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☑ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2023

or

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

Commission file number 001-37697

(Exact name of registrant as specified in its charter)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, par value $0.0001 per share

PR

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes ☐ No ☒

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 the filing requirements for the past 90 days.  Yes ☒ No ☐

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2,940,481,909 based on the closing price of the shares of common stock on that date. While shares of Class C Common Stock are not listed for public trading, they are exchangeable for shares of Class A Common Stock at any time on a share-for-share basis, and the calculation of aggregate market value assumes all outstanding shares of Class C Common Stock were exchanged for Class A Common Stock as of June 30, 2023.

As of February 23, 2024, there were 540,951,732 shares of Class A Common Stock, par value $0.0001 per share outstanding and 230,910,435 shares of Class C Common Stock , par value $0.0001 per share, outstanding.

Portions of the registrant’s definitive proxy statement for its 2024 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2023, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, 2023.

The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K, 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, condensate or NGLs.

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.

ICE Brent. Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).

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

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.

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.

Proved reserves. The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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 cash market price less 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 shares 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.

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.

This Annual Report on Form 10-K (the “Annual 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 Annual 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 Annual 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 in Item 1A. Risk Factors in this Annual Report.

Forward-looking statements may include statements about:

•volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL 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;

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

•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, natural gas and NGL prices; 

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

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

•our ability to realize the anticipated benefits and synergies from the Earthstone Merger and effectively integrate the acquired assets (as defined below);

•our hedging strategy and results; 

•our competition and government regulations; 

•our ability to obtain permits and governmental approvals; 

•our pending legal or environmental matters; 

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

•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 Annual Report that are not historical.

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 development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, risks relating to the merger of the Company with Earthstone Energy, Inc (the “Earthstone Merger”), environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in Item 1A.

Risk Factors in this 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.

Should one or more of the risks or uncertainties described in this Annual Report occur, or 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 Annual 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 Annual Report.

The following is a summary of the principal risks that could materially adversely affect our business, financial condition and results of operations. Refer to Risk Factors under Part I, Item 1A of this Annual Report for a more detailed description of each risk factor.

•Commodity prices are volatile, and a sustained period of low commodity prices for oil, natural gas and NGLs could adversely affect our business, financial condition and results of operations.

•If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.

•Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

•Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

•The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

•Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

•Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

•Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

•Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

•Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

•Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

•Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

•Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

•Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to recycle or dispose of the produced water we produce in an economical and environmentally safe manner.

•Our producing properties are concentrated in the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.

•The marketability of our production is dependent upon transportation and other facilities, most of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.

•We have entered into multi-year agreements with some of our suppliers, service providers and the purchasers of our oil and natural gas, which contain minimum volume commitments. Any failure by us to satisfy the minimum volume commitments could lead to contractual penalties that could adversely affect our results of operations and financial position.

•The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

•We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

•We depend upon a small number of significant purchasers for the sale of most of our oil, natural gas and NGL production.

•We may incur losses as a result of title defects in the properties in which we invest.

•Multi-well pad drilling may result in volatility in our operating results.

•We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

•A security interruption or failure with respect to our information technology systems could harm our ability to effectively operate our business.

•Our derivative activities could result in financial losses or could reduce our earnings.

•Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on our outstanding debt.

•We may not be able to generate sufficient cash to service all of OpCo’s indebtedness and may be forced to take other actions to satisfy OpCo’s obligations under applicable debt instruments, which may not be successful.

•Restrictions in OpCo’s existing and future debt agreements could limit our growth and ability to engage in certain activities.

•If OpCo is unable to comply with the restrictions and covenants in the agreements governing its indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that OpCo has borrowed.

•Any significant reduction in the borrowing base under OpCo’s revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

•If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

•Increases in interest rates could adversely affect our business.

•Climate change laws and regulations restricting emissions of GHGs could increase our costs and reduce demand for the oil and natural gas we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

•Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

•Conservation measures, technological advances and negative shift in market perception toward the oil and natural gas industry could reduce demand for oil and natural gas.

•Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

•Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

•A negative shift in investor sentiment towards the oil and natural gas industry and increased attention to environmental, social and governance (“ESG”) and conservation matters may adversely impact our business.

•Any restrictions on oil and natural gas development on federal lands has the potential to adversely impact our operations.

•Tax laws and regulations may change over time, and any such changes could adversely affect our business and financial condition.

•Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.

•A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.

•Our principal stockholders hold substantial voting power of our outstanding voting common stock.

•There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.

•The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.

•Provisions contained in our Charter and Bylaws, as well as provisions of Delaware law, could impair a takeover attempt, which may adversely affect the market price of our common stock.

•The Charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for substantially all actions and proceedings that may be initiated by stockholders, which could limit shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

•We may be unable to integrate the business of the Company and Earthstone successfully or realize the anticipated benefits of the Earthstone Merger.

•The financial forecasts disclosed in connection with the announcement of the Earthstone Merger are based on various assumptions that may not be realized.

•The synergies attributable to the Earthstone Merger may vary from expectations.

Permian Resources Corporation is an independent oil and natural gas company focused on driving sustainable returns through the responsible acquisition, optimization and development of high-return crude oil and associated liquids-rich natural gas reserves. Throughout this Annual Report, unless the context otherwise indicates, all references to the “Company,” “Permian Resources,” “we,” “us,” or “our” refer to Permian Resources Corporation and its consolidated subsidiary, Permian Resources Operating, LLC (“OpCo”).

Our principal business objective is to deliver leading shareholder returns by leveraging our high-quality asset base and technical expertise to sustainably and responsibly develop our oil and natural gas resources to meet the world’s need for affordable, abundant energy. We intend to drive disciplined production growth through optimized development of our assets with the overall objective of improving our rates of return, generating sustainable free cash flow, maintaining a strong and flexible balance sheet and maximizing returns to our shareholders. We also look for opportunities to optimize our portfolio of high-return, long-life inventory through accretive acquisitions that meet our strategic and financial objectives.

On November 1, 2023, we completed the merger (the “Earthstone Merger”) with Earthstone Energy, Inc. (“Earthstone”). Earthstone was an independent oil and gas company engaged in the operation and development of oil and natural gas properties. The Earthstone Merger added approximately 223,000 net leasehold acres and significant core inventory locations to our position in the Permian Basin in both Texas and New Mexico and was completed to drive long-term accretion across our key financial and operating metrics, enhance shareholder returns and improve capital efficiency. As a part of the Earthstone Merger consideration, approximately 161.2 million shares of our Class A Common Stock and 49.5 million shares of our Class C Common Stock (with underlying units of OpCo) were issued to Earthstone’s equity holders. Certain operational and financial information set forth in this Annual Report on Form 10-K does not include the activity of Earthstone for periods prior to the completion of the Earthstone Merger on November 1, 2023.

On September 1, 2022, we completed the merger (the “Colgate Merger”) with Colgate Energy Partners III, LLC (“Colgate”). Colgate was an independent oil and gas exploration and development company with properties located in the Delaware Basin. The Colgate Merger was completed to provide increases to our operational and financial scale, drive accretion across our key financial and operating metrics, and enhance the combined company’s shareholder returns. As a part of the Merger consideration, 269.3 million shares of our Class C Common Stock and underlying units of OpCo were issued to Colgate’s equity holders. Certain operational and financial information set forth in this Annual Report on Form 10-K does not include the activity of Colgate for periods prior to the completion of the Colgate Merger on September 1, 2022.

Refer to Note 2—Business Combinations under Part II, Item 8 of this Annual Report for further information regarding the mergers.

Our assets are concentrated in the core of the Permian Basin and consist of large, contiguous acreage blocks in West Texas and New Mexico. As of December 31, 2023, we have approximately 407,000 net leasehold acres and approximately 68,000 net royalty acres. Approximately 70% of our total acreage is located in Texas and the remaining 30% is located in New Mexico.

Reserve estimates are inherently imprecise, and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The pre-tax PV 10% amounts shown in the following table are not intended to represent the current market value of our estimated proved reserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated, due to a number of factors. The following table should be read along with Item 1A. Risk Factors in this Annual Report.

The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows for the periods indicated:

			December 31, 2023						December 31, 2022						December 31, 2021
Proved developed reserves:
Oil (MBbls)			271,328						156,941						77,973
Natural gas (MMcf)			1,441,914						652,270						326,223
NGL (MBbls)			192,368						74,940						30,318
Total proved developed reserves (MBoe)(1)			704,015						340,593						162,662
Proved undeveloped reserves:
Oil (MBbls)			122,008						130,091						75,480
Natural gas (MMcf)			324,176						381,301						250,782
NGL (MBbls)			45,046						47,911						25,265
Total proved undeveloped reserves (MBoe)(1)			221,083						241,553						142,542
Total proved reserves:
Oil (MBbls)			393,336						287,032						153,453
Natural gas (MMcf)			1,766,090						1,033,571						577,005
NGL (MBbls)			237,414						122,851						55,583
Total proved reserves (MBoe)(1)			925,098						582,146						305,204
Proved developed reserves %			76		%				59		%				53		%
Proved undeveloped reserves %			24		%				41		%				47		%
Reserve values (in millions):
Standard measure of discounted future net cash flows			$	9,526.2					$	9,425.6					$	3,396.3
Discounted future income tax expense			1,581.5						2,289.1						481.2
Total proved pre-tax PV 10%(2)			$	11,107.7					$	11,714.7					$	3,877.5

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

(2)    Total proved pre-tax PV 10% (“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure as defined by the U.S. Securities and Exchange Commission (“SEC”) and is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable U.S. generally accepted accounting principles (“GAAP”) financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.

Proved Undeveloped Reserves. Our proved undeveloped (“PUD”) reserves decreased by 20.5 MMBoe on a net basis from December 31, 2022 to December 31, 2023, and the following table provides a reconciliation of the changes to our PUD reserves that occurred during the year:

(MBoe)			2023
Proved undeveloped reserves at January 1, 2023			241,553
Transfers to proved developed reserves			(91,234)
Revisions to previous estimates			(34,872)
Extensions and discoveries			47,947
Purchase of reserves in place			57,689
Proved undeveloped reserves at December 31, 2023			221,083

The decrease in proved undeveloped reserves was primarily attributable to converting 91.2 MMBoe of PUD reserves to proved developed reserves during 2023, for which we spent $870.6 million in capital expenditures. Additionally, total revisions to previous estimates reduced PUD reserves by a net amount of 34.9 MMBoe. Negative revisions during 2023 mainly related to (i) 22.3 MMBoe of PUD locations that were mainly reclassified to unproved reserves due to changes made to our development plan (ii) 7.6 MMBoe of downward revisions related to lowered estimates associated with timing and performance, and (iii) 5.0 MMBoe of reduced PUD reserves from lower average commodity prices for the year ended 2023. These decreases in proved undeveloped reserves were partially offset by adding 57.7 MMBoe of PUD reserves, the significant majority of which were from properties acquired in the Earthstone Merger on November 1, 2023 (Refer to Note 2—Business Combinations under Part II, Item 8 of this Annual Report for further details on the Earthstone Merger). Additionally, we added 47.9 MMBoe of PUD reserves during the year through extensions and discoveries as a result of our 2023 drilling results, which mainly related to new locations added in the various Bone Spring and Wolfcamp formations on the Company’s acreage position in the Delaware Basin. All of our PUD locations are scheduled to be drilled within five years of their initial booking. Our PUD to proved developed reserves conversion rate was 38% in 2023.

    For additional information and for a discussion of material changes on our total proved reserves, see Supplemental Information About Oil & Natural Gas Producing Activities, Item 8. Financial Statements and Supplementary Data of this Annual Report.

Our proved reserves are estimated by an independent engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Reserve estimates are prepared in accordance with the definitions and regulations of the SEC and the Financial Accounting Standards Board (the “FASB”) using a deterministic method, which includes decline curve analysis, production performance analysis, offset analogies, and in some cases a combination of these methodologies.

We maintain adequate and effective internal controls over the reserve estimation process and the underlying data which the reserve estimates are based upon. Our reserves estimation process is coordinated by our internal reserves department, which consists of qualified petroleum engineers and is overseen by our Corporate Reserves Manager. Reserve information, including models and other technical data, are stored on a secured database on our network. Certain non-technical inputs used in the reserves estimation process such as ownership interest percentages, oil and natural gas production, commodity prices, price differentials, operating and development costs and plug and abandonment estimates are obtained by other departments. Annually, our internal reserves department prepares a preliminary reserve database and meets with NSAI to discuss the assumptions and methods to be used in the year-end proved reserve estimation process and to review field performance and our future development plans. Following this review, the reserve database and supporting data is furnished to NSAI for their independent estimates and final report.

Our Corporate Reserves Manager, Joseph Jones, is responsible for overseeing the preparation of the reserves estimates. Mr. Jones has held this position at Permian Resources since September 2022 after formerly serving in a similar role for Colgate prior to the Colgate Merger and has over 10 years of relevant experience in reservoir engineering and reserve estimation. He holds a Bachelor of Science degree in petroleum engineering from Texas A&M University.

NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Ms. Lily W. Cheung and Mr. Zachary R. Long. Ms. Cheung, a Licensed Professional Engineer in the State of Texas (No. 107207), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 4 years of prior industry experience. She graduated from Massachusetts Institute of Technology in 2003 with a Bachelor of Science Degree in Mechanical Engineering and from University of Texas at Austin in 2007 with a Master of Business Administration Degree.

Mr. Long, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11792), has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from University of Louisiana at Lafayette in 2003 with a Bachelor of Science Degree in Petroleum Geology and from Texas A&M University in 2005 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

			Year Ended December 31,
			2023						2022						2021
Net production:
Oil (MBbls)			35,560						18,235						11,701
Natural gas (MMcf)			119,182						59,692						40,741
NGL (MBbls)			15,569						6,750						3,752
Total (MBoe)(1)			70,992						34,934						22,243
Average sales price (excluding effect of hedges):
Oil (per Bbl)			$	75.84					$	88.95					$	63.50
Natural gas price excluding the effects of GP&T (per Mcf)(2)			1.60						4.86						3.67
NGL price excluding the effects of GP&T (per Bbl)(3)			22.83						35.97						36.61
Total per Boe(1)			$	45.68					$	61.69					$	46.30
Operating costs per Boe:
Lease operating expenses			$	5.26					$	4.92					$	4.78
Severance and ad valorem taxes			3.39						4.46						3.02
Gathering, processing and transportation expenses			1.26						2.80						3.86

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

(2)    Natural gas average sales price excludes $0.41 per Mcf of gathering, processing and transportation costs (“GP&T”) for the year ended December 31, 2023, $0.22 for the year ended December 31, 2022 and none for the year ended December 31, 2021.

(3)    NGL average sales price excludes $4.71 per Bbl of GP&T charges for the year ended December 31, 2023, $1.56 per Bbl for the year ended December 31, 2022 and none for the year ended December 31, 2021.

As of December 31, 2023, we owned an approximate 83% average working interest in 2,577 gross (2,143 net) operated productive wells and an approximate 11% average working interest in 1,094 gross (120 net) non-operated productive wells. Our wells are primarily oil wells (3,150 gross, 2,018 net productive oil wells) that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information as of December 31, 2023 relating to our gross and net developed and undeveloped leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Developed Acreage												Undeveloped Acreage												Total Acreage
Gross(1)						Net(2)						Gross(1)						Net(2)						Gross(1)						Net(2)
433,957						345,390						109,534						61,663						543,491						407,053

(1)    A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(2)    A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2023, that will expire over the next five years unless production is established within the spacing units covering the acreage, the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, or pursuant to other terms of the lease agreements.

2024												2025												2026												2027												2028
Gross						Net						Gross						Net						Gross						Net						Gross						Net						Gross						Net
1,620						766						1,519						930						3,402						1,700						1,120						533						213						200

The following table sets forth the results of our drilling activity, as defined by wells placed on production, for the periods indicated. Productive wells are exploratory, development or extension wells that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are exploratory, development or extension wells that prove to be incapable of producing hydrocarbons in sufficient quantities to justify incurring the costs associated with completion as an oil or gas well.

			Year Ended December 31,
			2023												2022												2021
			Gross						Net						Gross						Net						Gross						Net
Development Wells:
Productive			183						150.2						95						84.9						42						38.0
Dry(1)			2						1.8						3						2.8						—						—
			185						152.0						98						87.7						42						38.0
Exploratory Wells:
Productive			—						—						—						—						—						—
Dry			—						—						—						—						—						—
			—						—						—						—						—						—
Total			185						152.0						98						87.7						42						38.0

(1)    The developmental dry hole category includes wells that were unsuccessful due to mechanical issues that occurred during drilling.

As of December 31, 2023, we had 23 gross (19.5 net) operated wells in the process of drilling and 45 gross (36.3 net) operated wells in the process of completion or waiting on completion.

The table below summarizes our firm sales agreements for crude oil, which provides for gross firm sales over the contractual term:

						Oil Volume Commitments(1)
Period						Total (Bbl)						Daily (Bbls/d)
2024						10,610,000						29,000
2025						4,380,000						29,000
Total						14,990,000

(1) Above volumes represent the total gross volumes we are required to deliver pursuant to agreements with carriers, which gross volumes are not comparable to our net production presented in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Annual Report, as amounts therein are reflected net of all royalties, overriding royalties and production due to others.

These total oil volumes committed are subject to financial ship-or-pay penalties if such physical delivery commitments are not met. We believe our current production and reserves are sufficient to fulfill these physical delivery commitments, and production under the agreements is not tied to any specific property. Therefore, if our production is not sufficient to satisfy the firm delivery commitments above, we believe we can purchase sufficient volumes in the market at index-related prices to satisfy our commitments.

We believe that we have satisfactory title to substantially all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.

We market the majority of the production from properties we operate on account of both ourselves and that of the other working interest owners in these properties. We generally sell our oil, natural gas and NGL production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, and the majority of our revenue contracts have terms greater than twelve months.

We normally sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total net revenues for the periods presented:

			Year Ended December 31,
			2023						2022						2021
BP America			20		%				34		%				50		%
Shell Trading (US) Company			20		%				21		%				22		%
Enterprise Crude Oil, LLC			30		%				18		%				—		%
Kinetik Holdings Inc.			5		%				8		%				11		%

During these periods, no other purchaser accounted for 10% or more of our net revenues. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term. However, since crude oil and natural gas are fungible products with well-established markets and numerous purchasers and are based on current demand for oil and natural gas, we believe that the loss of any major purchaser would not have a material adverse effect on our financial condition or results of operations.

The oil and natural gas industry is a highly competitive environment. We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business including exploring, developing and operating our properties as well as transporting and marketing our production. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect the supply and demand for oil and natural gas production, such as price fluctuations (including basis differentials), domestic and foreign political conditions, weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. The majority of our oil production is sold at the wellhead as it enters third-party gathering pipelines. The purchaser then transports the oil by pipeline or truck to a tank farm, another pipeline or a refinery. Our natural gas is either transported by gathering lines from the wellhead to a central delivery point and is then gathered by third-party lines to a gas processing facility or gathered by a third-party directly from the wellhead.

Our operations are subject to extensive federal, state and local laws and regulations. All of the jurisdictions in which we own or operate producing properties have statutory provisions regulating the development and production of oil and natural gas, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations including, but not limited to, the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings affecting the oil and natural gas industry are regularly considered by Congress, the states, regulatory authorities, including the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental, health or safety incidents may occur or past non-compliance with environmental, health and safety laws or regulations may be discovered. In addition, governmental, scientific, and public concern over the threat of climate change arising from increasing global greenhouse gas (“GHG”) emissions has resulted in higher political and regulatory risks in the United States, including climate change related pledges made by certain administrations. President Biden has issued several executive orders focused on addressing climate change since taking office, which may impact the costs to produce, or demand for, oil and natural gas. Additionally, in November 2021, the Biden administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. The Biden administration has also proposed certain changes to the leasing and permitting programs for oil and natural gas development on federal lands, including imposing bans on new oil and gas leasing, cancelling issued oil and gas leases, and removing public lands from future oil and gas leasing.

The production of oil, natural gas and NGLs is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in New Mexico and Texas, which regulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of New Mexico and Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, natural gas and NGLs that we can produce from our wells and to limit the number of wells or the locations where we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, New Mexico and Texas impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdiction.

Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, and as a result we do not expect compliance with such regulatory requirements to affect our operations in any way that is of material difference from our competitors who are similarly situated.

However, the failure to comply with these rules and regulations can result in substantial penalties.

Sales of oil, condensate and NGLs from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

Sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipeline systems to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil producers and marketers with which we compete.

Historically, the transportation and sale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (the “NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The federal Energy Policy Act of 2005 (the “EP Act of 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. Such maximum civil penalty authority under the NGA and NGPA has been increased to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of $1,388,496 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and those enforced by the US Commodity Futures Trading Commission (the “CFTC”) under the Commodity Exchange Act, as amended (the “CEA”) and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market for financial instruments on such commodity, such as futures, options and swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states. Section 1(b) of the NGA exempts companies that provide natural gas gathering services from regulation by FERC as a “natural gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, or vice versa, and depending on the scope of that decision, our costs of delivering gas to point-of-sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Our operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, and protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costly investigation or actions. These laws and regulations may, among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and nonhazardous solid wastes. Pursuant to rules issued by the EPA, states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future.

For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes, or to sign a determination that revision of the regulations is not necessary. After undertaking its review, the EPA concluded in 2019 that it does not need to regulate exploration and production waste, and specifically “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy.” The EPA concluded that states are adequately regulating exploration and production waste under the Subtitle D provisions of RCRA. However, any such change in the future could result in an increase in our, as well as the oil, natural gas and NGL exploration and production industry’s, costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or the legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment, and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We may generate materials in the course of our operations that may be regulated as hazardous substances.

We currently own, lease or operate numerous properties that have been used for oil, natural gas and NGL exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers (the “Corps”) have issued rules attempting to clarify the federal jurisdictional reach over Waters of the United States since 2015 (“WOTUS rule”), including the Navigable Waters Protection Rule during the Trump administration, rules reverting back to the 1986 WOTUS definition during the Biden administration, and rules reinstating the pre-2015 definition in January 2023. However, in May 2023, the Supreme Court decided Sackett v. EPA, which sharply curtailed the EPA’s and Corps’ jurisdictional reach by limiting the types of wetlands that fell under WOTUS. Sackett codified the definition of WOTUS as only “geographical features” that are described in ordinary parlance as “streams, oceans, rivers, and lakes” and to adjacent wetlands that are “indistinguishable” from those bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water.

The final rule is currently subject to challenges in federal district courts. As such, uncertainty remains with respect to future implementation of the rule and any resulting litigation.

The process for obtaining permits under the CWA also has the potential to impact our operations. In April 2020, the U.S. District Court for the District of Montana vacated Nationwide Permit (“NWP”) 12, the general permit issued by the U.S. Army Corps of Engineers for pipelines and utility projects. In May 2020, the court narrowed its ruling, vacating and enjoining the use of NWP 12 only as it relates to construction of new oil and gas pipelines. The U.S. Army Corps of Engineers appealed the decision to the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”). In July 2020, the U.S. Supreme Court stayed the lower court order except as it applies to the Keystone XL pipeline. In January 2021, the U.S. Army Corps of Engineers released the final version of a rule renewing twelve of its NWPs, including NWP 12. The new rule splits NWP 12 into three parts; NWP 12 will continue to be available to oil and gas pipelines, while new NWP 57 will be available for electric utility line and telecommunications activities, and a new NWP 58 will be available for utility line activities for water and other substances. The new rule also eliminates preconstruction notice requirements for NWP 12 for several conditions that used to require such notice, but also now requires new oil and gas pipeline projects that exceed 250 miles in length to give preconstruction notice and obtain approval before proceeding. As a result of the U.S. Army Corps of Engineer’s new NWP 12, the Ninth Circuit in August 2021 ruled that the appeal of the superseded NWP 12 was moot, and remanded the case back to the District Court. On March 28, 2022, the Corps published a notice announcing that it is undertaking formal review of NWP 12 and sought public comments through May 27, 2022. We cannot predict at this time whether and, if so, how the new rule will be implemented, because permits are issued by the local U.S. Army Corps of Engineers district offices. Moreover, in January 2021, the Biden administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. If new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of CWA compliance, such projects could be significantly delayed, which could have an adverse impact on our operations.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below-ground disposal wells used for the injection of natural gas- and oil-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. The Railroad Commission of Texas (the “TRRC”) issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. As of May 1, 2023, operators in the Midland area began to implement the Operator Response Plan for the Gardendale Seismic Response Area (“SRA”), revised August 18, 2023, to prevent the occurrence of seismic events at or above magnitude 3.5 within the Gardendale SRA. Similar response plans have been developed for other SRAs in Texas. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other fluids may increase our costs or have other adverse impacts on our operations. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability; however, these costs are commonly incurred by all oil, natural gas and NGL producers, and we do not believe that the costs associated with the disposal of produced water will affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector. For example, the EPA promulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”), and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Emissions Standards for Hazardous Air Pollutants program. Additionally, in July 2023, the EPA issued a proposed rule to expand the scope of its Greenhouse Gas Reporting Program for certain petroleum and natural gas facilities. The proposed rule would make the reach of the program both broader and more granular, creating reporting obligations for a wider set of methane and other gas emissions events and requiring increased technical detail for certain other preexisting reporting obligations. The proposed rule indicated an intended effective date of January 1, 2025, but the final rule remains pending at this time and any final effective date thus remains uncertain. Should this rule go into effect without major changes, it could raise our costs of regulatory compliance.

In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include NSPS at Subpart OOOOa to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“VOC”) emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, as discussed above, in January 2021, the administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. The executive order specifically called on the EPA to consider a proposed rule suspending, revising or rescinding the September 2020 deregulatory amendments by September 2021. In response, the U.S. Congress has approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA announced a final rule on December 2, 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. The regulations are subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, future implementation of the standards is uncertain at this time.

The Bureau of Land Management (the “BLM”) also finalized rules (the “BLM methane rule”) in November 2016 that seek to limit methane emissions from exploration and production activities on federal lands by imposing limitations on venting and flaring of natural gas, as well as requirements for the implementation of leak detection and repair programs for certain processes and equipment. After attempts by the Trump administration to delay implementation of the BLM methane rule, and legal challenges both to the BLM methane rule and the delays, the BLM issued a final rule in September 2018 rescinding many of the provisions of the 2016 BLM methane rule, including the requirement to implement leak detection and repair programs, and imposing certain new requirements in a manner the BLM considered would reduce unnecessary compliance obligations on the industry. In November 2022, the BLM issued a proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. The comment period for this rule has closed and the rule is in the process of being finalized. We cannot predict the scope of any resulting legislation or new regulations, which may, in turn, affect our business.

The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standards for ground-level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. The EPA issued its anticipated area designations in November and December 2017. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 ppb rather than lower them further. In October 2021, the EPA announced it will reconsider its December 2020 decision; however, in August 2023, the EPA announced a new review of the ozone NAAQS after considering advice provided by the Clean Air Scientific Advisory Committee (“CASAC”). As part of its new review, the EPA is seeking information from the scientific community and the public to guide CASAC’s development of the Integrated Science Assessment prior to the EPA’s expected release of its Integrated Review Plan in the fall of 2024. If the EPA were to adopt more stringent NAAQS for ground-level ozone as part of its reconsideration of the December 2020 decision, States are expected to implement more stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operations. In addition, in November 2021, the EPA revised the 2015 ozone NAAQS designations, which expanded a New Mexico non-attainment area to include parts of El Paso County, Texas and designated Weld County, Colorado as a non-attainment area. The EPA’s designation of El Paso County was vacated as impermissibly retroactive in June 2023 by the D.C. Circuit Court of Appeals, but the designation of Weld County was upheld. In 2017, the EPA designated certain counties in southeastern New Mexico and West Texas located in the Permian Basin attainment/unclassifiable for the 2015 ozone NAAQS. In June 2022, the EPA announced that it is considering a discretionary redesignation for these counties based on current monitoring data and other air quality factors. If in the future, the areas in which we operate were redesignated as nonattainment areas, this could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.

Compliance with one or more of these and other air pollution control and permitting requirements and rules has the potential to delay the development of natural gas, oil and NGL projects and increase our costs of development and production, which costs could be significant.

In response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) preconstruction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that will typically be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the United States, including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. As discussed above, federal regulatory action regarding GHG emissions from the oil and gas sector has focused on methane emissions; however, federal implementation of the finalized 2016 methane rule is uncertain at this time (as also discussed above).

While Congress has, from time to time, considered legislation to reduce emissions of GHGs, no significant legislation has been adopted at the federal level. In the absence of such federal climate legislation, a number of state and regional cap-and-trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. The SEC originally planned to issue a final rule by October 2022, but according to the SEC’s updated rulemaking agenda, a final rule is now expected to be issued in the spring of 2024. In addition, the United Nations-sponsored Paris Agreement calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. However, the Paris Agreement does not impose any binding obligations on its participants. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. These goals were reaffirmed in November 2022 at the 27th Conference of the Parties (“COP27”) in Sharm-El Sheik. While there were limited announcements at COP27 with respect to the reduction of fossil fuel use, there were negotiations on emissions reduction targets and reduction of fossil fuel use amongst the international community, and such discussions continued at the 28th Conference of the Parties (“COP28”) in Dubai.

In addition, the Inflation Reduction Act of 2022 (“IRA”), signed by President Biden in August 2022, provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. The EPA recently issued a proposed rule to implement the waste emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions.

An executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide,” and “social cost of methane.” The EPA published a final report in December 2023 with the social cost of carbon at $190 per metric ton of carbon dioxide emitted in 2020 at a 2% discount rate. That figure is intended to be used to guide federal decisions on the costs and benefits of various policies and approvals, although such efforts have been the subject of a series of judicial challenges. A separate executive order targeting climate change, also issued by the current administration in January 2021, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate actions to account for corresponding climate costs. The climate change executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the executive orders have been filed. A federal district court issued a preliminary injunction against the order in June 2021, which the Fifth U.S. Circuit Court of Appeals vacated and remanded back to the district court in August 2022. The federal district court subsequently issued a permanent injunction against the order in August 2022 limited to the thirteen Plaintiff states, which included Louisiana, Alabama, Alaska, Arkansas, Georgia, Mississippi, Missouri, Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia. We cannot predict the scope of any resulting legislation or new regulations, which may, in turn, affect our business.

Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and NGLs we produce and lower the value of our reserves. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, in June 2016, establishing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting (which are subject to revision, as discussed above); published in June 2016 an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixtures used in hydraulic fracturing. In November 2022, the BLM also issued a proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.” To date, EPA has taken no further action in response to the December 2016 report.

From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. For example, Wyoming has promulgated rules related to the public disclosure of substances used in hydraulic fluid, testing requirements for water wells near drilling sites and leak detection and repair requirements for fugitive emissions from oil and gas production facilities.

In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. In January 2020, the White House Council on Environmental Quality (“CEQ”) proposed changes to NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule proposes to narrow the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” In July 2020, CEQ issued a final rule implementing the January 2020 proposal. However, several states and environmental groups have filed challenges to this rulemaking, and CEQ’s amendments are subject to reconsideration and may be subject to reversal or change under the Biden administration. CEQ issued an Interim Final Rule in June 2021, which extended the deadline by two years (to September 14, 2023) for federal agencies to develop or update their NEPA implementing procedures to conform to the CEQ regulations. Additionally, in October 2021, the CEQ issued a notice of proposed rulemaking to reintroduce certain requirements removed or reduced by the July 2020 amendments, and the Infrastructure and Investment Jobs Act, Pub.L. 117-58, signed into law in November 2021, codified some of the July 2020 amendments in statutory text. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. In April 2022, CEQ issued the Phase 1 Final Rule. The rule finalizes a narrow set of changes to generally restore regulatory provisions that were in effect for decades before the 2020 rule modified them for the first time. In June 2023, the Fiscal Responsibility Act was signed into law by President Biden, which also included reforms to the National Environmental Policy Act. In July 2023, the CEQ issued the proposed Phase 2 Rule. The impact of changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits. We currently have exploration, development and production activities on federal lands. Our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. However, any such adverse regulatory developments are expected to have no more than a minimal impact on our results, given our limited exposure of leases on federal lands.

In addition, the New Mexico state legislature in 2019 considered House Bill 206, which, if passed, would have enacted an Environmental Review Act comparable to NEPA. Specifically, the Environmental Review Act would require state governmental agencies at all levels to consider the qualitative, technical and economic factors relating to a project that may impact public health, ecosystems and the environment, the long-term as well as short-term benefits and costs of the proposed project, the cumulative impacts of the proposed project, and reasonable alternatives to proposed actions affecting the environment, communities or public health. If reconsidered and enacted in the future, the process contemplated by the Environmental Review Act has the potential, like NEPA, to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects in New Mexico, which costs could be substantial.

The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (the “FWS”) was required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The FWS did not meet that deadline. In August 2020, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. A coalition of states and environmental groups has challenged the three rules and the litigation remains pending. However, the Biden administration published two rules in October 2021 that reversed changes made by the Trump administration, namely to the definition of “habitat” and to a policy that made it easier to exclude territory from critical habitat under the ESA. In June and July 2022, the FWS issued final rules rescinding Trump-era regulations concerning the definition of “habitat” and critical habitat exclusions. In June 2023, the Biden administration announced additional proposed revisions concerning the procedures and criteria used for listing, reclassifying, and delisting protected species and designating critical habitat.

It is possible those developments could, in the future, affect our operations if the areas in which we operate are designated as critical or suitable habitat.

In addition, the federal government recently has issued indictments under the Migratory Bird Treaty Act (“MBTA”) to several oil and natural gas companies after migratory birds were found dead near reserve pits associated with drilling activities. The Department of the Interior issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In response to this opinion, two separate lawsuits were filed in May 2018 in the U.S. District Court for the Southern District of New York challenging the Department of the Interior’s interpretation of the MBTA. In September 2018, eight states filed a similar suit in the U.S. District Court for the Southern District of New York. In February 2020, the FWS published a rule seeking to codify the December 2017 legal opinion. In August 2020, the District Court struck down the December 2017 opinion, and the Department of the Interior responded by issuing a new rule in January 2021 that reduced the activities that could incur liability under the MBTA. The Biden administration has since revoked the January 2021 rule; published an Advanced Notice of Proposed Rulemaking announcing an intent to solicit comments to help develop proposed regulations establishing a permitting system to authorize, under certain circumstances, the incidental take of migratory birds; and issued a Director’s Order “establishing criteria for the types of conduct that will be a priority for enforcement activities with respect to incidental take of migratory birds.” The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other activities and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

We aim to attract and retain top-tier talent in the oil and gas sector and empower our employees to be innovators in our industry. As of December 31, 2023, we had 461 total employees. In addition, we hire independent contractors on an as needed basis but have no collective bargaining or employment agreements with our employees.

We believe that our employees give us a sustainable competitive advantage, and we understand the need to attract, retain and train the best team possible. We provide fair and competitive wages to assist in retention of our top talent, and our compensation programs are integrated with our overall business strategies to incentivize performance and maximize shareholder returns. In addition, we conduct an equitable pay analysis at least annually to ensure that we are adequately and fairly compensating all employees based on their experience and performance. We offer a variety of programs that are designed to retain our employees and also provide opportunities to grow their professional careers while continuing to deliver value to the company. Additionally, we maintain a comprehensive suite of benefits that provide our employees with various options including retirement, health and wellness, and life and disability plans.

We are committed to a diverse workforce because we believe employees with different backgrounds, experiences, interests and skillsets drive superior results. In terms of gender and racial distribution, approximately 31% of our employees identify as female and approximately 32% of our employees identify as non-white. We plan to continue to recruit and develop a diverse workforce to ensure that we remain an employer of choice delivering top-tier results.

We strive to promote a safe and healthy working environment with a focus on protecting our employees, contractors, the public and the environment in the communities in which we conduct our business. We provide frequent trainings and monthly safety meetings for all field employees and have excelled in health, safety and environmental performance maintaining zero employee recordable incidents due to illnesses or injuries at the workplace.

Our principal executive offices are located at 300 N. Marienfeld Street, Suite 1000, Midland, Texas, 79701, and our telephone number is (432) 695-4222. We also have office space in Carlsbad, New Mexico; Denver, Colorado; Eunice, New Mexico; Gardendale, Texas; Greenwood, Texas; Pecos, Texas; San Angelo, Texas; and Woodlands, Texas.

Our internet website address is www.permianres.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. Information on our website is not incorporated by reference into this Annual Report and should not be considered part of this document.

The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov.

The prices we receive for our oil, natural gas and NGLs heavily influence our revenue, cash flows, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the actual and expected supply of and demand for oil, natural gas and NGLs and market uncertainty. Historically, oil, natural gas and NGL prices have been volatile and subject to fluctuations relating to a variety of additional factors that are beyond our control, including:

•worldwide and regional economic conditions impacting the global supply of and demand for oil, natural gas and NGLs;

•the price and quantity of foreign imports of oil, natural gas and NGLs;

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

•actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

•actions of U.S., European Union and other governments and governmental organizations relating to Russia’s oil, natural gas and NGLs, including through sanctions, import restrictions and commodity price caps;

•actions of U.S. producers, and independent producers operating in other countries, relating to production levels;

•political, economic and other conditions that affect perceived or actual demand for oil, natural gas and NGLs, including international trade disputes, sanctions and global health pandemics, epidemics and concerns;

•the level of global exploration, development, production, and inventories;

•actions of U.S. and other governments to strategically release oil, natural gas and NGLs from strategic reserves;

•the availability of refining and storage capacity;

•prevailing prices on local price indexes in the area in which we operate;

•the proximity, capacity, cost and availability of gathering and transportation facilities;

•the cost of exploring for, developing, producing and transporting reserves;

•weather conditions and other natural disasters;

•terrorist attacks targeting oil and natural gas related facilities and infrastructure;

•technological advances affecting fuel economy, energy supply and energy consumption;

•the effect of energy conservation measures, alternative fuel requirements and the price and availability of alternative fuels;

•laws, regulations and taxes in the U.S. and in foreign jurisdictions that impact the demand for oil, natural gas and NGLs;

•shareholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize emissions of carbon dioxide and methane GHGs or otherwise;

•localized and global supply and demand fundamentals; and

•expectations about future commodity prices.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty.

A sustained or extended decline in commodity prices may result in a shortfall in our expected revenues and cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods of low commodity prices for oil and natural gas and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone, moderate or eliminate our planned drilling and completions operations, or suspend production from current wells, which could result in the reduction of our expected production and some of our proved undeveloped reserves and related standardized measure.

If we moderate or curtail our drilling, completion or production operations, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a sustained or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. A sustained or extended decline in commodity prices could require that we recognize impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

The process of estimating oil and natural gas reserves is complex. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, seismic, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as commodity prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant inaccuracies in our interpretations of this technical data or in making our assumptions could materially affect the estimated quantities and present value of our reserves.

Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. Our estimated proved reserves as of December 31, 2023, and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $74.70 per barrel of oil (WTI Posted) and $2.64 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2023. For example, if the crude oil and natural gas prices used in our year-end reserve estimates were to increase or decrease by 10%, our proved reserve quantities at December 31, 2023 would increase by 14.4 MMBoe (1.6%) or decrease by 18.2 MMBoe (2.0%), respectively, and the pre-tax PV 10% of our proved reserves would increase or decrease by $1.9 billion (17%).

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production, particularly because competition in the oil and natural gas industry is intense, and many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

As of December 31, 2023, 24% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.

As of December 31, 2023, over 96% of our total net acreage was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. Some of our leases also expire as to certain depths if continuous drilling obligations are not met. If our leases expire in whole or in part and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

In the future, we may shut-in some or all of our production depending on market conditions, storage or transportation constraints and contractual obligations, and any prolonged shut-in of our wells could result in the expiration, in whole or in part, of the related leases, which could adversely affect our reserves, business, financial condition and results of operations.

We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, availability of gathering or transportation facilities, access to and availability of water sourcing and distribution systems, regulatory approvals, including permitting, and other factors. Because of these uncertain factors, we do not know if the numerous identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. Historically, we have funded our capital expenditures with cash flows from operations, borrowings under OpCo’s revolving credit facility, proceeds from offering debt and equity securities and divestitures of non-core assets, and we intend to finance our future capital expenditures in a similar fashion. When we finance our capital expenditures through indebtedness, a portion of our cash flows from operations must be used to pay interest and principal on the indebtedness, which reduces our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments.

Our cash flow from operations and access to capital are subject to a number of variables, including:

•the prices at which our production is sold;

•our proved reserves;

•the level of hydrocarbons we are able to produce from existing wells;

•our ability to acquire, locate and produce new reserves;

•the levels of our operating expenses; and

•our ability to borrow under OpCo’s revolving credit facility and to access the capital markets.

If our revenues or the borrowing base under OpCo’s revolving credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under OpCo’s revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. In addition to the risks we face in drilling for and producing oil and natural gas, some factors that may directly or indirectly negatively impact our scheduled operations:

•lack of available gathering or transportation facilities or delays in the constructing such facilities;

•abnormal pressure or irregularities in geological formations;

•shortages of or delays in obtaining equipment, qualified personnel, materials or resources;

•equipment failures, accidents or other unexpected operational events;

•delays imposed by or resulting from compliance with laws, regulations or litigation, including limitations resulting from wastewater disposal, emission of GHGs and limitations on hydraulic fracturing;

•environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•natural disasters;

•personal injuries and death;

•terrorist attacks targeting oil and natural gas related facilities and infrastructure;

•limited availability of financing at acceptable terms;

•title problems;

•adverse weather conditions; and

•limitations in the market for oil and natural gas.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events, including those operating risks listed above, could materially and adversely affect our business, financial condition or results of operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include:

•landing a wellbore in the desired drilling zone;

•staying in the desired drilling zone while drilling horizontally through the formation; and

•spacing the wells appropriately to maximize production rates and recoverable reserves.

Risks that we face while completing wells include:

•the ability to fracture stimulate the planned number of stages;

•the ability to run tools the entire length of the wellbore during completion operations; and

•the ability to prevent unintentional communication with other wells.

If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas and New Mexico in past years. These drought conditions have led some local water districts to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Where practicable, we strive to use recycled water for our hydraulic fracturing operations. If we are unable to obtain water from water suppliers or our recycling operations, it may need to be obtained from non-local sources and transported to drilling sites, resulting in increased costs, or we may be unable to economically drill for or produce oil and natural gas, each of which could have an adverse effect on our financial condition, results of operations and cash flows.

Our operations could be impaired if we are unable to recycle or dispose of the water we produce in an economical and environmentally safe manner. Where practicable, we strive to recycle the produced water for our future oil and gas operations. Produced water that is not recycled generally gets disposed of in disposal wells that are operated by us or third-party contractors. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection of produced water resulting from oil and gas activities, which has led to increased public and governmental scrutiny of injection safety. For instance, in response to concerns regarding induced seismicity, regulators in Texas have adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

Another consequence of water disposal activities and seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on our use of injection wells or commercial disposal wells to dispose of produced water. Increased regulation and attention given to water disposal and induced seismicity could also lead to greater opposition, including litigation, to limit or prohibit oil and gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in limitations on disposal well volumes, disposal rates and pressures or locations, require us or our vendors to shut down or curtail the injection into disposal wells, or cause delays, interruptions or termination of our operations, which events could have a material adverse effect on our business, financial condition and results of operations.

Our producing properties are geographically concentrated in West Texas and New Mexico in the Permian Basin. At December 31, 2023, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages, regional power outages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The marketability of our oil, natural gas and NGLs production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil, natural gas and NGLs production is generally transported from the wellhead by gathering systems that are either owned by us or third-party midstream companies. In general, we do not control the transportation of our production and our access to transportation facilities may be limited or denied. In some instances, we have contractual guarantees relating to the transportation of our production through firm transportation arrangements, but third-party systems may be temporarily unavailable due to pressure limitations, market conditions, mechanical failures, accidents or other reasons. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or third-party midstream companies or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, natural gas and NGLs and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements, we may be required to shut in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil, natural gas and NGLs produced from our fields, would materially and adversely affect our financial condition and results of operations.

We have entered into certain multi-year supply and service agreements associated with energy and frac sand purchase agreements. We also have various multi-year agreements that relate to the sale, transportation or gathering of our oil and natural gas and may in the future enter into multi-year agreements for contracts for drilling rigs or other services. Some of these agreements contain minimum volume commitments that we must satisfy or contractual penalties in the form of volume deficiencies or other remedies may apply. As of December 31, 2023, our aggregate long-term contractual obligation under these agreements was $120.4 million, which represents the gross minimum obligation but does not include amounts that may be due under certain contracts that contain variable pricing or volumetric components as the future obligations cannot be determined. Further information about these agreements can be found at Note 14—Commitments and Contingencies under Part II, Item 8 of this Annual Report. Any failure by us to satisfy the minimum volume commitments in these agreements could adversely affect our results of operations and financial position.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue as commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

We normally sell production to a relatively small number of customers, as is customary in our business. See Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part II, Item 8 of this Annual Report for significant purchasers that accounted for more than 10% of our revenues for the years ended December 31, 2023, 2022 and 2021. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:

•recoverable reserves;

•future commodity prices and their applicable differentials;

•operating costs; and

•potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and purchase prices higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. In addition, debt agreements impose certain limitations on our ability to enter into mergers or combination transactions and our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Our ability to effectively manage and operate our business depends significantly on information technology systems. The failure of these systems to operate effectively and support our operations, challenges in transitioning to upgraded or replacement systems, difficulty in integrating new or updated systems, or a breach in security of these systems could adversely impact the operations of our business.

Any breach of our network may result in the loss of valuable business data, misappropriation of our customers’ or employees’ personal information, or a disruption of our business, which could harm our customer relationships and reputation, and result in lost revenues, fines or lawsuits.

Moreover, we must comply with increasingly complex and rigorous regulatory standards enacted to protect business and personal data. Any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against us by governmental entities or others, damage to our reputation and credibility, and could have a negative impact on revenues and profits.

We may enter into derivative instrument contracts for a portion of our oil and natural gas production from time to time. As of December 31, 2023, we had entered into derivative contracts covering a portion of our projected oil and gas production through 2023 (refer to Note 8—Derivative Instruments under Part II, Item 8 of this Annual Report for a summary of our derivative instruments as of December 31, 2023). Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•production is less than the volume covered by the derivative instruments;

•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

•there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of OpCo’s borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile commodity prices and interest rates.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Since our production is not fully hedged, and we are also exposed to fluctuations in oil, natural gas and NGL prices as it relates to the price we receive from the sale of our unhedged volumes. We intend to continue to hedge a portion of our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility with regard to these unhedged volumes, and a decline in commodity prices could materially and adversely affect our business, financial condition and results of operations.

As of December 31, 2023, we had approximately $3.8 billion of total long-term debt and additional borrowing capacity of $2.0 billion under OpCo’s revolving credit facility (after giving effect to $5.7 million of outstanding letters of credit), all of which would be secured if borrowed. Subject to the restrictions in the instruments governing OpCo’s outstanding indebtedness (including OpCo’s revolving credit facility and senior notes), OpCo and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing OpCo’s outstanding indebtedness do contain restrictions on the incurrence of additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.

Our current and future level of indebtedness could affect our operations in several ways, including the following:

•require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;

•limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•increase our vulnerability to downturns and adverse developments in our business and the economy generally;

•limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses or to refinance existing indebtedness;

•place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

•make it more likely that a reduction in OpCo’s borrowing base following a periodic redetermination could require OpCo to repay a portion of its then-outstanding bank borrowings;

•make us vulnerable to increases in interest rates as the indebtedness under OpCo’s revolving credit facility may vary with prevailing interest rates;

•place us at a competitive disadvantage relative to our competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

•make it more difficult for OpCo to satisfy its obligations under its debt and increase the risk that we may default on its debt obligations.

OpCo’s ability to make scheduled payments on or to refinance its indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit OpCo to pay the principal, premium, if any, and interest on OpCo’s indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance OpCo’s indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require OpCo to comply with more onerous covenants, which could further restrict business operations.

The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm OpCo’s ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The agreements governing OpCo’s indebtedness restrict OpCo’s ability to dispose of assets and OpCo’s use of the proceeds from such disposition. OpCo may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit OpCo to meet scheduled debt service obligations.

OpCo’s credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing in February 2027 (the “Credit Agreement”) and the indentures governing its senior notes contain a number of significant covenants, including restrictive covenants that may limit OpCo’s ability to, among other things:

•incur additional indebtedness;

•make loans to others;

•make investments;

•merge or consolidate with another entity;

•make certain payments;

•hedge future production or interest rates;

•incur liens;

•sell assets; and

•engage in certain other transactions without the prior consent of the lenders.

In addition, OpCo’s Credit Agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of December 31, 2023, we were in full compliance with such financial ratios and covenants.

The restrictions in OpCo’s debt agreements may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive imposed on OpCo.

Any default under the agreements governing OpCo’s indebtedness that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make OpCo unable to pay principal, premium, if any, and interest on such indebtedness. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on OpCo’s indebtedness, or if OpCo otherwise fails to comply with the various covenants, including financial and operating covenants, in the agreements governing OpCo’s indebtedness, OpCo could be in default under the terms of the agreements governing such indebtedness. In the event of such default:

•the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;

•the lenders under OpCo’s revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and

•we could be forced into bankruptcy or liquidation.

If our operating performance declines, we may in the future need to obtain waivers under OpCo’s revolving credit facility to avoid OpCo being in default. If OpCo breaches the covenants under its revolving credit facility and seeks a waiver, OpCo may not be able to obtain a waiver from the required lenders. If this occurs, OpCo would be in default under the revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

OpCo’s revolving credit facility limits the amounts OpCo can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually in the spring and fall. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan.

The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted senior unsecured notes OpCo may issue in the future. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under OpCo’s revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. In connection with amending the Credit Agreement in connection with closing the Earthstone Merger, the elected commitments were increased to $2.0 billion.

In the future, we may not be able to access adequate funding under OpCo’s revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, OpCo could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service OpCo’s indebtedness.

Our ability to obtain financing and trade credit and the terms of any financing or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor, limit, and report existing emissions of greenhouse gases as well as to reduce such future emissions. The SEC issued a proposed rule in March 2022 that would mandate disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. The SEC originally planned to issue a final rule by October 2022, but according to the SEC’s updated rulemaking agenda, a final rule is now expected to be issued in the spring of 2024.

In addition, in response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require Prevention of Significant Deterioration preconstruction and Title V operating permits for certain large stationary sources. While the regulation of methane from oil and gas facilities in the U.S. has been subject to uncertainty in recent years, President Biden signed an executive order in January 20, 2021 calling for the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. The EPA subsequently issued new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, which were finalized in December 2023. The EPA has also issued a proposed rule in July 2023 with a proposed effective date of January 1, 2025, to expand the scope of the EPA’s Mandatory Greenhouse Gas Reporting program and to update reporting requirements. We cannot predict the scope of any final methane or GHG regulatory requirements or the cost to comply with such requirements. In addition, the IRA, signed by President Biden in August 2022, provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change.

The IRA also includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. The EPA recently issued a proposed rule to implement the waste emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions. Compliance with these rules and legislation will likely require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, increased frequency of maintenance and repair activities to address emissions leakage and additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance.

A separate executive order targeting climate change was issued by President Biden in January 2021, which directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters and identify any “fossil fuel subsidies” to take steps to ensure that federal funding is not directly subsidizing fossil fuels. Legal challenges to the executive orders have been filed. A federal district court issued a preliminary injunction against the order in June 2021, which the Fifth U.S. Circuit Court of Appeals vacated and remanded back to the district court in August 2022. The federal district court subsequently issued a permanent injunction against the order in August 2022, limited to the thirteen Plaintiff states, which included Louisiana, Alabama, Alaska, Arkansas, Georgia, Mississippi, Missouri, Montana, Nebraska, Oklahoma, Texas, Utah, and West Virginia. In November 2022, the BLM also issued a proposed rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. We cannot predict the scope of any resulting legislation or new regulations, which may, in turn, affect our business.

At the international level, the United Nations-sponsored Paris Agreement, a non-binding agreement of which the U.S. is a signatory, encourages nations to limit their GHG emissions through nationally-determined reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50% to 52% from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021 at the COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 150 counties have joined since, committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. These goals were reaffirmed in November 2022 at the COP27 in Sharm-El Sheik. While there were limited announcements at COP27 with respect to the reduction of fossil fuel use, there were negotiations on emissions reduction targets and reduction of fossil fuel use amongst the international community, and such discussions continued at COP28 in Dubai. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time.

Please refer to Regulation of the Oil and Natural Gas Industry in Item 1 for further discussion on the topics referenced above and additional information on existing and proposed laws, regulations, treaties and international pledges intended to address GHGs and other climate change issues. Existing and future laws and regulations relating to climate change and GHG emissions could increase our costs, reduce demand for our products, limit our growth opportunities, impair our ability to develop our reserves and have other adverse effects on our business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA and other federal agencies have asserted regulatory authority over aspects of the process. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act (“SDWA”) and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above-and-below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. To date, EPA has taken no further action in response to the December 2016 report.

Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These completed, ongoing, or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms. Additionally, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, production or development activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition and results of operations. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, including as a result of the renewable energy incentives contained in the IRA, could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects.

The impact of the changing demand for oil and natural gas, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to stringent, complex and evolving federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to protection of the environment and natural resources (including threatened and endangered species and their habitats). These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the requirement to engage in remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental, health and safety risks and costs or may not provide sufficient coverage if an environmental, health and safety claim is made against us. Moreover, public interest in the protection of the environment and human health has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. In the states of New Mexico and Texas, as an example, governmental authorities are investigating the practice of flaring natural gas and it is possible that such states could implement additional volumetric or other restrictions on this practice which may require us to curtail or shut in production which otherwise is or would be flared due to the unavailability of acceptable delivery, transportation or processing arrangements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered or threatened species and their habitats could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

Increasing attention to climate change and natural capital, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures, and consumer demand for alternative sources of energy may result in increased costs (including but not limited to increased costs associated with compliance, stakeholder engagement, contracting, and insurance), reduced demand for our products and our product and services, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for our products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed on us without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. Voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations.

Moreover, while we may create and publish disclosures regarding ESG matters, many of the statements in those disclosures may be on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying and measuring many ESG matters. Such disclosures may also be partially reliant on third-party information that we have not or cannot independently verify. Additionally, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, and increased regulation will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions.

Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have a negative impact on our stock price and our or our access to and costs of capital. Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel industry companies based on climate change, natural capital, or other ESG related concerns, which could affect our or our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our or the fossil fuel industry’s reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

We possess leases which are granted by the federal government and administered by the BLM, a federal agency. Operations we conduct on federal leases must comply with numerous additional statutory and regulatory restrictions. These leases contain relatively standardized terms requiring compliance with detailed regulations. Under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. Any such suspension or termination of our leases could adversely impact the results of our operations.

The Biden administration has proposed certain changes to the leasing and permitting programs for oil and natural gas development on federal lands, including imposing bans on new oil and gas leasing, cancelling issued oil and gas leases, and removing public lands from future oil and gas leasing. For example, on June 2, 2023, the Biden administration issued a 20-year ban on new oil and gas leasing within a 10-mile radius of Chaco Culture National Historical Park in Northern New Mexico. Additionally, on September 6, 2023, the Biden administration announced that it is cancelling issued leases for oil and gas in the Arctic National Wildlife Refuge designated for oil and gas development. While we cannot predict the ultimate impact of these changes or whether federal agencies will implement further reforms, any revisions to the federal leasing or permitting process that make it more difficult for us to pursue operations on federal lands may adversely impact our operations.

In addition to administrative and policy risks, operations on federal lands also face litigation risks. Ongoing litigation related to the federal oil and gas leasing program may impact our federal oil and gas leases, which in turn could impact our results of operations. For example, a June 2022 settlement approved by a federal district court in Washington, D.C., obligates the BLM to redo its environment reports under NEPA for all oil and gas leases sold between 2015 and 2020, including leases in New Mexico. The settlement stems from a 2016 lawsuit alleging that the BLM was not properly accounting for the cumulative climate impacts of its federal leasing program. Separately, there is a risk that authorizations required for existing operations may be delayed to the point that it causes a business disruption, and we cannot guarantee that further action will not be taken to curtail oil and natural gas development on federal land. For example, certain lawmakers have proposed to reduce or ban further leasing on federal lands or to adopt further restrictions for same. To the extent such legislation is passed, it may adversely impact our operations, which could negatively impact our financial performance.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

We are subject to laws, regulations and rules enacted by national, regional and local governments and NYSE. In particular, we are required to comply with certain SEC, NYSE and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

Certain segments of the investor community have recently developed negative sentiment towards investing in the oil and gas industry. Over the past years, equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain institutional investors, private equity companies, pension funds, university endowments and family foundations have stated policies to reduce or eliminate their investments in the oil and gas sector based on social and environment considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.

Holders of our Class A Common Stock and Class C Common Stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our Fourth Amended and Restated Certificate of Incorporation, as amended (the “Charter”). As of December 31, 2023, Pearl Energy Investments (“Pearl”), EnCap Partners GP, LLC (“EnCap”), Riverstone Investment Group LLC (“Riverstone”) and NGP Energy Capital (“NGP”) beneficially own approximately 12%, 10%, 7% and 6%, respectively, of our voting interests and, along with their affiliates, could limit the ability of our other stockholders to approve transactions they may deem to be in the best interests of our Company or delay or prevent changes in control or changes in our management.

As long as Pearl, EnCap, Riverstone and NGP continue to own or control a significant percentage of outstanding voting power, they may have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our Charter or our second amended and restated bylaws (the “Bylaws”), or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

In addition, Pearl, EnCap, Riverstone and NGP and their respective affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential acquisition candidates or industry partners. They may also acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership by our significant stockholders may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with stockholders who own such a significant percentage of our voting securities.

We are not restricted from issuing additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market, or the perception that these sales could occur, could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.

Dividends, whether fixed or variable, and stock repurchases are authorized and determined by our board of directors in its sole discretion and depend upon a number of factors, including the Company’s financial results, cash requirements and future prospects, restrictions in our debt agreements, as well as such other factors deemed relevant by our board of directors. In September 2022 at the closing of the Colgate Merger, we announced an upsized $500 million stock repurchase program, but this repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time. Similarly, any dividends, whether fixed or variable, we may declare in the future will be determined by our board of directors in its sole discretion. Any elimination of, or downward revision in, our stock repurchase program or dividend policy could have an adverse effect on the market price of our common stock.

Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:

•a classified board of directors, with only approximately one-third of our board of directors elected each year;

•no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;

•the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;

•the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

•a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;

•the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officers, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

•limiting the liability of, and providing indemnification to, our directors and officers;

•controlling the procedures for the conduct and scheduling of stockholder meetings;

•providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and

•advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.

These provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.

As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.

Our Charter provide that, unless we consent in writing to the selection of an alternative forum, the (i) Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (A) any derivative action or proceeding brought on our behalf, (B) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (C) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, the Charter or our Bylaws or (D) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein; and (ii) subject to the foregoing, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act, including all causes of action asserted against any defendant to such complaint. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits. Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations.

The Earthstone Merger involved the combination of two companies that operated as independent public companies until November 1, 2023. The combination of two independent businesses is complex, costly and time consuming, and we will be required to continue to devote significant management attention and resources to integrating the business practices and operations of Earthstone into the Company. Potential difficulties that we may encounter as part of the integration process include the following:

•the inability to successfully combine the business of the Company and Earthstone in a manner that permits the combined company to achieve, on a timely basis, or at all, the enhanced revenue opportunities and cost savings and other benefits anticipated to result from the Earthstone Merger;

•complexities associated with managing the combined businesses, including difficulty addressing possible differences in operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;

•the assumption of contractual obligations with less favorable or more restrictive terms; and

•potential unknown liabilities and unforeseen increased expenses associated with the Earthstone Merger.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees and other constituencies, our ability to achieve the anticipated benefits of the Earthstone Merger, our earnings or our business and financial results following the Earthstone Merger.

The financial estimates disclosed in connection with the announcement of the Earthstone Merger were based on assumptions of, and information available to, our management when prepared, and these estimates and assumptions are subject to uncertainties, many of which are beyond our control and may not be realized. Many factors will be important in determining the Company’s future results following the Earthstone Merger. As a result of these contingencies, actual future results may vary materially from our estimates. In view of these uncertainties, these financial estimates should not be viewed as a representation that the forecasted results will necessarily reflect actual future results.

Our financial estimates were not prepared with a view toward public disclosure, and such financial estimates were not prepared with a view toward compliance with published guidelines of any regulatory or professional body. Further, any forward-looking statement speaks only as of the date on which it is made, and we do not undertake any obligation, other than as required by applicable law, to update the financial estimates to reflect events or circumstances after the date those financial estimates were prepared or to reflect the occurrence of anticipated or unanticipated events or circumstances.

We may fail to realize the anticipated benefits and synergies expected from the Earthstone Merger, which could adversely affect the Company’s business, financial condition and results of operations. The success of the Earthstone Merger will depend, in significant part, on the Company’s ability to successfully integrate the acquired business, grow the revenue of the Company and realize the anticipated strategic benefits and synergies from the acquisition. We believe that the acquisition will provide operational and financial scale, increasing free cash flow and an enhanced corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the Earthstone Merger. This growth and the anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Earthstone Merger within the anticipated timing or at all, our business, financial condition and results of operations may be adversely affected.

None.

We rely on information technology and data to operate our business effectively and recognize the importance of implementing and maintaining cybersecurity systems and processes that allow us to protect the confidentiality, integrity and availability of our information systems and the data residing within them.

In order to monitor our information technology systems and data and to identify potential threats to such, we maintain cybersecurity risk assessment and management programs. Such programs include, but are not limited to, annual security penetration tests performed both externally and internally, bi-annual security assessments against cybersecurity frameworks, continuous vulnerability scanning, incident response processes, monthly and annual security awareness and simulated phishing trainings for our employees, and various system alert monitoring and screenings.

As part of our cybersecurity risk management process, we conduct simulated cybersecurity incidents to ensure that we are prepared to respond to such incidents and to highlight any areas for potential improvement in our cyber incident preparedness. We have a cybersecurity incident management policy and response plan in place. Cybersecurity breaches are evaluated by our information technology teams, which includes our VP of Information Technology. If an incident is deemed to be a breach, it is communicated to our legal department and management for evaluation, including whether the breach requires communication to the Board of Directors or investors through a relevant public filing.

Our cybersecurity risk management is primarily the responsibility of our VP of Information Technology and information technology teams. Our VP of Information Technology has over 25 years of industry experience in the field of information systems and oversees our risk assessment programs, remediation of known risks, processes for the regular monitoring of our information systems and our employee cybersecurity training programs. Our Board of Directors also oversees cybersecurity risk through our Audit Committee who reviews periodic reporting and updates regarding our risk management associated with cybersecurity.

We have not experienced any cybersecurity incidents that have had a material impact on our business strategy, results of operations or financial condition. For more information about the cybersecurity risks we face, refer to Risk Factors under Part I, Item 1A of this Annual Report.

Refer to Note 14—Commitments and Contingencies under Part II, Item 8 of this Annual Report for more information regarding our legal proceedings.

Environmental. Due to the nature of the oil and gas industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination and we conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from events are probable and the costs can be reasonably estimated. We are not aware of any material environmental claims existing as of December 31, 2023 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties.

Not applicable.

Our Class A Common Stock is currently listed on the New York Stock Exchange under the ticker symbol “PR”. As of February 23, 2024, there were 240 registered holders of record of our Class A Common Stock and 55 registered holders of record of our Class C Common Stock.

The following performance graph and related information shall deemed to be furnished, but not filed with the SEC.

The performance graph below compares the cumulative total stockholder return on our Class A Common Stock (“PR”) to that of the Standard & Poor’s 500 Index (“S&P 500”) and the Standard & Poor’s 500 Oil and Gas Exploration & Production ETF (“XOP”). The “cumulative total return” assumes that $100 was invested, including reinvestment of dividends, if any, in our Class A Common Stock, the S&P 500, and XOP on December 31, 2018 and tracks it through December 31, 2023. The results shown in the graph below are not necessarily indicative of future stock price performance.

Our Board of Directors authorized a stock repurchase program to acquire up to $500 million of our outstanding Common Stock (the “Repurchase Program”), which was approved to run through December 31, 2024. The Repurchase Program can be used to reduce our 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 our discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with our 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 our Board of Directors at any time.

Share repurchase activity during the three months ended December 31, 2023 was as follows:

Period						Total Number of Shares Purchased						Average Price Paid per Share						Total Number of Shares Purchased as Part of Publicly Announced Programs						Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs (in thousands)
October 1 - 31, 2023						—						$	—					—						$	442,661
November 1 - 30, 2023(1)						2,774,826						$	13.64					2,774,826						$	404,811
December 1 - 31, 2023(2)						2,252,252						$	12.93					2,252,252						$	375,689

(1)    During the fourth quarter of 2023, we repurchased and subsequently canceled 2,774,826 shares of Class A Common Stock in connection with shares issued for the Earthstone Merger on November 1, 2023. The shares were repurchased at an average price of $13.64 per common share for a total cost of $37.9 million.

(2)    During the fourth quarter of 2023, we repurchased 2,252,252 shares of Class C Common Stock at a weighted average price of $12.93 per common share for a total cost of $29.1 million. The shares that were repurchased were subsequently canceled. The share repurchase was completed from a selling shareholder during a secondary offering of Class C Common Stock.

We return capital to shareholders through a combination of base dividends plus a variable return framework, comprised of variable dividends and/or share repurchases. The variable return program is structured to distribute at least 50% of free cash flow after the base dividend through a variable dividend, share repurchases or a combination of both. The mix between variable dividends and share repurchases are dependent upon market conditions during a given quarter. Variable dividends are typically declared on or around our quarterly earnings and paid shortly thereafter. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board of Directors. Our Board of Directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board deems relevant at the time of such determination.

We are 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.

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, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

Immediately following the COVID-19 pandemic, global oil supply was limited by production curtailment agreements among the Organization of Petroleum Exporting Countries and other oil producing countries (“OPEC+”), in addition to overall reduced drilling and completion activity from U.S. producers. As global economies have reopened, demand for oil and gas has risen steadily post-pandemic and has been positively impacted by a global-wide transition away from coal to natural gas. The aforementioned factors, among others, led to heightened commodity prices during certain time periods of 2022, particularly during the beginning of Russia’s invasion of Ukraine. Specifically, NYMEX WTI spot prices for crude oil reached a high of $123.70 per barrel on March 8, 2022, and the NYMEX Henry Hub index price for natural gas reached a high of $9.85 per MMBtu on August 23, 2022. Subsequently, governments from several countries coordinated a simultaneous release of a portion of their strategic petroleum reserves, which increased global oil inventories to near normalized levels. In response, OPEC+ announced an agreement to curtail production by approximately two million barrels per day. Despite OPEC+’s largest production cut since the pandemic, crude oil prices continued to fall from their peak in mid-2022 due in part to government-coordinated petroleum releases, in addition to global recession concerns, a high interest rate environment, and lower than expected demand from China. Year-to-date, OPEC+ has undertaken a series of actions in an effort to support commodity prices. In April 2023, OPEC+ announced further production cuts, which were later extended. In addition, both Saudi Arabia and Russia announced unilateral production curtailments at separate times during 2023. These actions, coupled with relatively strong global demand and recent tensions in the Middle East, caused crude oil prices to increase during 2023, with NYMEX WTI spot prices reaching a high of $93.68 per barrel on September 27, 2023. However, further concerns of global economic growth and increases in oil and natural gas supply levels have resulted in additional price deterioration at the end of 2023.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations, weather conditions, the global transition to 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 2021:

Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement and senior notes.

Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to 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.

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. inflation rate has been steadily increasing during 2022 and 2023. 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.

On August 21, 2023, we entered into an Agreement and Plan of Merger (“the Merger Agreement”) with Earthstone pursuant to which Permian Resources agreed to acquire Earthstone. On November 1, 2023 the Earthstone Merger was completed, and we issued 161.2 million shares of our Class A Common Stock and 49.5 million shares of our Class C Common Stock to Earthstone stockholders under the terms of the Merger Agreement, and we also assumed Earthstone’s debt upon closing of the Merger, which consisted of $1.05 billion of senior notes and $830 million in borrowings outstanding under its credit facility at closing. Based on the fair value of our common stock on the closing date of the Earthstone Merger, November 1, 2023, the merger consideration was $2.9 billion.

Under the terms of the Merger Agreement (i) each share of Earthstone Class A Common Stock was converted into 1.446 shares (the “Exchange Ratio”) of our Class A Common Stock, (ii) each share of Earthstone Class B Common Stock was converted into 1.446 shares of our Class C Common Stock, (iii) each common unit of Earthstone Energy Holdings, LLC (“Earthstone OpCo”), a subsidiary of Earthstone, representing limited liability company membership interests in Earthstone OpCo were converted into common units of OpCo (“Common Unit”), equal to the Exchange Ratio.

As a result of the Earthstone Merger, we acquired approximately 223,000 net leasehold acres in the Permian Basin and increased our aggregate production to approximately 300,000 Boe per day. We believe that the Earthstone Merger will drive accretion across our key financial and operating metrics over the long term, enhance our shareholder returns, improve capital efficiency, add significant core inventory and provide increased acreage to our position in the Permian Basin. The operational and financial information set forth in this Annual Report on Form 10-K do not include the activity of Earthstone for periods prior to the completion of the Earthstone Merger on November 1, 2023.

On December 15, 2023 we completed the acquisition of approximately 7,000 net leasehold acres for an unadjusted purchase price of $98 million. The acquired assets consist largely of undeveloped acreage that is contiguous to one of our existing core acreage blocks in Eddy County, New Mexico.

On February 16, 2023, we completed an acquisition of approximately 4,000 net leasehold acres and 3,300 net royalty acres for an unadjusted purchase price of $98 million. The acquired assets consist largely of undeveloped acreage that is contiguous to one of our existing core acreage blocks in Lea County, New Mexico.

On March 13, 2023, we completed the sale of our operated saltwater disposal wells and the associated produced water infrastructure in Reeves County, Texas. The total cash consideration received at closing was $125 million, of which $65 million was directly related to the sale and transfer of control of our water assets, while the remaining $60 million consisted of contingent consideration that is tied to our future drilling, completion and water connection activity in Reeves County, Texas. The proceeds from the divestiture were used to fund the February 2023 bolt-on acquisition discussed above and to pay down incremental borrowings under our credit facility.

During each quarter of the year ended December 31, 2023, we declared and paid a quarterly dividend of $0.05 per share of Class A Common Stock and a quarterly distribution of $0.05 per Class C Common Stock (each of which has an underlying Common Unit of OpCo). Additionally, during the year ended December 31, 2023, our Board of Directors declared and paid variable dividends and distributions totaling $0.17 per share of Class A Common Stock and Class C Common Stock.

The cash dividends and distributions paid to common unitholders totaled $236.0 million for the year ended December 31, 2023.

Also during the year ended 2023, we paid in aggregate $86.5 million to repurchase 7.2 million Common Units of OpCo resulting in an equal number of associated shares of Class C Common Stock simultaneously being canceled under our stock repurchase program.

On September 12, 2023, we issued at par $500 million of 7.00% senior notes due 2032 (the “Existing Notes”) in a 144A private placement. On December 13, 2023, we issued additional notes under this indenture dated September 12, 2023, that totaled an additional $500 million of 7.00% senior notes (together with the Existing Notes, the “2032 Senior Notes”) which resulted in aggregate net proceeds to the Company of $982.5 million from the 2032 Senior Notes, after deducting the issuance discount of $2.5 million and debt issuance costs of $15.0 million. The proceeds from the 2032 Senior Notes were used to repay debt outstanding under our credit facility, including borrowings assumed in connection with the closing of the Earthstone Merger.

On December 20, 2023, we entered into the sixth amendment to the Credit Agreement (the “Sixth Amendment”). The Sixth Amendment, among other things, increased the borrowing base from $2.5 billion to $4.0 billion and maintained the elected commitments at $2.0 billion. On September 1, 2023, we entered into the fourth and fifth amendments to the Credit Agreement (the “Fourth Amendment” and the “Fifth Amendment”). The Fourth Amendment expanded the waiver of the automatic reduction of the borrowing base under the Credit Agreement to, among other things, allow for the assumption (or the issuance, in certain circumstances) of up to $1.05 billion principal amount of Permitted Senior Unsecured Notes (as defined in the Credit Agreement) in order to refinance debt assumed in the Earthstone Merger and otherwise allow for the issuance of Permitted Senior Unsecured Notes up to an aggregate principal amount of $1.0 billion. The Fifth Amendment, among other things, waived compliance with certain restrictive covenants to enable the Earthstone Merger, subject to customary conditions. In addition, the Fifth Amendment increased the aggregate elected commitments from $1.5 billion to $2.0 billion. The Fifth Amendment was effective as of the closing date of the Earthstone Merger on November 1, 2023.

During 2023, we completed the Earthstone Merger, and the results of operations of Earthstone were included in our financial and operational data beginning on November 1, 2023. During 2022, we completed the Colgate Merger, and the results of operations of Colgate were included in our financial and operational data beginning on September 1, 2022.

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

			Year Ended December 31,												Increase/(Decrease)
			2023						2022						$						%
Net revenues (in thousands):
Oil sales			$	2,696,777					$	1,622,035					$	1,074,742					66		%
Natural gas sales(1)			142,077						276,957						(134,880)						(49)		%
NGL sales(2)			282,039						232,273						49,766						21		%
Oil and gas sales			$	3,120,893					$	2,131,265					$	989,628					46		%
Average sales prices:
Oil (per Bbl)			$	75.84					$	88.95					$	(13.11)					(15)		%
Effect of derivative settlements on average price (per Bbl)			1.81						(4.85)						6.66						137		%
Oil including the effects of hedging (per Bbl)			$	77.65					$	84.10					$	(6.45)					(8)		%
Average NYMEX WTI price for oil (per Bbl)			$	77.62					$	94.24					$	(16.62)					(18)		%
Oil differential from NYMEX			(1.78)						(5.29)						3.51						66		%
Natural gas price excluding the effects of GP&T (per Mcf)(1)			$	1.60					$	4.86					$	(3.26)					(67)		%
Effect of derivative settlements on average price (per Mcf)			0.29						(0.53)						0.82						155		%
Natural gas including the effects of hedging (per Mcf)			$	1.89					$	4.33					$	(2.44)					(56)		%
Average NYMEX Henry Hub price for natural gas (per MMBtu)			$	2.53					$	6.38					$	(3.85)					(60)		%
Natural gas differential from NYMEX			(0.93)						(1.52)						0.59						39		%
NGL price excluding the effects of GP&T (per Bbl)(2)			$	22.83					$	35.97					$	(13.14)					(37)		%
Net production:
Oil (MBbls)			35,560						18,235						17,325						95		%
Natural gas (MMcf)			119,182						59,692						59,490						100		%
NGL (MBbls)			15,569						6,750						8,819						131		%
Total (MBoe)(3)			70,992						34,934						36,058						103		%
Average daily net production:
Oil (Bbls/d)			97,424						49,958						47,466						95		%
Natural gas (Mcf/d)			326,525						163,539						162,986						100		%
NGL (Bbls/d)			42,654						18,494						24,160						131		%
Total (Boe/d)(3)			194,499						95,708						98,791						103		%

(1)    Natural gas sales for the year ended December 31, 2023 include $48.9 million of gathering, processing and transportation costs (“GP&T”) that are reflected as a reduction to natural gas sales and $13.1 million for the year ended December 31, 2022. Natural gas average sales price, however, excludes $0.41 per Mcf of such GP&T charges for the year ended December 31, 2023 and $0.22 for the year ended December 31, 2022.

(2)    NGL sales for the year ended December 31, 2023 include $73.3 million of GP&T that are reflected as a reduction to NGL sales and $10.6 million for the year ended December 31, 2022. NGL average sales price, however, excludes $4.71 per Bbl of such GP&T charges for the year ended December 31, 2023 and $1.56 per Bbl for the year ended December 31, 2022.

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

Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the year ended December 31, 2023 increased by $1.0 billion, or 46%, compared to the year ended December 31, 2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Net production volumes for oil, natural gas, and NGLs increased 95%, 100% and 131%, respectively, between periods. The oil production volume increase resulted from placing 183 wells on production since December 31, 2022 as compared to 95 wells brought online during the year ended December 31, 2022. Oil production also benefited from wells acquired in the mergers with Colgate and Earthstone, which collectively added 9,852 MBbls of net oil production to the year ended December 31, 2023 compared to 3,517 MBbls of net oil production added from the Colgate Merger to the year ended December 31, 2022. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold driving the 100% and 131%, respectively, increase in gas and NGL volumes between periods. The higher increase in gas and NGL volumes between periods as compare to the 95% increase in oil volumes was due to the producing wells acquired in the Earthstone Merger, which have a higher gas-to-oil ratio than our existing production base, and this has resulted in more volumes of gas and NGLs being added to our total production stream since the closing of the Earthstone Merger on November 1, 2023. Additionally, certain processors of our raw gas operated in higher ethane-recovery mode during the year ended December 31, 2023 as compared to the year ended December 31, 2022, which resulted in a higher percentage of NGLs being recovered from our wet gas stream during 2023.

These production increases were partially offset by decreases in the average realized sale prices for oil, natural gas and NGLs which decreased 15%, 67% and 37%, respectively, for the year ended December 31, 2023 compared to the same 2022 period. The 15% decrease in the average realized oil price was mainly the result of 18% lower NYMEX crude prices between periods, which was slightly offset by improved oil differentials. The average realized sales price of natural gas decreased 67% due to 60% lower average NYMEX gas prices between periods as well as a larger proportional gas differential during the year ended December 31, 2023 compared to the same 2022 period. The 37% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in 2023 compared to 2022. The market prices for oil and natural gas have been impacted by global supply and demand factors throughout 2022 and 2023 as discussed in the market conditions section above.

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

			Year Ended December 31,												Increase/(Decrease)
			2023						2022						Change						%
Operating costs (in thousands):
Lease operating expenses			$	373,772					$	171,867					$	201,905					117		%
Severance and ad valorem taxes			240,762						155,724						85,038						55		%
Gathering, processing, and transportation expense			89,282						97,915						(8,633)						(9)		%
Operating cost metrics:
Lease operating expenses (per Boe)			$	5.26					$	4.92					$	0.35					7		%
Severance and ad valorem taxes (% of revenue)			7.7		%				7.3		%				0.4		%				6		%
Gathering, processing, and transportation expense (per Boe)			1.26						2.80						(1.55)						(55)		%

Lease Operating Expenses. Lease operating expenses (“LOE”) for the year ended December 31, 2023 increased $201.9 million compared to the year ended December 31, 2022. This increase in LOE was primarily related to higher fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with our significantly higher well count from new producing wells drilled or acquired. The higher well count in 2023 was due to (i) 309 gross operated horizontal wells acquired in the Colgate Merger on September 1, 2022 that operated for the entire year of 2023 compared to four months in 2022, (ii) 183 wells placed on production since December 31, 2022, and (iii) 1,190 gross operated horizontal wells acquired in the Earthstone Merger on November 1, 2023.

LOE per Boe was $5.26 for the year ended December 31, 2023, which represents an increase of $0.35 per Boe (or 7%) from the year ended December 31, 2022. This increase was primarily driven by per Boe increases associated with higher water disposal rates between periods, resulting from the sale of our operated saltwater disposal system in March 2023 (see Note 3—Acquisitions and Divestitures for additional information on the divestiture). This increase was partially offset by fewer workovers and lower semi-variable well costs, such as wellhead chemicals, labor and electricity that resulted from operational efficiencies.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 2023 increased $85.0 million compared to the year ended December 31, 2022. 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 year ended 2023 increased $63.4 million compared to the same 2022 period primarily due to higher oil, natural gas and NGL revenues between periods.

Ad valorem taxes between periods increased by $21.6 million due to (i) higher tax assessments on our oil and gas reserve values, (ii) incurring a full year of ad valorem taxes on the proved developed properties acquired in the Colgate Merger compared to four months in 2022, and (iii) additional expense incurred on the proved developed properties acquired in the Earthstone Merger on November 1, 2023.

Severance and ad valorem taxes as a percentage of total net revenues increased to 7.7% for the year ended December 31, 2023 as compared to 7.3% for the year ended December 31, 2022. This increase in rate was primarily the result of higher ad valorem taxes as discussed above.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the year ended December 31, 2023 decreased $8.6 million compared to the year ended December 31, 2022. Additionally, GP&T decreased on a per Boe basis from $2.80 for the year ended December 31, 2022 to $1.26 per Boe for the year ended December 31, 2023. These decreases are primarily due to a higher proportion of our GP&T costs being recognized as a reduction to our gas and NGL revenues for the year ended December 31, 2023 as compared to 2022. This classification of GP&T costs in revenues is required under ASC Topic 606, Revenue from contracts with Customers, whenever our gas processers transfer control of our raw gas at delivery points prior to, or at, the inlet of gas processing plants. Refer to Note 15—Revenues under Part II, Item 8 of this Annual Report for additional information on our natural gas gathering and processing contracts.

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

For the year ended December 31, 2023, DD&A expense amounted to $1.0 billion, an increase of $562.9 million from 2022. The primary factor contributing to higher DD&A expense in 2023 was the increase in our overall production volumes between periods, which increased DD&A expense by $459.0 million period over period, while higher DD&A rates between periods increased DD&A expense by $103.9 million.

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. Our DD&A rate per Boe was $14.19 for the year ended December 31, 2023 compared to $12.73 in 2022. This increase in the rate between periods was primarily due to (i) the finding and development rate of approximately $10.50 per BOE for 2023, as incorporated in our DD&A computation and (ii) downward proved reserve revisions primarily because of decreasing oil prices during 2023.

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

			Year Ended December 31,
(in thousands)			2023						2022
Cash general and administrative expenses			$	85,978					$	60,584
Stock-based compensation - equity awards			75,877						113,759
Stock-based compensation - liability awards			—						(24,174)
Stock-based compensation - cash settled awards			—						9,385
General and administrative expenses			$	161,855					$	159,554

G&A expenses for the year ended December 31, 2023 were $161.9 million compared to $159.6 million for the year ended December 31, 2022. Higher G&A in 2023 was the result of a $25.4 million increase in cash G&A between periods. This increase was primarily due to (i) higher payroll and employee-related costs associated with our G&A headcount, which increased from a year to date monthly average of 126 as of December 31, 2022 to 185 as of December 31, 2023 stemming from the Colgate and Earthstone Mergers; (ii) higher professional and legal fees between periods; and (iii) higher rent, software and office expenses between periods associated with the higher headcount. This was partially offset by a $23.1 million decrease in total stock-based compensation expense between periods. This decrease was largely due to (i) a $19.4 million net decrease in stock-based compensation expense related to liability classified awards that were settled in cash or reclassified as equity in 2022 (we no longer have any liability based equity awards outstanding); and (ii) a $6.5 million decrease in equity awards compensation costs associated with less expense recognized for the acceleration of certain awards for officer and employee exits stemming from the Colgate Merger, which totaled $40.0 million for the year ended December 31, 2023 as compared to $46.5 million for the year ended December 31, 2022.

Refer to Note 7—Stock-Based Compensation under Part II, Item 8 of this Annual Report for additional information regarding these awards.

Merger and integration expense. Merger and integration expense for the year ended December 31, 2023 was $125.3 million. compared to $77.4 million for the year ended December 31, 2022. Merger and integration expense incurred during the year ended December 31, 2023 consisted of (i) $63.4 million in bankers’ advisory, legal, consultancy and accounting fees associated with the Earthstone Merger; (ii) $43.5 million in severance and related benefits associated with employee terminations that occurred in 2023 in connection with the Earthstone Merger; and (iii) $18.4 million in costs incurred during 2023 related to the Colgate Merger primarily related to employee severance charges and integration and consulting expenses. During the year ended December 31, 2022, merger and integration expense primarily consisted of (i) $40.0 million in bankers’ advisory fees related to the Colgate Merger; (ii) $24.0 million in severance and related benefits associated with employee terminations that occurred in connection with the Colgate Merger; and (iii) legal, accounting and consultancy fees.

Exploration and Other Expenses. The following table summarizes exploration and other expenses for the periods indicated:

			Year Ended December 31,
(in thousands)			2023						2022
Geological and geophysical costs			$	11,342					$	7,401
Stock-based compensation - equity awards			2,541						2,721
Other expenses			5,454						1,256
Exploration and other expenses			$	19,337					$	11,378

Exploration and other expenses were $19.3 million for the year ended December 31, 2023 compared to $11.4 million for the year ended December 31, 2022. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and include other operating costs. The period over period increase was primarily related to (i) higher G&G personnel costs associated with increased headcount; (ii) increased costs incurred on G&G projects and seismic studies; and (iii) $1.5 million in costs incurred in 2023 associated with nonrecurring legal settlements.

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

			Year Ended December 31,
(in thousands)			2023						2022
Credit Facility			$	30,049					$	15,974
5.375% Senior Notes due 2026			15,557						15,557
7.75% Senior Notes due 2026			23,250						7,750
6.875% Senior Notes due 2027			24,500						24,500
8.00% Senior Notes due 2027			7,333						—
3.25% Convertible Senior Notes due 2028			5,525						5,525
5.875% Senior Notes due 2029			41,125						13,708
9.875% Senior Notes due 2031			8,229						—
7.00% Senior Notes due 2032			12,347						—
Amortization of debt issuance costs, debt discount and debt premium			16,078						15,652
Interest capitalized			(7,813)						(3,021)
Other interest expense			1,029						—
Total			$	177,209					$	95,645

Interest expense was $81.6 million higher for the year ended December 31, 2023 compared to the year ended December 31, 2022 mainly due to (i) $58.5 million in additional interest expense incurred from the senior notes that were assumed in the Colgate and Earthstone Mergers; (ii) $14.1 million in higher interest expense incurred on our credit facility due to a higher weighted average borrowings outstanding and effective interest rate during 2023; and (iii) $12.3 million in interest incurred on our Senior Notes due 2032 that were issued in September 2023.

Our weighted average borrowings outstanding under our Credit Agreement were $357.0 million during 2023 compared to $235.5 million in 2022. Our Credit Agreement’s weighted average effective interest rate was 7.1% and 4.5% for the years ended December 31, 2023 and 2022, respectively, due to higher rates on our variable-rate borrowings between periods.

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

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

			Year Ended December 31,
(in thousands)			2023						2022
Realized cash settlement gains (losses)			$	99,410					$	(120,105)
Non-cash mark-to-market derivative gain (loss)			14,606						77,737
Total			$	114,016					$	(42,368)

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

			Year Ended December 31,
(in thousands)			2023						2022
Income before income taxes			$	1,035,648					$	870,132
Income tax expense			(155,945)						(120,292)

Our provision for income taxes for the years ended December 31, 2023 and 2022 differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income primarily due to (i) the portion of pre-tax net income that is attributable to our non-controlling interest and which is therefore not taxable to the Company; (ii) other permanent differences; (iii) state income taxes; and (iv) any changes during the period in our deferred tax asset valuation allowance.

For the year ended December 31, 2023 we generated pre-tax net income of $1.0 billion and recorded income tax expense of $155.9 million. The primary factors decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income that was attributable to our non-controlling interest partners and not taxable to the Company.

During the year ended December 31, 2022, generated pre-tax net income of $870.1 million and recorded income tax expense of $120.3 million. The primary factors decreasing our income tax expense below the U.S. statutory rate was (i) the portion of pre-tax income that was attributable to our non-controlling interest partners, and (ii) the release of our deferred tax valuation allowance due to the generation of net income in the current year.

Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2022 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021.

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. Our total capital expenditures incurred for the year ended December 31, 2023 were $1.5 billion. We expect our total drilling, completion and facilities cash capital expenditures budget for 2024 to be between $1.9 billion to $2.1 billion. We funded our capital expenditures for 2023 entirely from cash flows from operations, and we expect to fund our 2024 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.

Because we are the operator of a high percentage of our acreage, we 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: prevailing and anticipated prices for oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners.

In August 2023, we announced our merger with Earthstone, and it was completed on November 1, 2023. As a result of the Earthstone Merger, our future operational plans, cash flows and leverage profile, among others things, as a combined entity has changed, and such changes include (i) assuming $1.05 billion of Earthstone’s senior notes, (ii) refinancing Earthstone’s credit facility borrowings outstanding at closing with borrowings under our facility, and (iii) funding of transaction costs incurred related to the Earthstone Merger. Additionally, during the year ended 2023, we issued $1.0 billion of 7.00% 2032 Senior Notes, with the net proceeds being used to repay indebtedness outstanding under our credit facility, including a portion of the debt we assumed upon closing of the Earthstone Merger.

We plan to return capital to shareholders through a combination of base dividends plus a variable return program, including variable dividends, share repurchases or a combination of both. During each quarter for the year ended December 31, 2023, we declared and paid a quarterly cash dividend of $0.05 per share of Class A Common Stock and a quarterly cash distribution of $0.05 per Common Unit of OpCo. In addition, during the year ended December 31, 2023, our Board of Directors also declared and paid total variable cash dividends of $0.17 per share of Class A Common Stock and total variable cash distributions of $0.17 per Common Unit of OpCo. The cash dividends and distributions paid to common unitholders totaled $236.0 million for the year ended December 31, 2023. Additionally, we repurchased 7.2 million shares of Class C Common Stock for $86.5 million and 2.8 million shares of Class A Common Stock for $37.9 million under our stock repurchase program during the year ended December 31, 2023.

    The 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.

We cannot ensure that cash flows from operations or other sources of needed capital will be available at acceptable terms or at all. Further, 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.

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

			Year Ended December 31,
(in thousands)			2023						2022						2021
Net cash provided by operating activities			$	2,213,499					$	1,371,671					$	525,619
Net cash used in investing activities			(1,578,379)						(1,205,049)						(226,476)
Net cash (used in) provided by financing activities			(631,188)						(106,625)						(297,547)

Cash Flows from 2023 Compared to 2022. For the year ended December 31, 2023, we generated $2.2 billion of cash from operating activities, an increase of $841.8 million from 2022. Cash provided by operating activities increased primarily due to higher production volumes, higher cash settlements on derivatives as well as the timing of our receivable collections for the year ended December 31, 2023 as compared to the same 2022 period. These increasing factors were partially offset by lower realized prices for all commodities, higher lease operating expenses, severance and ad valorem taxes, interest expense, merger and integration expense and cash G&A expense for the year ended December 31, 2023. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating expenses between periods.

For the year ended December 31, 2023, cash flows from operating activities, cash on hand, $1.0 billion in proceeds from the issuance of our 2032 Senior Notes and sales proceeds from divestitures together with contingent consideration of $175.4 million from the sale of oil and natural gas properties were used to: fund $1.5 billion of drilling and development cash expenditures; repay $830.0 million of borrowings outstanding from Earthstone’s credit facility that were assumed at closing of the Earthstone Merger; repay net borrowings of $385.0 million under our Credit Agreement; pay $236.0 million in dividends and cash distributions to holders of our Common Units; fund acquisitions of oil and gas properties of $234.3 million; and repurchase $162.4 million of our common stock.

Cash Flows from 2022 Compared to 2021. For the year ended December 31, 2022, we generated $1.4 billion of cash from operating activities, an increase of $846.1 million from 2021. Cash provided by operating activities increased primarily due to higher realized prices for oil and gas, higher production volumes, and the timing of vendor payments during 2022 as compared to 2021. These increasing factors were partially offset by higher merger and integration expense, severance and ad valorem taxes, lease operating expenses, GP&T, cash G&A expense and the timing of our receivable collections for the year ended December 31, 2022 as compared to the same 2021 period.

For the year ended December 31, 2022, cash flows from operating activities and net borrowings under our revolving credit facility were used to fund $771.6 million of drilling and development cash expenditures, finance $496.7 million of net cash consideration paid for the Colgate Merger, repay $400.0 million of borrowings outstanding from Colgate’s credit facility that were assumed at closing of the Colgate Merger and pay a total cash dividend and distribution to noncontrolling interest owners of $27.9 million.

OpCo, our consolidated subsidiary, has a five-year secured revolving Credit Agreement with a syndicate of banks maturing in February 2027 that, as of December 31, 2023, had a borrowing base of $4.0 billion and elected commitments of $2.0 billion. As of December 31, 2023, we had no borrowings outstanding and $2.0 billion in available borrowing capacity, which was net of $5.7 million in letters of credit outstanding.

OpCo was in compliance with the covenants and financial ratios under the Amended Credit Agreement described above through the filing of this Annual Report.

For further information on the Credit Agreement, refer to Note 5—Long-Term Debt under Item 8 of this Annual Report.

On March 19, 2021, OpCo issued $150.0 million in aggregate principal amount of Convertible Senior Notes. On March 26, 2021, OpCo issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. These issuances resulted in aggregate net proceeds to OpCo of $163.6 million, which were used to repay borrowings outstanding under the Credit Agreement and to fund the cost of entering in to capped call spread transactions of $14.7 million. Subsequently in April 2021, we redeemed at par all of our Senior Secured Notes (defined below), which was the intended use of proceeds from the Convertible Senior Notes offering.

The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of OpCo’s current subsidiaries that guarantee OpCo’s outstanding Senior Unsecured Notes as defined below.

The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028 unless earlier repurchased, redeemed or converted. The Convertible Senior Notes may become convertible prior to April 1, 2028, upon the occurrence of certain events or conditions being met as disclosed in Note 5—Long-Term Debt under Item 8 of this Annual Report. As of December 31, 2023, certain conditions have been met, and as a result, noteholders have the right to convert their Convertible Senior Notes during the first quarter of 2023. OpCo can settle the Convertible Senior Notes by paying or delivering cash, shares of the Class A Common Stock, or a combination of cash and Class A Common Stock, at OpCo’s election.

In connection with the Convertible Senior Notes issuance, OpCo entered into privately negotiated capped call spread transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to our Class A Common Stock upon a conversion and/or offset any cash payments OpCo is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap.

The Capped Call Transactions have an initial strike price of $6.28 per share of Class A Common Stock and an initial capped price of $8.4525 per share of Class A Common Stock (each subject to certain customary adjustments per the agreements).

On November 1, 2023, in connection with the Earthstone Merger, OpCo entered into supplemental indentures whereby all of Earthstone’s outstanding senior notes were assumed and became the senior unsecured debt of OpCo. The senior notes assumed by OpCo included $550 million of 8.00% senior notes due 2027 (the “2027 8.00% Senior Notes”) and $500 million of 9.875% senior notes due 2031 (the “2031 Senior Notes”). We recorded the acquired senior notes at their fair values as of the Earthstone Merger closing date, which were equal to 102.86% of par (a $15.7 million premium) for the 2027 8.00% Senior Notes and 107.37% of par (a $36.8 million premium) for the 2031 Senior Notes.