior Notes

In March 2021, OpCo issued $170.0 million in aggregate principal amount of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”) resulting in aggregate net proceeds to OpCo of $163.6 million, after deducting debt issuance costs of $6.4 million. Interest was payable on the Convertible Senior Notes semi-annually in arrears on each April 1 and October 1 with a maturity date of April 1, 2028.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Convertible Senior Notes could be settled by paying or delivering, as applicable, cash, shares of Class A Common Stock, or a combination of cash and shares of Class A Common Stock, at OpCo’s election. On or after April 7, 2025, the Convertible Senior Notes could be redeemed at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, if the last reported sale price per share of Class A Common Stock exceeded 130% of the conversion price (i) for any 20 trading days during the 30 consecutive trading days ending on the day immediately before the date OpCo sends the related redemption notice; and (ii) also on the trading day immediately before the date OpCo sends such notice.

On August 28, 2025, the Company issued a redemption notice (the “Redemption Notice”) to holders of the Convertible Senior Notes (“Holders”) calling for the redemption of all outstanding Convertible Senior Notes (the “Redemption”). The Redemption Notice allowed Holders the right to convert each $1,000 principal amount of the Convertible Senior Notes for 179.9208 shares of Class A Common Stock (the “Conversion Rate”) or a cash redemption price of $1,014.53. Certain Holders exercised their right to convert $169.9 million aggregate principal amount of the Convertible Senior Notes for 30.6 million shares of Class A Common Stock based on the Conversion Rate. The Class A Common Stock issued in the Redemption was valued at $430.0 million based on the trading price of the Company’s Class A Common Stock on the date of each conversion and was recorded as an increase to additional paid-in capital within the consolidated balance sheets. The remaining $0.1 million principal amount of Convertible Senior Notes was redeemed for cash.

The Redemption was accounted for as an extinguishment of debt in accordance with ASC 470-50, Modifications and Extinguishments, which resulted in a loss on extinguishment of debt of $263.9 million being recognized in the consolidated statement of operations during the nine months ended September 30, 2025. This loss on extinguishment of debt consisted of the difference in the value of the 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.

Capped Called Transactions

In connection with the issuance of the Convertible Senior Notes in March 2021, OpCo entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Class A Common Stock that initially underlie the Convertible Senior Notes and have a strike price of $6.28 per share of Class A Common Stock and a capped price of $8.4525 per share of Class A Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements. Following the Redemption, the Company elected to keep the Capped Call Transactions outstanding and the instruments are scheduled to expire on April 1, 2028.

Senior Unsecured Notes

The table below summarizes the interest rates, interest payment dates, principal amounts outstanding and the maturity dates related to OpCo’s outstanding senior unsecured note obligations as of September 30, 2025.

Interest Rate

Interest Payment Dates

Principal Amount

Maturity Date

8.00% Senior Notes due 2027

8.00%

April 15, October 15

550,000

April 15, 2027

5.875% Senior Notes due 2029

5.875%

January 1, July 1

700,000

July 1, 2029

9.875% Senior Notes due 2031

9.875%

January 15, July 15

325,000

July 15, 2031

7.00% Senior Notes due 2032

7.00%

January 15, July 15

1,000,000

January 15, 2032

6.25% Senior Notes due 2033

6.25%

February 1, August 1

1,000,000

February 1, 2033

The 8.00% senior notes due 2027, 5.875% senior notes due 2029, 9.875% senior notes due 2031, 7.00% senior notes due 2032 and 6.25% senior notes due 2033 (collectively, the “Senior Unsecured Notes”) are unsecured senior obligations. OpCo may redeem some or all of its Senior Unsecured Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Unsecured Notes. The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of OpCo’s current subsidiaries that guarantee borrowings under OpCo’s Credit Agreement.

If OpCo experiences certain defined changes of control accompanied by a ratings decline, each holder of the Senior Unsecured Notes may require OpCo to repurchase all or a portion of its Senior Unsecured Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Unsecured Notes, plus any accrued but unpaid interest to the date of repurchase.

The indentures governing the Senior Unsecured Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit OpCo’s ability and the ability of OpCo’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. OpCo was in compliance with these covenants as of September 30, 2025.

Please refer to Note 5—Long-Term Debt included in Part II, Item 8 in the 2024 Annual Report for additional details around OpCo’s Senior Unsecured Notes and Convertible Senior Notes.

Partial Senior Note Repurchase and Redemptions

During June 2025, the Company repurchased $2.7 million of its outstanding 5.375% senior notes due 2026 (the “2026 5.375% 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, on September 20, 2025, the Company redeemed all remaining outstanding 2026 5.375% 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, the Company redeemed $175 million of its 9.875% senior notes due 2031 (the “2031 Senior Notes”) at a redemption price equal to 109.875% of the principal amount redeemed plus accrued and unpaid interest up to, but excluding, the redemption date. The Company paid total consideration of $192.3 million, excluding interest, resulting in a loss on extinguishment of debt of $5.8 million after writing off the carrying value of the 2031 Senior Notes of $186.5 million, which included the associated pro rata unamortized debt premium. Following the redemption, the remaining aggregate principal amount of the 2031 Senior Notes outstanding was $325 million.

Note 5—Asset Retirement Obligations

The following table summarizes changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the nine months ended September 30, 2025:


(in thousands)
Asset retirement obligations, beginning of period	$	160,089
Liabilities incurred	6,639
Liabilities acquired	6,316
Liabilities divested and settled	(6,019)
Accretion expense	8,607

Asset retirement obligations, end of period	175,632
Less current portion(1)	(11,934)
Asset retirement obligations - long-term, end of period	$	163,698

(1) The current portion of ARO is included within Other current liabilities in the consolidated balance sheets.

ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous estimates and assumptions, including plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and the timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liabilities, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability with an offsetting charge to accretion expense, which is included within depreciation, depletion and amortization.

Note 6—Stock-Based Compensation

The Company has a Long Term Incentive Plan (the “LTIP”) that has a total of 71,718,560 shares of Class A Common Stock authorized for issuance. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units (including performance stock units), stock appreciation rights and other stock or cash-based awards.

Stock-based compensation expense is recognized within both General and administrative expenses and Exploration and other expenses in the consolidated statements of operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur.

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The following table summarizes stock-based compensation expense recognized for the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2025		2024		2025		2024
Equity Awards
Restricted stock	$	7,463	$	6,083	$	21,390	$	21,522
Performance stock units	10,788		8,023		33,954		25,191
Total stock-based compensation expense	$	18,251	$	14,106	$	55,344	$	46,713

Equity Awards

The Company has restricted stock, stock options and performance stock units (“PSUs”) outstanding that were granted under the LTIP as discussed below. Each award has service-based and, in the case of the PSUs, market-based vesting requirements, and is expected to be settled in shares of Class A Common Stock upon vesting. As a result, these awards are classified as equity-based awards in accordance with ASC Topic 718, Compensation-Stock Compensation.

Restricted Stock

The following table provides information about restricted stock activity during the nine months ended September 30, 2025:


	Restricted Stock	Weighted Average Fair Value
Unvested balance as of December 31, 2024	3,614,303	$	12.64
Granted	4,535,288	14.32
Vested	(1,514,384)	11.11
Forfeited	(407,098)	13.99
Unvested balance as of September 30, 2025	6,228,109	14.15

The Company grants service-based restricted stock to certain officers and employees, which either vests ratably over a three-year service period or cliff vests upon an eighteen month to five year service period, and to directors, which vest over a one-year service period. Compensation cost for these service-based restricted stock grants is based on the closing market price of the Company’s Class A Common Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The total fair value of restricted stock that vested during the nine months ended September 30, 2025 and 2024 was $16.8 million and $19.1 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of September 30, 2025 was $69.7 million, which the Company expects to recognize over a weighted average period of 2.4 years.

Stock Options

Stock options that have been granted under the LTIP expire ten years from the grant date and vest ratably over their three-year service period. The exercise price for an option granted under the LTIP is the closing market price of the Company’s Class A Common Stock on the grant date. Compensation cost for stock options is based on the grant-date fair value of the award, which is then recognized ratably over the vesting period of three years.

The following table provides information about stock option awards outstanding during the nine months ended September 30, 2025:


	Options	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2024	388,033	$	16.10		$	628

Exercised	(35,000)	6.58			257

Expired	(73,500)	18.02
Outstanding as of September 30, 2025	279,533	16.78		2.2	284
Exercisable as of September 30, 2025	279,533	16.78		2.2	284

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Performance Stock Units

The Company grants PSUs to certain officers and members of management that are subject to market-based vesting criteria as well as a service period of three years. Vesting at the end of the service period depends on the Company’s absolute annualized total shareholder return (“TSR”) over the performance period, as well as the Company’s TSR relative to the TSR of a group of peer companies. These market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the PSUs subject to market conditions regardless of whether it becomes probable that these conditions will be met or not, and compensation expense is not reversed if vesting does not actually occur.

The Company’s PSUs currently outstanding can be settled in either Class A Common Stock or cash upon vesting at the Company’s discretion. The Company intends to settle all PSUs in Class A Common Stock and has sufficient shares available under the LTIP to settle the units in Class A Common Stock at the potential future vesting dates. Accordingly, the PSUs have been treated as equity-based awards with their fair values determined as of the grant or modification date, as applicable. The fair values of the awards are estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Class A Common Stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods.

The following table summarizes the key assumptions and related information used to determine the fair value of PSUs granted during the nine months ended September 30, 2025:


			2025 Awards

Fair value per share			$19.53
Expected implied stock volatility			34.6%
Risk-free interest rate			4.2%

The following table provides information about PSUs outstanding during the nine months ended September 30, 2025:


	Awards	Weighted Average Fair Value
Unvested balance as of December 31, 2024	5,343,399	$	16.54
Granted	2,216,934	19.53
Vested(1)	(47,082)	30.62
Forfeited	(5,921)	23.49
Unvested balance as of September 30, 2025	7,507,330	17.33

(1) This balance includes vested PSU awards as of September 30, 2025 based on the original number of PSUs granted. Actual PSUs vested is based upon the Company’s absolute annualized TSR calculation at the time of vesting, which may be greater than or less than the original number granted.

As of September 30, 2025, there was $42.4 million of unrecognized compensation cost related to PSUs that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 1.6 years.

Note 7—Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.

Commodity Derivative Contracts

Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars, basis swaps, and other similar agreements, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flows from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.

Commodity Swaps. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production or basis swaps to hedge the difference between the index price and a local or future

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index price. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.

The following table summarizes the approximate volumes and average contract prices of derivative contracts the Company had in place as of September 30, 2025:


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Crude Price ($/Bbl)
Crude oil swaps - NYMEX WTI	October 2025 - December 2025	5,244,000	57,000	$70.99
	January 2026 - March 2026	2,655,000	29,500	69.71
	April 2026 - June 2026	2,684,500	29,500	68.85
	July 2026 - September 2026	2,714,000	29,500	68.13
	October 2026 - December 2026	2,714,000	29,500	67.57


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)
Crude oil basis differential swaps(1)	October 2025 - December 2025	4,140,000	45,000	$1.10
	January 2026 - March 2026	2,655,000	29,500	1.07
	April 2026 - June 2026	2,684,500	29,500	1.07
	July 2026 - September 2026	2,714,000	29,500	1.07
	October 2026 - December 2026	2,714,000	29,500	1.07


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)
Crude oil roll differential swaps - NYMEX WTI	October 2025 - December 2025	5,244,000	57,000	$0.55
	January 2026 - March 2026	1,575,000	17,500	0.28
	April 2026 - June 2026	1,592,500	17,500	0.28
	July 2026 - September 2026	1,610,000	17,500	0.28
	October 2026 - December 2026	1,610,000	17,500	0.28

(1) These crude oil basis swap transactions are settled utilizing the ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices.


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Gas Price ($/MMBtu)
Natural gas swaps - NYMEX Henry Hub	October 2025 - December 2025	15,180,000	165,000	$4.02
	January 2026 - March 2026	8,190,000	91,000	4.08
	April 2026 - June 2026	8,281,000	91,000	3.40
	July 2026 - September 2026	8,372,000	91,000	3.65
	October 2026 - December 2026	8,372,000	91,000	4.01
	January 2027 - March 2027	12,600,000	140,000	4.24
	April 2027 - June 2027	12,740,000	140,000	3.32
	July 2027 - September 2027	12,880,000	140,000	3.58
	October 2027 - December 2027	12,880,000	140,000	3.94

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	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Gas Price ($/MMBtu)
Natural gas swaps - Waha Hub	October 2025 - December 2025	7,530,000	81,848	$1.41
	January 2026 - March 2026	5,850,000	65,000	2.78
	April 2026 - June 2026	5,915,000	65,000	0.27
	July 2026 - September 2026	5,980,000	65,000	1.68
	October 2026 - December 2026	12,385,000	134,620	2.68
	January 2027 - March 2027	7,650,000	85,000	3.57


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Differential ($/MMBtu)
Natural gas basis differential swaps(1)	October 2025 - December 2025	19,044,000	207,000	$(1.43)
	January 2026 - March 2026	12,330,000	137,000	(1.34)
	April 2026 - June 2026	12,467,000	137,000	(2.31)
	July 2026 - September 2026	12,604,000	137,000	(1.42)
	October 2026 - December 2026	12,604,000	137,000	(1.21)
	January 2027 - March 2027	14,490,000	161,000	(0.47)
	April 2027 - June 2027	14,651,000	161,000	(1.11)
	July 2027 - September 2027	14,812,000	161,000	(0.65)
	October 2027 - December 2027	14,812,000	161,000	(0.91)

(1) These natural gas basis swap contracts are settled utilizing the Inside FERC’s West Texas Waha Hub price and the NYMEX Henry Hub price of natural gas.

Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes. Therefore, all gains and losses are recognized in the Company’s consolidated statements of operations. All derivative instruments are recorded at fair value in the consolidated balance sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.

The following table presents the impact of the Company’s derivative instruments in its consolidated statements of operations for the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2025		2024		2025		2024
Net gain (loss) on derivative instruments	$	105,714	$	238,533	$	236,464	$	131,702

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Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarize the fair value amounts and the classification in the consolidated balance sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:


	Balance Sheet Classification	Gross Fair Value Asset/Liability Amounts		Gross Amounts Offset(1)		Net Recognized Fair Value Assets/Liabilities
(in thousands)		September 30, 2025
Derivative Assets
Commodity contracts	Derivative instruments	$	209,818	$	(4,830)	$	204,988
	Other noncurrent assets	22,332		(14,515)		7,817
Derivative Liabilities
Commodity contracts	Other current liabilities	$	4,830	$	(4,830)	$	—
	Other noncurrent liabilities	26,978		(14,515)		12,463

		December 31, 2024
Derivative Assets
Commodity contracts	Derivative instruments	$	95,771	$	(10,262)	$	85,509
	Other noncurrent assets	32,858		(3,971)		28,887
Derivative Liabilities
Commodity contracts	Other current liabilities	$	13,302	$	(10,262)	$	3,040
	Other noncurrent liabilities	3,971		(3,971)		—

(1) The Company has agreements in place with each of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or if contracts are terminated.

Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are primarily lenders under OpCo’s Credit Agreement. The Company enters into new hedge arrangements only with participants under its Credit Agreement, since these institutions are secured equally with the holders of any OpCo bank debt, which eliminates the potential need to post collateral when the Company is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a lender under OpCo’s Credit Agreement as referenced above.

Note 8—Fair Value Measurements

Recurring Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

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•Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The following table presents, for each applicable level within the fair value hierarchy, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:


(in thousands)	Level 1		Level 2		Level 3
September 30, 2025
Total assets	$	—	$	212,805	$	—
Total liabilities	—		12,463		—
December 31, 2024
Total assets	$	—	$	114,396	$	—
Total liabilities	—		3,040		—

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.

Derivatives

The Company uses Level 2 inputs to measure the fair value of its oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. Refer to Note 7—Derivative Instruments for details of the gross and net derivative assets, liabilities and offset amounts as presented in the consolidated balance sheets.

Nonrecurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

Oil and Gas Property Acquisitions. The fair value measurements of assets acquired and liabilities assumed are measured on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; (vi) a market participant-based weighted average cost of capital rate and (vii) risk adjustment factors applied to proved and unproved reserves. These inputs require significant judgements and estimates by the Company’s management at the time of valuation.

Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.

The Company calculates the estimated fair value of its oil and natural gas properties using an income approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) oil and gas reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management.

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Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.

Other Financial Instruments

The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.

The Company’s senior notes and borrowings under its Credit Agreement are accounted for at cost. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the periods indicated:


	September 30, 2025						December 31, 2024
	Carrying Value		Principal Amount		Fair Value		Carrying Value		Principal Amount		Fair Value
Credit Facility(1)	$	—	$	—	$	—	$	—	$	—	$	—
5.375% Senior Notes due 2026(2)	—		—		—		288,357		289,448		287,400
8.00% Senior Notes due 2027(2)	557,597		550,000		559,861		560,910		550,000		561,855
3.25% Convertible Senior Notes due 2028(2)	—		—		—		166,803		170,000		436,554
5.875% Senior Notes due 2029(2)	670,024		700,000		701,546		664,935		700,000		688,103
9.875% Senior Notes due 2031(2)	344,409		325,000		354,279		532,730		500,000		550,562
7.00% Senior Notes due 2032(2)	985,725		1,000,000		1,040,126		984,426		1,000,000		1,017,903
6.25% Senior Notes due 2033(2)	987,081		1,000,000		1,020,062		986,072		1,000,000		989,508

(1) The carrying values of the amounts outstanding under OpCo’s Credit Agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.

(2) The carrying values include associated unamortized debt issuance costs and any debt discounts or premiums as reflected in the consolidated balance sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the senior notes outstanding.

Note 9—Shareholders’ Equity and Noncontrolling Interest

Stock Conversion

During the nine months ended September 30, 2025 and 2024, certain legacy owners of Colgate Energy Partners III, LLC (“Colgate”) and Earthstone Energy, Inc. (“Earthstone”) exchanged 12.4 million and 126.8 million, respectively, of their common units of OpCo (“Common Units”) with the cancellation of a corresponding number of shares of Class C Common Stock, for an equivalent number of shares of Class A Common Stock. A deferred tax liability of $3.2 million and a deferred tax asset of $89.7 million were recorded in equity as a result of the conversions of shares from the noncontrolling interest owners for the nine months ended September 30, 2025 and 2024, respectively. No cash proceeds were received by the Company in connection with these transactions.

Stock Issuances

During the nine months ended September 30, 2025, the Company issued 30.6 million shares of Class A Common Stock in connection with the Redemption of its Convertible Senior Notes as discussed in Note 4—Long-Term Debt.

During the nine months ended September 30, 2024, the Company completed an underwritten public offering of 26.5 million shares of its Class A Common Stock in which the Company received net cash proceeds of $402.2 million after underwriting discounts and commissions. The Company used the net proceeds from this equity offering to fund a portion of the aggregate purchase price of the Bolt-On Acquisition discussed in Note 2—Acquisitions.

Additionally, during the nine months ended September 30, 2024, the Company issued 6.2 million shares of Class A Common Stock, which were issued as partial consideration for a portion of the asset acquisitions executed during the year ended December 31, 2024 (discussed in Note 3 — Acquisitions and Divestitures in the 2024 Annual Report). No cash proceeds were received by the Company in connection with this issuance.

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Dividends

The following table summarizes the Company’s base and variable dividend per share of Class A Common Stock and distribution per Common Unit (each of which has an underlying share of Class C Common Stock) declared and paid during each period:


	Dividend/Distribution per Share						Total Dividends/Distributions Declared and Paid
	Base		Variable		Total
Three Months Ended,							(in thousands)
September 30, 2025	$	0.15	$	—	$	0.15	$	125,200
September 30, 2024	$	0.06	$	0.15	$	0.21	$	170,156
Nine Months Ended,
September 30, 2025	$	0.45	$	—	$	0.45	$	366,774
September 30, 2024	$	0.17	$	0.39	$	0.56	$	440,291

Repurchase Program

The Company’s Board of Directors authorized a stock repurchase program to acquire up to $1 billion of the Company’s outstanding common stock (the “Repurchase Program”), which was approved to run on an indefinite basis and can be used by the Company to reduce its shares of Class A Common Stock and Class C Common Stock outstanding. Repurchases may be made from time to time in the open-market or via privately negotiated transactions at the Company’s discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt agreements and other factors. The Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by the Company’s Board of Directors at any time.

During the nine months ended September 30, 2025, the Company paid $46.8 million to repurchase 4.4 million shares of Class A Common Stock at a weighted average price of $10.70 per share as part of the Repurchase Program. The shares that were repurchased were subsequently canceled by the Company.

Additionally, during the nine months ended September 30, 2025 and 2024, the Company paid $26.9 million and $61.0 million, respectively, to repurchase 2.0 million and 3.8 million, respectively, Common Units of OpCo resulting in an equal number of the underlying shares of Class C Common Stock simultaneously being canceled under its Repurchase Program.

Noncontrolling Interest

The noncontrolling interest relates to Common Units that were issued in connection with the merger with Colgate on September 1, 2022 and the merger with Earthstone on November 1, 2023. The noncontrolling interest percentage is affected by various equity transactions such as conversions of Common Units for Class A Common Stock (and corresponding Class C Common Stock cancellations) and transactions involving Class A Common Stock.

As of September 30, 2025 the noncontrolling interest ownership of OpCo had decreased to 10% from 12% as of December 31, 2024. The Company consolidates the financial position, results of operations and cash flows of OpCo and reflects the portion retained by other holders of Common Units as a noncontrolling interest. Refer to the consolidated statements of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the period.

Note 10—Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income attributable to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income by the weighted average shares of diluted Class A Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested equity-based restricted stock and performance stock units and outstanding stock options, all using the treasury stock method; and (ii) the Company’s Class C Common Stock and shares issuable for our Convertible Senior Notes, which were fully redeemed during the three months ended September 30, 2025, both using the “if-converted” method, which is net of tax.

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(Unaudited)

The following table reflects the EPS computations for the periods indicated based on a weighted average number of Class A Common Stock outstanding each period:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per share data)	2025		2024		2025		2024
Net income attributable to Class A Common Stock	$	59,234	$	386,376	$	595,669	$	768,051

Add: Interest on Convertible Senior Notes, net of tax	—		1,305		—		3,887
Adjusted net income (attributable to Class A Common Stock)	$	59,234	$	387,681	$	595,669	$	771,938

Basic weighted average shares of Class A Common Stock outstanding	712,282		693,692		705,920		619,741

Add: Dilutive effects of Convertible Senior Notes	—		29,117		—		29,117
Add: Dilutive effects of equity awards	15,411		13,430		14,818		14,457
Diluted weighted average shares of Class A Common Stock outstanding	727,693		736,239		720,738		663,315

Basic net earnings per share of Class A Common Stock	$	0.08	$	0.56	$	0.84	$	1.24
Diluted net earnings per share of Class A Common Stock	$	0.08	$	0.53	$	0.83	$	1.16

The following table presents shares excluded from the diluted earnings per share calculation for the periods presented as their impact was anti-dilutive:


	Three Months Ended September 30,		Nine Months Ended September 30,
(in thousands)	2025	2024	2025	2024
Weighted average shares of Class C Common Stock	95,660	100,670	98,087	159,396
Convertible Senior Notes	22,864	—	27,972	—
Performance stock units	1,250	831	1,341	277
Restricted stock	690	325	1,169	182
Out-of-the-money stock options	246	436	274	482

Note 11—Commitments and Contingencies

Commitments

During the nine months ended September 30, 2025, the Company entered into a series of firm commitment transportation agreements that guarantee volumetric capacity on pipelines for gas transportation with varying terms over ten years. The agreements are effective beginning in 2025 and will provide the Company natural gas capacity on the pipelines ranging from 25,000 to 300,000 MMBtu per day. The Company is not required to deliver natural gas volumes specifically produced from any of the Company’s properties under these agreements. The agreements include demand fees that are applied to the total volumetric capacity per the agreements regardless if utilized. As a result, the aggregate minimum financial commitment amount over the term of these agreements is approximately $1.2 billion based upon the volumetric commitments per the agreements as of September 30, 2025. The Company has paid $2.5 million related to these commitments during the nine months ended September 30, 2025, which are included in the Purchased gas sales, net line item described in Note 12—Revenues.

The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. There has been no other material, non-routine changes in commitments during the nine months ended September 30, 2025.

Contingencies

The Company may at times be subject to various commercial or regulatory claims, prior period adjustments from service providers, litigation or other legal proceedings that arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations, or cash flows. Management is unaware of any pending litigation brought against the Company requiring a contingent liability to be recognized as of the date of these consolidated financial statements.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 12—Revenues

Revenue from Contracts with Customers

Crude oil, NGL and natural gas sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Substantially all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, NGLs and natural gas fluctuate to remain competitive with other available oil, NGLs and natural gas supplies both globally and locally.

Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas, NGLs and purchased gas sales as shown below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Operating revenues (in thousands):
Oil sales	$	1,113,847	$	1,099,318	$	3,231,068	$	3,265,303
NGL sales	170,385		153,340		513,426		460,701
Natural gas sales	33,856		(37,087)		145,686		(21,351)
Purchased gas sales, net	3,708		—		5,663		—
Oil and gas sales	$	1,321,796	$	1,215,571	$	3,895,843	$	3,704,653

Oil sales

The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.

NGL and Natural gas sales

Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream gathering and processing entity at the agreed upon delivery point at which the purchaser takes title of the product. The midstream processing entity gathers and processes the raw gas and then remits proceeds to the Company. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company elects to take its NGL or residue gas product “in-kind” at the plant tailgate, fees incurred prior to transfer of control at the outlet of the plant are presented as GP&T within the consolidated statements of operations. Where the Company does not take its NGL or residue gas products “in-kind”, transfer of control occurs at the inlet of the gas gathering systems, or prior, and fees incurred subsequent to this point are reflected as a net reduction to NGL and natural gas sales revenues presented in the table above.

Purchased gas sales

The Company has entered into a series of natural gas purchase and sale agreements to facilitate the sale of natural gas at additional markets. The proceeds and costs of these transactions are presented net as they are transacted with the same counterparty (or same related parties) as shown in the line item Purchased gas sales, net in the table above.

Performance obligations

For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for crude oil are generally received within 30 days following the date that production volumes are delivered, but for NGL and natural gas sales, statements may not be received for 30 to 60 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the consolidated balance sheets. As of September 30, 2025 and December 31, 2024, such receivable balances were $273.5 million and $326.4 million, respectively.

The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the nine months ended September 30, 2025 and 2024, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not material.

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PERMIAN RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606, Revenue from contracts with Customers, which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation. Therefore, future commodity volumes to be delivered and sold are wholly unsatisfied, and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required.

Note 13—Subsequent Events

Amended Credit Agreement

In connection with the fall borrowing base redetermination on October 24, 2025, the Company entered into the tenth amendment to its Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) reaffirmed the borrowing base at $4.0 billion, (ii) reaffirmed the aggregate elected revolving commitments at $2.5 billion, (iii) adjusted the applicable margin by (a) adding a new borrowing base utilization pricing grid applicable on any day during a borrowing base period on which the Company has an index debt rating of BBB- or better from Fitch Ratings, Inc. and (b) subject to certain conditions, reducing the interest rates applicable on any day during an investment grade period, and (iv) removed the additional 10 basis point credit spread adjustment factor from the SOFR definition.

Dividends Declared

On November 5, 2025, the Company announced that its Board of Directors declared a quarterly base dividend of $0.15 per share of Class A Common Stock and distribution of $0.15 per share of Class C Common Stock (each of which has an underlying Common Unit of OpCo). The dividend is payable December 31, 2025, to shareholders of record as of December 17, 2025.

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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, inflation, 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 2024 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 the responsible acquisition, optimization and development of high-return oil and natural gas properties. Our assets are mainly located in the core of the Permian Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way, 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.

Concerns of 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 the third quarter of 2025.

Throughout 2024 and 2025, natural gas prices in the Permian Basin have been 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, including the OBBBA, 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
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
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

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 secured revolving credit facility (the “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 the 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.

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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. As commodity prices rise, costs of oilfield goods and services generally also increase; however, during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. 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

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 nine months ended September 30, 2025, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $225.6 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs.

Return of Capital Program

During the nine months ended September 30, 2025, we declared and paid quarterly base dividends totaling $0.45 per share of Class A Common Stock and distributions totaling $0.45 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 to common unitholders totaled $366.8 million for the nine months ended September 30, 2025.

During the nine months ended September 30, 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 stock 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 5.375% 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 5.375% 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.

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Results of Operations

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 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:


	Three Months Ended September 30,				Increase/(Decrease)
	2025		2024		$		%
Net revenues (in thousands):
Oil sales	$	1,113,847	$	1,099,318	$	14,529	1	%
NGL sales	170,385		153,340		17,045		11	%
Natural gas sales	33,856		(37,087)		70,943		191	%
Purchased gas sales, net	3,708		—		3,708		100	%
Oil and gas sales	$	1,321,796	$	1,215,571	$	106,225	9	%

Net production:
Oil (MBbls)	17,198		14,794		2,404		16	%
NGL (MBbls)	9,736		7,889		1,847		23	%
Natural gas (MMcf)	64,841		55,496		9,345		17	%
Total (MBoe)(1)	37,741		31,932		5,809		18	%

Average daily net production:
Oil (Bbls/d)	186,937		160,801		26,136		16	%
NGL (Bbls/d)	105,822		85,754		20,068		23	%
Natural gas (Mcf/d)	704,795		603,217		101,578		17	%
Total (Boe/d)(1)	410,225		347,091		63,134		18	%

Average sales prices:
Oil (per Bbl)	$	64.77	$	74.31	$	(9.54)	(13)	%
Effect of derivative settlements on average price (per Bbl)	2.20		0.09		2.11		2,344	%
Oil including the effects of hedging (per Bbl)	$	66.97	$	74.40	$	(7.43)	(10)	%

NGL (per Bbl)	$	17.50	$	19.44	$	(1.94)	(10)	%

Natural gas (per Mcf)	$	0.52	$	(0.67)	$	1.19	178	%
Effect of derivative settlements on average price (per Mcf)	0.50		0.43		0.07		16	%
Effect of purchased gas sales on average price (per Mcf)	0.06		—		0.06		100	%
Natural gas including the effects of hedging (per Mcf)	$	1.08	$	(0.24)	$	1.32	550	%

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

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Oil and Gas Sales. Total net revenues for the three months ended September 30, 2025 were $106.2 million (or 9%) higher than total net revenues for the three months ended September 30, 2024. 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 16%, 23% and 17%, respectively, between periods. The increase in oil production resulted from additional production added from wells placed online or acquired since the third 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 23% and 17% increases in NGL and natural gas volumes between periods.

Total net revenues increases were also driven by higher average realized sales prices of natural gas, which increased 178% in the third quarter of 2025 compared to the same 2024 period. This increase was the result of significantly higher regional and national average index gas prices between periods.

These increases were partially offset by lower realized sales prices for oil and NGLs which decreased 13% and 10%, respectively, in the third quarter of 2025 compared to the same 2024 period. The 13% decrease in the average realized oil price was mainly the result of lower NYMEX crude prices between periods. The 10% decrease in the average realized NGL price between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the third quarter of 2025 compared to the same 2024 period.

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


	Three Months Ended September 30,						Increase/(Decrease)
	2025			2024			Change			%
Operating costs (in thousands):
Lease operating expenses	$	191,338		$	173,255		$	18,083		10	%
Severance and ad valorem taxes	101,481			91,548			9,933			11	%
Gathering, processing and transportation expenses	53,971			50,220			3,751			7	%
Operating cost metrics:
Lease operating expenses (per Boe)	$	5.07		$	5.43		$	(0.36)		(7)	%
Severance and ad valorem taxes (% of revenue)	7.7		%	7.5		%	0.2		%	3	%
Gathering, processing and transportation expenses (per Boe)	$	1.43		$	1.57		$	(0.14)		(9)	%

Lease Operating Expenses. Lease operating expenses (“LOE”) per Boe for the third quarter of 2025 decreased 7% to $5.07 from $5.43 during the third quarter of 2024. This decrease in our LOE per Boe rate was primarily driven by lower semi-variable well costs, including water disposal rates and wellhead chemicals that resulted from operational efficiencies. While LOE per Boe decreased period over period, total LOE for the three months ended September 30, 2025 increased $18.1 million compared to the three months ended September 30, 2024 as a direct result of our higher well count between periods primarily due to additional wells placed on production or acquired since September 30, 2024.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended September 30, 2025 increased $9.9 million compared to the three months ended September 30, 2024. Severance taxes are based on the market value of our oil and gas production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the third quarter of 2025 increased $10.6 million compared to the same 2024 period primarily due to (i) higher NGL and natural gas revenues between periods; and (ii) less tax credits received on wells designated “high cost gas” by the state of Texas during the third quarter of 2025 as compared to the same 2024 period. As a result, our severance and ad valorem taxes as a percentage of revenues also increased between periods from 7.5% for the three months ended September 30, 2024 to 7.7% for the three months ended September 30, 2025.

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Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) on a per Boe basis decreased from $1.57 for the three months ended September 30, 2024 to $1.43 for the three months ended September 30, 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 third quarter of 2024. While our GP&T per Boe was lower period versus period, total GP&T for the three months ended September 30, 2025 increased $3.8 million as compared to the three months ended September 30, 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:


	Three Months Ended September 30,
(in thousands, except per Boe data)	2025		2024
Depreciation, depletion and amortization	$	526,915	$	453,603
Depreciation, depletion and amortization per Boe	$	13.96	$	14.21

For the three months ended September 30, 2025, DD&A expense amounted to $526.9 million, an increase of $73.3 million over the same 2024 period. 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 $82.5 million, while our slightly lower DD&A rate of $13.96 per Boe decreased DD&A expense by $9.2 million between periods.

DD&A per Boe was $13.96 for the third quarter of 2025 as compared to $14.21 for the same period in 2024, a 2% decrease between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, and impairments, as well as changes in proved developed and proved undeveloped reserves.

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


	Three Months Ended September 30,
(in thousands)	2025		2024
Cash general and administrative expenses	$	32,528	$	30,246
Stock-based compensation	17,435		13,537
General and administrative expenses	$	49,963	$	43,783

Cash general and administrative expenses per Boe	$	0.86	$	0.95

G&A expenses for the three months ended September 30, 2025 were $50.0 million compared to $43.8 million for the three months ended September 30, 2024. Stock-based compensation increased $3.9 million between periods and was primarily related to additional grants of performance stock units (“PSUs”) and restricted stock since the third quarter of 2024. Cash G&A was $2.3 million higher between periods mainly related to increased employee expense and consulting and professional services due to our increased headcount and overall corporate growth.

While cash G&A expense increased between periods, on a per Boe basis our cash G&A rate decreased 9% from $0.95 per Boe during the three months ended September 30, 2024 to $0.86 per Boe during the three months ended September 30, 2025. This per Boe rate decrease was the result of focus on controlling costs and growing production.

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Other Income and Expenses.

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


	Three Months Ended September 30,
(in thousands)	2025		2024
Credit facility	$	2,406	$	4,015
5.375% Senior Notes due 2026	3,382		3,889
7.75% Senior Notes due 2026	—		2,390
8.00% Senior Notes due 2027	11,000		11,000
3.25% Convertible Senior Notes due 2028	(1,380)		1,381
5.875% Senior Notes due 2029	10,281		10,281
9.875% Senior Notes due 2031	8,023		12,344
7.00% Senior Notes due 2032	17,500		17,500
6.25% Senior Notes due 2033	15,625		9,722
Amortization of debt issuance costs, discount and premium	2,014		1,752
Other interest expense	535		550
Total	$	69,386	$	74,824

Interest expense decreased $5.4 million for the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily due to (i) $10.0 million less interest incurred on our senior notes that were fully or partially redeemed or repurchased; and (ii) $1.6 million 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 an additional $5.9 million in interest incurred during the 2025 period on our senior notes due 2033 (“2033 Senior Notes”) that were issued in July 2024.

Loss on extinguishment of debt. The loss on extinguishment of debt incurred during the three months ended September 30, 2025 of $264.3 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 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report for additional information regarding the Redemption.

During the three months ended September 30, 2024, we recognized $5.1 million of loss on extinguishment of debt related to the redemption of our 7.75% senior notes due 2026.

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:


	Three Months Ended September 30,
(in thousands)	2025		2024
Realized cash settlement gains (losses)	$	70,407	$	25,431
Non-cash mark-to-market derivative gain (loss)	35,307		213,102
Total	$	105,714	$	238,533

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


	Three Months Ended September 30,
(in thousands)	2025		2024
Income before income taxes	$	168,855	$	562,995
Income tax expense	(87,394)		(106,468)

Our provisions for income taxes for the three months ended September 30, 2025 and 2024 differ from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our non-controlling interest and which is therefore not taxable to the Company; (ii) other permanent differences; and (iii) state income taxes.

For the three months ended September 30, 2025, we generated pre-tax net income of $168.9 million and recorded income tax expense of $87.4 million. The primary factor increasing our income tax expense above the U.S. statutory rate was the tax impact associated with the Redemption of the Convertible Senior Notes, which was partially offset by the portion of the pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company. During the three months ended September 30, 2024, we generated pre-tax net income of $563.0 million and recorded income tax expense of $106.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company.

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Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024


	Nine Months Ended September 30,				Increase/(Decrease)
	2025		2024		$		%
Net revenues (in thousands):
Oil sales	$	3,231,068	$	3,265,303	$	(34,235)	(1)	%
NGL sales	513,426		460,701		52,725		11	%
Natural gas sales	145,686		(21,351)		167,037		782	%
Purchased gas sales, net	5,663		—		5,663		100	%
Oil and gas sales	$	3,895,843	$	3,704,653	$	191,190	5	%

Net production:
Oil (MBbls)	49,009		42,519		6,490		15	%
NGL (MBbls)	26,377		22,229		4,148		19	%
Natural gas (MMcf)	185,932		162,522		23,410		14	%
Total (MBoe)(1)	106,376		91,835		14,541		16	%

Average daily net production:
Oil (Bbls/d)	179,523		155,180		24,343		16	%
NGLs (Bbls/d)	96,618		81,129		15,489		19	%
Natural gas (Mcf/d)	681,071		593,144		87,927		15	%
Total (Boe/d)(1)	389,653		335,166		54,487		16	%

Average sales prices:
Oil (per Bbl)	$	65.93	$	76.80	$	(10.87)	(14)	%
Effect of derivative settlements on average price (per Bbl)	1.94		(0.37)		2.31		624	%
Oil including the effect of hedging (per Bbl)	$	67.87	$	76.43	$	(8.56)	(11)	%

NGL (per Bbl)	$	19.46	$	20.73	$	(1.27)	(6)	%

Natural gas (per Mcf)	$	0.78	$	(0.13)	$	0.91	700	%
Effect of derivative settlements on average price (per Mcf)	0.28		0.34		(0.06)		(18)	%
Effect of purchased gas sales on average price (per Mcf)	0.03		—		0.03		100	%
Natural gas including the effects of hedging (per Mcf)	$	1.09	$	0.21	$	0.88	419	%

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

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Oil and Gas Sales. Total net revenues for the nine months ended September 30, 2025 were $191.2 million, or 5%, higher than total net revenues for the nine months ended September 30, 2024. 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 15%, 19%, and 14%, respectively, between periods. The increase in oil production resulted from additional production added from wells placed online or acquired since the third 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 19% and 14% increases in NGL and natural gas volumes between periods.

Total net revenue increases were also driven by higher average realized sales prices of natural gas, which increased 700% in the first nine months of 2025 compared to the same 2024 period. This increase was the result of higher regional and national average index gas prices between periods.

These increases were partially offset by decreases in the average realized sales prices for oil and NGLs, which decreased 14% and 6%, respectively, in the first nine months of 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 6% decrease in the average realized NGL price between periods was primarily attributable to lower Mont Belvieu spot prices for plant products for the first nine months of 2025 compared to the same 2024 period.

Operating Expenses. The following table summarizes our operating expenses for the periods indicated:


	Nine Months Ended September 30,						Increase/(Decrease)
	2025			2024			Change			%
Operating costs (in thousands):
Lease operating expenses	$	558,937		$	501,597		$	57,340		11	%
Severance and ad valorem taxes	304,404			280,784			23,620			8	%
Gathering, processing and transportation expenses	156,375			133,020			23,355			18	%
Operating cost metrics:
Lease operating expenses (per Boe)	$	5.25		$	5.46		$	(0.21)		(4)	%
Severance and ad valorem taxes (% of revenue)	7.8		%	7.6		%	0.2		%	3	%
Gathering, processing and transportation expenses (per Boe)	$	1.47		$	1.45		$	0.02		1	%

Lease Operating Expenses. LOE per Boe for the nine months ended September 30, 2024 was $5.25, which represents a 4% decrease compared to the same 2024 period. This decrease in our LOE per Boe rate was primarily driven by lower semi-variable well costs, including lower water disposal rates and wellhead chemicals that resulted from operational efficiencies. While LOE per Boe decreased period over period, total LOE for the nine months ended September 30, 2025 increased by $57.3 million compared to the nine months ended September 30, 2024 and was the direct result of our higher well count between periods primarily due to additional wells placed on production or acquired since September 30, 2024.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the nine months ended September 30, 2025 increased $23.6 million compared to the nine months ended September 30, 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. Severance taxes for the first nine months of 2025 increased $24.3 million compared to the same 2024 period primarily due to (i) higher NGL and natural gas revenues between periods; and (ii) less tax credits received on wells designated “high cost gas” by the state of Texas. As a result, our severance and ad valorem taxes as a percentage of revenues also increased between periods from 7.6% for the nine months ended September 30, 2024 to 7.8% for the nine months ended September 30, 2025.

Gathering, Processing and Transportation Expenses. GP&T on a per Boe basis remained relatively consistent increasing from $1.45 for the first nine months of 2024 to $1.47 for the first nine months of 2025. Total GP&T for the nine months ended September 30, 2025 increased $23.4 million compared to the nine months ended September 30, 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.

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Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:


	Nine Months Ended September 30,
(in thousands, except per Boe data)	2025		2024
Depreciation, depletion and amortization	$	1,507,528	$	1,290,210
Depreciation, depletion and amortization per Boe	$	14.17	$	14.05

For the nine months ended September 30, 2025, DD&A expense amounted to $1.5 billion, an increase of $217.3 million over the same 2024 period. 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 $204.3 million during the first nine months of 2025, while slightly higher DD&A rates between periods increased DD&A expense by $13.0 million for the nine months ended September 30, 2025.

DD&A per Boe was $14.17 for the nine months ended September 30, 2025 as compared to $14.05 for the same period in 2024, a 1% increase between periods. 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.

General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:


	Nine Months Ended September 30,
(in thousands)	2025		2024
Cash general and administrative expenses	$	89,931	$	84,791
Stock-based compensation expense	52,927		45,094
General and administrative expenses	$	142,858	$	129,885

Cash general and administrative expenses per Boe	$	0.85	$	0.92

G&A expenses for the nine months ended September 30, 2025 were $142.9 million compared to $129.9 million for the nine months ended September 30, 2024. Stock-based compensation increased $7.8 million primarily related to (i) additional grants of PSUs and restricted stock since the third quarter of 2024; and (ii) the modification of the Co-CEO’s PSUs that resulted in more accelerated expense period over period. This was partially offset by less expense associated with accelerated vestings of equity awards that occurred during the first nine months of 2024 that did not reoccur during the same 2025 period. Cash G&A was $5.1 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 expense increased between periods, on a per Boe basis our cash G&A rate decreased 8% from $0.92 per Boe during the nine months ended September 30, 2024 to $0.85 per Boe during the nine months ended September 30, 2025. This per Boe rate decrease was the result of focus on controlling costs and growing production.

Other Income and Expenses.

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


	Nine Months Ended September 30,
(in thousands)	2025		2024
Credit facility	$	7,138	$	13,657
5.375% Senior Notes due 2026	11,153		11,667
7.75% Senior Notes due 2026	—		14,016
6.875% Senior Notes due 2027	—		6,397
8.00% Senior Notes due 2027	33,000		33,000
3.25% Convertible Senior Notes due 2028	1,382		4,143
5.875% Senior Notes due 2029	30,843		30,843
9.875% Senior Notes due 2031	25,174		37,032
7.00% Senior Notes due 2032	52,500		52,500
6.25% Senior Notes due 2033	46,875		9,722
Amortization of debt issuance costs, discount and premium	6,313		4,752
Other interest expense	1,617		1,659
Total	$	215,995	$	219,388

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Interest expense was $3.4 million lower for the nine months ended September 30, 2025 compared to the same 2024 period mainly due to (i) $35.5 million less interest incurred on our senior notes that were fully or partially redeemed or repurchased; and (ii) $6.5 million 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 a $37.2 million increase in interest incurred on our 2033 Senior Notes that were issued in July 2024.

Loss on extinguishment of debt. The loss on extinguishment of debt incurred during the nine months ended September 30, 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 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report for additional information regarding the Redemption.

During the nine months ended September 30, 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:


	Nine Months Ended September 30,
(in thousands)	2025		2024
Realized cash settlement gains (losses)	$	147,478	$	40,340
Non-cash mark-to-market derivative gain (loss)	88,986		91,362
Total	$	236,464	$	131,702

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


	Nine Months Ended September 30,
(in thousands)	2025		2024
Income before income taxes	$	967,259	$	1,232,727
Income tax expense	(250,214)		(237,697)

Our provisions for income taxes for the first nine months of 2025 and 2024 differ from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our non-controlling interest and which is therefore not taxable to the Company; (ii) other permanent differences; and (iii) state income taxes.

For the nine months ended September 30, 2025 we generated pre-tax net income of $967.3 million and recorded income tax expense of $250.2 million. The primary factor increasing our income tax expense above the U.S. statutory rate was the tax impact associated with the Redemption of the Convertible Senior Notes, which was partially offset by the portion of the pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company. During the nine months ended September 30, 2024, we generated pre-tax net income of $1.2 billion and recorded income tax expense of $237.7 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company.

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Liquidity and Capital Resources

Overview

Our drilling and completion activities require us to make significant capital expenditures. Historically, 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. During the nine months ended September 30, 2025 our total development capital expenditures were $1.5 billion. We expect our total drilling, completion and facilities capital expenditures for 2025 to be between $1.92 billion to $2.02 billion. We funded our capital expenditures for the nine months ended September 30, 2025 entirely from cash flows from operations, and we expect to fund the remainder of our 2025 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 nine months ended September 30, 2025, we declared and paid quarterly base dividends totaling $0.45 per share of Class A Common Stock and distributions totaling $0.45 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 $366.8 million for the nine months ended September 30, 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 stock repurchase program during the nine months ended September 30, 2025.

Our stock 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 nine months ended September 30, 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 5.375% 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 Quarterly Report and the long-term.

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Analysis of Cash Flow Changes

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


	Nine Months Ended September 30,
(in thousands)	2025		2024
Net cash provided by operating activities	$	2,703,214	$	2,540,390
Net cash used in investing activities	(2,147,414)		(2,563,819)
Net cash used in financing activities	(923,338)		222,196

For the nine months ended September 30, 2025, we generated $2.7 billion of cash from operating activities, an increase of $162.8 million from the same period in 2024. Cash provided by operating activities increased primarily due to higher production volumes, realized derivative gains, realized prices for gas and lower merger and integration expense as well as the timing of payments to our suppliers during the nine months ended September 30, 2025 as compared to the same 2024 period. These increasing factors were partially offset by lower realized prices for oil and NGLs, higher lease operating expenses, severance and ad valorem taxes, and GP&T as well as the timing of our collections on our receivables during the nine months ended September 30, 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 costs between periods.

During the nine months ended September 30, 2025, cash flows from operating activities, cash on hand and proceeds of $179.6 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 $1.5 billion of drilling and development cash capital expenditures; (ii) fund acquisitions of oil and gas properties of $830.3 million; (iii) redeem $464.5 million of our senior notes; (iv) pay $366.8 million in dividends and cash distributions to our shareholders and holders of our Common Units; and (v) repurchase $73.7 million of our Class A and C Common Stock.

During the nine months ended September 30, 2024, cash flows from operating activities, proceeds from the issuance of our 2033 Senior Notes and proceeds from an underwritten public offering of 26.5 million Class A Common Stock were used to (i) fund $1.6 billion of drilling and development cash capital expenditures; (ii) fund acquisitions of oil and gas properties of $1.0 billion; (iii) redeem $656.4 million of our senior notes; (iv) pay $440.3 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 September 30, 2025, had a borrowing base of $4.0 billion and elected commitments of $2.5 billion. As of September 30, 2025, we had no borrowings outstanding and $2.5 billion in available borrowing capacity, which was net of $2.5 million in letters of credit outstanding. The elected commitments and borrowing base were reaffirmed during the spring and fall 2025 borrowing base redeterminations.

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

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 the applicable financial ratios described above as of September 30, 2025 and through the filing of this Quarterly Report.

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Senior Notes

OpCo has $3.5 billion in debt outstanding as of September 30, 2025, consisting of senior unsecured notes with maturity dates ranging from 2027 to 2033. For further information on our debt instruments, refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report.

Contractual Obligations

Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify or extend. Since December 31, 2024, there have not been any significant, non-routine changes in our contractual obligations other than (i) a drilling rig contract entered into and (ii) a series of firm transportation agreements that guarantee volumetric capacity on pipelines for gas transportation entered into as discussed in Note 1—Basis of Presentation and Summary of Significant Accounting Policies and Note 11—Commitments and Contingencies, respectively, under Part I, Item 1 of this Quarterly Report.

Critical Accounting Policies and Estimates

There have been no material changes to the critical accounting policies as disclosed in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 2024 Annual Report.

New Accounting Pronouncements

Refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1 of this Quarterly Report for a discussion of recently adopted accounting standards and the potential effects of new accounting pronouncements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Pricing for oil, NGLs and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Based on our production for the first nine months of 2025, our oil and gas sales for the nine months ended September 30, 2025, would have moved up or down $323.1 million for each 10% change in oil prices per Bbl, $51.3 million for each 10% change in NGL prices per Bbl, and $14.6 million for each 10% change in natural gas prices per Mcf.

Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps, puts and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.

The table below summarizes the terms of the derivative contracts we had in place as of September 30, 2025 and additional contracts entered into through October 31, 2025. Refer to Note 7—Derivative Instruments in Part I, Item 1 of this Quarterly Report for open derivative positions as of September 30, 2025.


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Crude Price ($/Bbl)
Crude oil swaps - NYMEX WTI	October 2025 - December 2025	5,244,000	57,000	$70.99
	January 2026 - March 2026	2,655,000	29,500	69.71
	April 2026 - June 2026	2,684,500	29,500	68.85
	July 2026 - September 2026	2,714,000

Permian Resources Corp 10-Q