# Crescent Energy Co (CRGY) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Crescent Energy Co's 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1866175/000186617523000010/crgy-20221231.htm
Accession: 0001866175-23-000010
Filing date: 2023-03-07
Report date: 2022-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/CRGY/
All MD&A years: /company/CRGY/mda/
Previous year: /company/CRGY/mda/fy2021/ (FY 2021)
Next year: /company/CRGY/mda/fy2023/ (FY 2023)

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Combined and Consolidated Financial Statements and related Notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report and also with "Part I., Item 1A. Risk Factors" of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 2022 and 2021. Refer to our 2021 Annual Report filed March 10, 2022 for discussion and analysis of the changes in results of operations between the years ended December 31, 2021 and 2020. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Business overview

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven regions across the lower 48 states, focused in Texas and the Rockies.

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Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.

Geopolitical developments and economic environment

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility. In particular, the global spread of the COVID-19 virus during 2020 and 2021 had a negative impact on the global demand for oil and natural gas and caused significant commodity market volatility. While the increase in domestic vaccination programs and reduced spread of the COVID-19 virus has contributed to an improvement in the economy and higher realized prices for commodities, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

In addition, in February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, have contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of over $120 per barrel in 2022. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While the near-term impact of these events resulted in higher oil and gas prices in 2022, the geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. Furthermore, the United States has experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility.

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, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See "Part I., Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our operations—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In August 2022, IRA 2022 was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of GHGs through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge will start in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See "Part I., Item 1A. Risk Factors" for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. While we are evaluating the impact of the new corporate alternative minimum tax will have, we do not believe that it will have a material impact on our near-term taxes.

Equity transactions

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In September 2022, Independence Energy Aggregator L.P. ("Aggregator"), the entity through which certain affiliated entities hold their interests in us, exchanged 6.3 million units representing membership interests in OpCo (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock and agreed to sell 5.75 million shares of our Class A Common Stock (the "Offering") at a price to the public of $15.00 per share, or a net price of $14.10 per share after deducting the underwriters' discounts and commissions. We did not receive any cash proceeds from the Offering. Concurrent with the closing of the Offering, we repurchased an aggregate of approximately 2.6 million OpCo Units from PT Independence for $36.2 million and cancelled a corresponding number of shares of our Class B Common Stock (the "Concurrent OpCo Unit Purchase," and, together with the Offering, the "Equity Transactions"). As a result of the Equity Transactions, the total number of shares of our Class A Common Stock increased by 6.3 million shares, including 0.6 million shares of our Class A Common Stock that were not included as part of the Offering but rather issued in exchange for shares of Class B Common Stock and distributed in-kind by Aggregator. to affiliates, and the number of shares of our Class B Common Stock decreased by approximately 8.9 million. After the Equity Transactions, shares of our Class A Common Stock represent approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we own approximately 29% of the outstanding OpCo Units. Redeemable noncontrolling interests decreased by $158.1 million while APIC increased by $121.8 million as a result of the Equity Transactions and to reflect the new ownership of OpCo.

Other transactions

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes"). The estimated proceeds of the offering were $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds to repay a portion of outstanding borrowings under our revolving credit facility.

Acquisitions, divestitures and related reorganization

Acquisitions and related reorganization

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the “Purchase Agreement” and the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that holds all development and production assets of, and certain obligations formerly held by EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction, we paid $621.3 million in cash consideration and transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility (as defined below). In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to, among other things, increase the borrowing base to $1.8 billion and the elected commitment amount to $1.3 billion (see NOTE 8 – Debt). We incurred financing costs of $13.4 million associated with this amendment, which are recorded as debt issuance costs within Other assets on the consolidated balance sheets.

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

In December 2021, we completed a series of transactions, pursuant to which the business of Contango and the business of Independence combined under a new publicly traded holding company named "Crescent Energy Company." Our Class A common stock, par value $0.0001 per share (“Class A Common Stock") is listed on the NYSE under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Contango) indirectly held by our operating subsidiary, OpCo. Crescent Energy Company is a holding company, the sole material asset of which consists of OpCo Units, and is responsible for all operational, management and administrative decisions related to OpCo’s business. We are the sole managing member of OpCo. Crescent consolidates the financial results of OpCo and its subsidiaries. Former Contango shareholders own shares of Class A Common Stock, which have both voting and economic rights. The former owners of our predecessor, Independence Energy LLC, own economic, non-voting OpCo Units and corresponding shares of Class B common stock, par value $0.0001 per share ("Class B Common Stock," together with Class A Common Stock, the "Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights. OpCo Units may be redeemed or exchanged for Class A Common Stock or, at our election, cash on the terms and conditions set forth in the Amended and Restated Limited Liability Company Agreement of OpCo.

In connection with the Merger Transactions, we underwent a reorganization (the “Crescent Reorganization”), whereby Independence merged with and into OpCo (the “Isla Merger”). The financial statements include the accounts of Independence

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from the date of the Isla Merger, which is the date the Company obtained a controlling financial interest in Independence on a consolidated basis. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

In December 2021, we also acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments (the "Central Basin Platform Acquisition"). The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 8 – Debt).

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries (the "Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under the revolving credit facilities of certain of our subsidiaries (the "Prior Credit Agreements") and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of Class A units of our Predecessor, representing 0.77% of our consolidated ownership pursuant to the April 2021 Exchange. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the April 2021 Exchange.

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition.

In August 2020, we consummated the Titan Acquisition, pursuant to which we acquired of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence to an entity substantially owned by Liberty Holdco. Subsequent to the Titan Acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ and Eagle Ford Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. As a part of the Titan Acquisition, during the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor.

Divestitures

In November 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We closed the divestiture in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC ("Chama") in exchange for a 9.4% interest in Chama, which interest was valued at $3.8 million. As a result, we derecognized the assets and liabilities that were contributed to Chama from our consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

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In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million.

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

Stewardship

We strive to be good stewards of others’ assets: our investors’ capital, the environment and the communities in which we operate. We believe that this stewardship, and our success, requires an alignment with the interests of our stakeholders including our employees, investors, customers, suppliers and society at large. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In September 2022, we released our 2021 ESG report. The report included benchmarks for measuring future performance, consistent with Crescent's commitment to aligning with the SASB and Task Force on Climate-related Financial Disclosures frameworks, noted the progress of our key ESG priorities and detailed our goals to reduce GHG emissions in support of an economy-wide transition to a net-zero world. We are working to reduce Scope 1 GHG and methane emissions by implementing ambitious targets and eliminating routine flaring, among other initiatives. In February 2022, we joined the Oil & Gas Methane Partnership ("OGMP") 2.0 Initiative to enhance reporting of methane emissions. Our inaugural OGMP 2.0 submission was rated the highest-level, "Gold Standard."We also established an ESG Advisory Council to advise management and our Board on ESG-related issues.

How we evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

•Production volumes sold;

•Commodity prices and differentials;

•Operating expenses;

•Adjusted EBITDAX (non-GAAP); and

•Levered Free Cash Flow (non-GAAP)

Development program and capital budget

Our development program is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to incur approximately $575 million to $650 million, excluding acquisitions, for our 2023 capital program. The majority of our program is allocated to D&C, which approximately 85% is allocated to our operated assets primarily in the Eagle Ford and Uinta basins. We expect to fund our 2023 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Sources of revenues

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to

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supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","2020"],["Oil","66","%","","62","%","","69","%"],["Natural gas","25","%","","25","%","","21","%"],["NGLs","9","%","","13","%","","10","%"]]
[[/GREPCENT_TABLE]]

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 6% or less of our total revenues for each of the years ended December 31, 2022, 2021 and 2020.

Production volumes sold

The following table presents historical sales volumes for our properties:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","2020"],["Oil (MBbls)","21,865","","","13,237","","","13,132"],["Natural gas (MMcf)","128,470","","","89,455","","","78,541"],["NGLs (MBbls)","7,110","","","6,099","","","5,078"],["Total (MBoe)","50,387","","","34,245","","","31,300"],["Daily average (MBoe/d)","138","","","94","","","86"]]
[[/GREPCENT_TABLE]]

Total sales volume increased 16,142 MBoe during the year ended December 31, 2022 compared to 2021. The increase is primarily due to the Merger Transactions, DJ Basin Acquisition and Central Basin Platform Acquisition (collectively, the "2021 Acquisitions") and our Uinta Transaction, which contributed an additional 10,777 MBoe and 7,740 MBoe, respectively. Sales volumes from our other assets decreased by 2,375 during the year ended December 31, 2022 compared to 2021, primarily as a result of the natural decline from our existing asset base, partially offset by new operated Eagle Ford well completions in 2022.

Commodity prices and differentials

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations. The outbreak of the COVID-19 virus followed by certain actions taken by OPEC caused crude oil prices to decline significantly beginning in the first half of 2020 and prices remained below pre-pandemic levels for a prolonged period of time, finally recovering to pre-pandemic levels during 2021 and into 2022. Commodity prices were higher in 2022, compared to 2021, reflecting the ongoing recovery in the oil and gas industry in 2022 due to increasing demand as more states and countries re-open and national and global economies recover from the global COVID-19 pandemic and a premium due to the reduction in crude oil supply resulting from sanctions imposed on Russia in response to its large-scale invasion of Ukraine in February 2022. Although commodity prices have increased substantially in 2022, uncertainty persists regarding OPEC’s actions, increased U.S. drilling, the continued effect from the COVID-19 pandemic, inflation and the armed conflict in Ukraine.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

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[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","2020"],["Oil","64","%","","81","%","","81","%"],["Natural gas","66","%","","83","%","","76","%"],["NGLs","46","%","","67","%","","60","%"]]
[[/GREPCENT_TABLE]]

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","2020"],["Oil (Bbl):"],["Average NYMEX","$","94.23","","","$","68.04","","","$","39.40"],["Realized price (excluding derivative settlements)","90.06","","","66.71","","","37.45"],["Realized price (including derivative settlements) (1)","71.98","","","53.07","","","48.85"],["Natural Gas (Mcf):"],["Average NYMEX","$","6.64","","","$","3.91","","","$","2.08"],["Realized price (excluding derivative settlements)","5.97","","","3.96","","","1.90"],["Realized price (including derivative settlements)","3.42","","","3.06","","","2.32"],["NGLs (Bbl):"],["Realized price (excluding derivative settlements)","$","37.72","","","$","30.42","","","$","13.77"],["Realized price (including derivative settlements)","29.70","","","19.15","","","16.61"]]
[[/GREPCENT_TABLE]]

(1)For the year ended December 31, 2021, the realized price excludes the impact of the settlement of certain of our outstanding derivative oil commodity contracts associated with calendar years 2022 and 2023 for $198.7 million in June 2021. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Results of operations:

Year ended December 31, 2022 compared to year ended December 31, 2021

Revenues

The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:

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[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","$ Change","","% Change"],["Revenues (in thousands):"],["Oil","$","1,969,070","","","$","883,087","","","$","1,085,983","","","123","%"],["Natural gas","766,962","","","354,298","","","412,664","","","116","%"],["Natural gas liquids","268,192","","","185,530","","","82,662","","","45","%"],["Midstream and other","52,841","","","54,062","","","(1,221)","","","(2","%)"],["Total revenues","$","3,057,065","","","$","1,476,977","","","$","1,580,088","","","107","%"],["Average realized prices, before effects of derivative settlements:"],["Oil ($/Bbl)","$","90.06","","","$","66.71","","","$","23.35","","","35","%"],["Natural gas ($/Mcf)","$","5.97","","","$","3.96","","","$","2.01","","","51","%"],["NGLs ($/Bbl)","$","37.72","","","$","30.42","","","$","7.30","","","24","%"],["Total ($/Boe)","$","59.62","","","$","41.55","","","$","18.07","","","43","%"],["Net sales volumes:"],["Oil (MBbls)","21,865","","","13,237","","","8,628","","","65","%"],["Natural gas (MMcf)","128,470","","","89,455","","","39,015","","","44","%"],["NGLs (MBbls)","7,110","","","6,099","","","1,011","","","17","%"],["Total (MBoe)","50,387","","","34,245","","","16,142","","","47","%"],["Average daily net sales volumes:"],["Oil (MBbls/d)","60","","","36","","","24","","","67","%"],["Natural gas (MMcf/d)","352","","","245","","","107","","","44","%"],["NGLs (MBbls/d)","19","","","17","","","2","","","12","%"],["Total (MBoe/d)","138","","","94","","","44","","","47","%"]]
[[/GREPCENT_TABLE]]

Oil revenue. Oil revenue increased $1,086.0 million, or 123%, in 2022 compared to 2021. This increase was driven by higher realized oil prices that resulted in an increase of $510.4 million (an increase of 35% per Bbl) and a $575.6 million increase from higher sales volumes (24 MBbl/d, or 67%). The increase in sales volumes primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 3,569 MBbls and 5,371 MBbls, respectively, partially offset by the natural decline from our existing asset base of 312 MBbls.

Natural gas revenue. Natural gas revenue increased $412.7 million, or 116%, in 2022 compared to 2021. This increase was driven by higher realized natural gas prices that resulted in an increase of $258.2 million (an increase of 51% per Mcf) and a $154.5 million increase from higher sales volumes (107 MMcf/d, or 44%). The increase in sales volumes was primarily related to our 2021 Acquisitions and Uinta Transaction, which contributed an additional 34,497 MMcf and 14,201 MMcf, respectively, partially offset by the natural decline from our existing asset base of 9,683 MMcf.

NGL revenue. NGL revenue increased $82.7 million, or 45%, in 2022 compared to 2021. This increase was driven by higher realized NGL prices that resulted in an increase of $51.9 million (an increase of 24% per Bbl) and a $30.8 million increase from higher sales volumes (2 MBbl/d, or 12%). The increase in sales volumes was primarily related to our 2021 Acquisitions which contributed an additional 1,458 MBbls, partially offset by the natural decline from our existing asset base of 447 MBbls.

Midstream and other revenue. Midstream and other revenue decreased $1.2 million, or 2%, in 2022 compared to 2021, driven primarily by the production decline from some of our legacy asset areas.

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Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","$ Change","","% Change"],["Expenses (in thousands):"],["Operating expense","$","1,013,298","","","$","609,722","","","$","403,576","","","66","%"],["Depreciation, depletion and amortization","532,926","","","312,787","","","220,139","","","70","%"],["Impairment expense","142,902","","","\u2014","","","142,902","","","NM*"],["General and administrative expense","84,990","","","78,342","","","6,648","","","8","%"],["Other operating costs","(1,216)","","","(7,613)","","","6,397","","","(84","%)"],["Total expenses","$","1,772,900","","","$","993,238","","","$","779,662","","","78","%"],["Selected expenses per Boe:"],["Operating expense, excluding production and other taxes","$","15.38","","","$","14.62","","","$","0.76","","","5","%"],["Production and other taxes","4.73","","","3.18","","","1.55","","","49","%"],["Depreciation, depletion and amortization","10.58","","","9.13","","","1.45","","","16","%"]]
[[/GREPCENT_TABLE]]

*NM = Not meaningful.

Operating expense. Total operating expense increased $403.6 million, or 66%, in 2022 compared to 2021, driven primarily by the following factors:

(i)Lease and asset operating expenses increased $228.0 million, or 79%, in 2022 compared to 2021. Additionally, lease and asset operating expense per Boe increased $1.82 per Boe from $8.45 per Boe to $10.27 per Boe. This $228.0 million increase was driven primarily by higher production in 2022 compared to 2021, due in part to (i) the 2021 Acquisitions and Uinta Transaction, which contributed $151.4 million and $28.5 million to the increase, respectively, (ii) general inflationary costs across our assets and (iii) certain costs that move in tandem with oil prices, such as CO2 purchase costs related to our CO2 flood asset in Wyoming. These contractually commodity indexed operating expenses move in tandem with oil commodity prices, and as oil prices increase, higher contractually commodity-linked operating costs are offset by higher realizations.

(ii)Gathering, transportation and marketing expense decreased $10.0 million, or 5%, in 2022 compared to 2021. Additionally, gathering, transportation and marketing expense per Boe decreased $1.95 per Boe from $5.46 per Boe to $3.51 per Boe. This decrease was driven primarily by lower sulfur processing and transportation expenses.

(iii)Production and other taxes increased $129.4 million, or 119%, in 2022 compared to 2021 and increased 1.55 per Boe, or 49%, to $4.73 per Boe. This increase was driven primarily by higher oil and natural gas revenues, which increased the tax base upon which production and other taxes are calculated.

(iv)Workover expense increased $56.0 million in 2022 compared to 2021, and increased $1.01 per Boe from $0.32 per Boe to $1.33 per Boe. This increase was driven primarily by (i) higher well workover activities that meet our internal return thresholds due to the higher commodity price environment, (ii) general inflationary costs across our assets and (iii) additional costs from our 2021 Acquisitions and Uinta Transaction, which contributed $29.8 million and $9.4 million to the increase, respectively. The 2021 Acquisitions increase includes additional costs related to a standard turnaround at our natural gas processing plant in Wyoming.

(v)Midstream operating expense increased $0.1 million, or 1%, in 2022 compared to 2021,

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $220.1 million, or 70%, in 2022 compared to 2021, driven primarily by $104.7 million and $119.5 million of additional depreciation, depletion and amortization due to our 2021 Acquisitions and Uinta Transaction.

Impairment expense. During the year ended December 31, 2022, we evaluated our Goodwill and Oil and natural gas properties and determined that certain amounts were impaired. We recorded impairment charges totaling $142.9 million as a result of our evaluations, including $77.7 million related to Goodwill and $65.2 million related to Oil and natural gas properties. We did not record an impairment expense during the year ended December 31, 2021.

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General and administrative expense. General and administrative expense ("G&A") increased $6.6 million, or 8%, in 2022 compared to 2021, driven primarily by $14.3 million related to expense payable under the Management Agreement with KKR Energy Assets Manager LLC, which is the pro-rata portion of the Manager Compensation borne by us. The Management Agreement was entered into in connection with the Merger Transactions and we incurred expense in 2021 only for the period from December 7, 2021 through December 31, 2021. While only the portion of the Manager Compensation borne by us impacts our consolidated statements of operations, we include the full Manager Compensation in the calculation of Adjusted EBITDAX and Levered Free Cash Flow (the difference between the Manager Compensation and the amount presented in G&A is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation”). This increase was partially offset by $16.0 million in lower transaction and nonrecurring expenses.

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","$ Change","","% Change"],["General and administrative expense (in thousands)"],["Recurring general and administrative expense","$","38,863","","","$","14,359","","","$","24,504","","","171","%"],["Transaction and nonrecurring expenses","8,064","","","24,064","","","(16,000)","","","(66","%)"],["Equity-based compensation","38,063","","","39,919","","","(1,856)","","","(5","%)"],["Total general and administrative expense","$","84,990","","","$","78,342","","","$","6,648","","","8","%"],["General and administrative expense per Boe:"],["Recurring general and administrative expense","$","0.77","","","$","0.42","","","$","0.35","","","83","%"],["Transaction and nonrecurring expenses","0.16","","","0.70","","","(0.54)","","","(77","%)"],["Equity-based compensation","0.76","","","1.17","","","(0.41)","","","(35","%)"]]
[[/GREPCENT_TABLE]]

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs were negative in the years ended December 31, 2022 and 2021 as a result of gains on asset sales. Other operating costs reduced our 2022 and 2021 expenses by $1.2 million and $7.6 million, respectively. For the year ended December 31, 2022 we had gains from sales of assets of $4.6 million offset by $3.4 million of exploration expense. For the year ended December 31, 2021 we had gains from sales of assets of $8.8 million offset by $1.2 million of exploration expenses.

Interest expense. In 2022, we incurred interest expense of $95.9 million, as compared to $50.7 million in 2021, a 89% increase. The increase was primarily driven by higher interest rates associated with the issuance of the 2026 Notes and an increase in our weighted average debt outstanding during the period.

Gain (loss) on derivatives

We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and interest rate risks on our variable interest rate debt. The following table presents our total unrealized and realized gain (loss) on derivatives for the periods presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","$ Change","","% Change"],["Gain (loss) on derivatives (in thousands)"],["Gain (loss) on commodity derivatives","$","(676,902)","","","$","(865,994)","","","$","189,092","","","(22","%)"],["Gain (loss) on interest rate derivatives","\u2014","","","(26)","","","26","","","(100","%)"],["Gain (loss) on derivatives","$","(676,902)","","","$","(866,020)","","","$","189,118","","","(22","%)"]]
[[/GREPCENT_TABLE]]

Our loss on commodity derivatives in 2022, decreased $189.1 million, or 22%, compared to 2021 primarily due to changes in commodity prices relative to our strike price. In addition, in June 2021, we incurred additional losses on derivatives from the settlement of certain derivative oil contracts for $198.7 million.

Income from equity affiliates

Our income from equity method investments was $4.6 million in 2022 primarily due to a gain on sale of substantially all of the oil and gas assets held by Exaro.

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Income tax benefit (expense)

For the majority of the year ended December 31, 2021, we were organized as a limited liability company and treated as a flow-through entity for U.S. federal income tax purposes. As a result, the tax provision for the year ended December 31, 2021 was minimal. Subsequent to the Merger Transactions, we are a corporation that is subject to U.S. federal and state income tax on our allocable share of any taxable income from OpCo. For the years ended December 31, 2022 and 2021 we recognized income tax expense of $36.3 million and a income tax benefit of $0.3 million, respectively, for an effective tax rate of 7% and less than 1%, respectively. Our effective tax rate is lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests.

Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)

Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results. See “—Non-GAAP financial measures” section below for their definitions and application.

The following table presents a reconciliation of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss), the most directly comparable financial measure calculated in accordance with GAAP:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021","","$ Change","","% Change"],["(in thousands)"],["Net income (loss)","$","480,600","","","$","(432,227)","","","$","912,827","","","NM*"],["Adjustments to reconcile to Adjusted EBITDAX:"],["Interest expense","95,937","","","50,740"],["Realized (gain) loss on interest rate derivatives","\u2014","","","7,373"],["Income tax expense (benefit)","36,291","","","(306)"],["Depreciation, depletion and amortization","532,926","","","312,787"],["Exploration expense","3,425","","","1,180"],["Non-cash (gain) loss on derivatives","(102,358)","","","330,368"],["Impairment expense","142,902","","","\u2014"],["Non-cash equity-based compensation expense","38,063","","","39,919"],["Gain on sale of assets","(4,641)","","","(8,794)"],["Other (income) expense","(949)","","","(120)"],["Certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation","(39,070)","","","(2,706)"],["Transaction and nonrecurring expenses (1)","34,051","","","23,149"],["Early settlement of derivative contracts (2)","\u2014","","","198,688"],["Adjusted EBITDAX (non-GAAP)","$","1,217,177","","","$","520,051","","","$","697,126","","","134","%"],["Adjustments to reconcile to Levered Free Cash Flow:"],["Interest expense, excluding non-cash deferred financing cost amortization","(87,043)","","","(40,551)"],["Realized (gain) loss on interest rate derivatives","\u2014","","","(7,373)"],["Current income tax benefit (expense)","(3,113)","","","(629)"],["Tax-related redeemable noncontrolling interest distributions made by OpCo","(18,160)","","","\u2014"],["Development of oil and natural gas properties","(624,880)","","","(194,828)"],["Levered Free Cash Flow (non-GAAP)","$","483,981","","","$","276,670","","","$","207,311","","","75","%"]]
[[/GREPCENT_TABLE]]

*NM = Not meaningful.

(1)Transaction and nonrecurring expenses of $34.1 million during the year ended December 31, 2022 were primarily related to (i) legal, consulting, transition service agreement costs, related restructuring of acquired derivative contracts and other fees incurred for the Uinta Transaction and Merger Transactions, (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs. Transaction and nonrecurring expenses of $23.1 million for the year ended December 31, 2021 were primarily related to legal, consulting

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and other fees incurred for (i) the Noncontrolling Interest Carve-out, (ii) the April 2021 Exchange and (iii) the Merger Transactions.

(2)Represents the settlement in June 2021 of certain outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Adjusted EBITDAX increased by $697.1 million or 134% in 2022, compared to 2021, driven primarily by higher revenue associated with our oil, natural gas and NGL production as a result of (i) realized prices and (ii) sales volume driven by our 2021 Acquisitions, our Uinta Transaction and increased completions activity in the Eagle Ford. This increase was partially offset by a corresponding increase in operating costs due to higher production volumes and commodity prices, as well as higher realized losses on our commodity derivatives in 2022 compared to 2021.

Levered Free Cash Flow increased by $207.3 million or 75% in 2022 compared to 2021, driven primarily by increased Adjusted EBITDAX of $697.1 million, partially offset by $430.1 million of increased capital expenditures related to 2022 development activities following the increase in commodity prices.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations and borrowings under the Revolving Credit Facility. Our primary use of capital is for dividends to shareholders, debt repayment, development of our existing assets, share repurchases and opportunistic acquisitions.

Our development program is designed to prioritize the generation of meaningful free cash flow, attractive risk-adjusted returns and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program.

We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to preserve capital and protect margins and corporate returns through commodity cycles. For information regarding risks related to our derivative program, see "Part I., Item 1A. Risk Factors".

The following table presents our cash balances and outstanding borrowings at the end of each period presented:

[[GREPCENT_TABLE]]
[["","At December 31,"],["(in thousands)","2022","","2021"],["Cash and cash equivalents","$","\u2014","","","$","128,578"],["Long-term debt","1,247,558","","","1,030,406"]]
[[/GREPCENT_TABLE]]

Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading “Contractual obligations,” recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Cash flows

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

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[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2022","","2021","","2020"],["Net cash provided by operating activities","$","1,012,372","","","$","233,147","","","$","411,028"],["Net cash used in investing activities","(1,124,344)","","","(244,595)","","","(124,940)"],["Net cash (used in) provided by financing activities","(7,841)","","","105,145","","","(272,089)"]]
[[/GREPCENT_TABLE]]

Net cash provided by operating activities. Net cash provided by operating activities for the year ended December 31, 2022 increased by $779.2 million, or 334%, compared to 2021, primarily due to higher Adjusted EBITDAX and the restructuring of certain derivative contracts in 2021, partially offset by the restructuring of certain oil commodity derivative contracts acquired in connection with the Uinta Transaction.

Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2022 increased by $879.7 million, or 360%, compared to 2021, primarily due to $511.5 million of additional acquisitions of oil and natural gas properties in 2022, driven by the Uinta Transaction, and an additional $437.1 million of cash development capital expenditures as we have resumed reinvestment activity in light of higher commodity prices. The increase from our acquisitions and capital expenditures was partially offset by $67.5 million of higher proceeds from our 2022 assets sales.

Net cash provided by (used in) financing activities. Net cash used in financing activities for the year ended December 31, 2022 was $7.8 million, as compared to $105.1 million net cash provided by financing activities in 2021. This decrease was primarily due to cash outflows for $27.5 million of dividends to our Class A shareholders and $129.2 million of distributions to our redeemable noncontrolling interests in 2022. In addition we had a cash outflow of $36.2 million related to the Concurrent OpCo Unit Purchase. These net cash inflows in 2022 were partially offset by cash inflows from our debt transactions of $195.2 million.

Debt agreements

Senior Notes

On February 1, 2023, we issued $400.0 million aggregate principal amount of the 2028 Notes. The estimated proceeds of the offering were $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds to repay a portion of our outstanding credit facility balance. The 2028 Notes bear interest at an annual rate of 9.250%, which is payable on February 15 and August 15 of each year and mature on February 15, 2028.

We may, at our option, redeem all or a portion of the 2028 Notes at any time on or after February 15, 2025 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2028 Notes before February 15, 2025 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 109.250% of the principal amount of the 2028 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to February 15, 2025, we may redeem some or all of the 2028 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

On May 6, 2021, Crescent Energy Finance LLC ("Crescent Finance") issued $500.0 million aggregate principal amount of senior notes due 2026 at par (the "Original 2026 Notes"). In February 2022, Crescent Finance issued an additional $200.0 million aggregate principal amount of our senior notes due 2026 at 101% of par (the "Additional 2026 Notes" and, together with the Original 2026 Notes, the "2026 Notes"). Both issuances of the 2026 Notes are treated as a single series and vote together as a single class, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment. The 2026 Notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after May 1, 2023 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2026 Notes before May 1, 2023 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.250% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to May 1, 2023, we may redeem some or all of the 2026 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

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The Senior Notes are our senior unsecured obligations, and the notes and the guarantees issued in connection with the issuance of the Senior Notes rank equally in right of payment with the borrowings under the Revolving Credit Facility and all of its other future senior indebtedness and senior to any of its future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that guarantee the Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the Senior Notes in the future, on any securities exchange, and currently there is no public market for the Senior Notes.

Revolving Credit Facility

In connection with the issuance of the 2026 Notes in May 2021, Crescent Finance entered into the Revolving Credit Facility. The Revolving Credit Facility matures on September 23, 2027. At December 31, 2022, we had $559.4 million of outstanding borrowings under the Revolving Credit Facility and $9.8 million in outstanding letters of credit. Our elected commitment amount was $1.3 billion, and we had $730.8 million of available borrowings under the Revolving Credit Facility as of December 31, 2022.

Borrowings under the Revolving Credit Facility bear interest at either a (i) U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate ("SOFR"), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2022 was 6.98%.

The borrowing base under the Revolving Credit Facility was $2.0 billion as of December 31, 2022. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies. We expect to remain in compliance with these covenants for the foreseeable future.

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Capital expenditures

Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion and recompletion activities are presented as "development of oil and natural gas properties" in investing activities on our combined and consolidated statements of cash flows.

We expect to fund our 2023 capital program through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related Standardized Measure. These risks could materially affect our business, financial condition and results of operations.

The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["(in thousands)","2022","","2021","","2020"],["Total development of oil and natural gas properties","$","624,880","","","$","194,828","","","$","110,126"],["Change in accruals and other non-cash adjustments","(32,173)","","","(39,221)","","","16,038"],["Cash used in development of oil and natural gas properties","592,707","","","155,607","","","126,164"],["Cash used in acquisition of oil and natural gas properties","626,620","","","115,076","","","\u2014"],["Non-cash acquisition of oil and natural gas properties","\u2014","","","647,579","","","454,599"],["Total expenditure on acquisition and development of oil and natural gas properties","$","1,219,327","","","$","918,262","","","$","580,763"]]
[[/GREPCENT_TABLE]]

Our development of oil and natural gas properties was higher during the year ended December 31, 2022, compared to the year ended December 31, 2021. Due to the low commodity price environment experienced throughout 2020 resulting from the COVID-19 pandemic and the actions from OPEC, we significantly reduced our development capital expenditures starting in the second quarter of 2020 but resumed development activities in the second half of 2021 as commodity prices recovered to pre-pandemic levels. During the year ended December 31, 2022, commodity prices remained at or above levels prior to the COVID-19 pandemic. Accordingly, in conjunction with the higher price environment we increased our capital expenditures in 2022.

We used cash of $626.6 million in 2022 for the acquisition of oil and natural gas properties, primarily related to the Uinta Transaction, as compared to $115.1 million in 2021 which primarily related to the DJ Basin and Central Basin Acquisitions. We had non-cash acquisitions of $647.6 million in 2021 related to the Merger Transactions and the Titan Acquisition (see Our Combined and Consolidated Financial Statements—NOTE 3 - Acquisitions and Divestitures).

Contractual obligations

The following table presents our material contractual obligations at December 31, 2022:

[[GREPCENT_TABLE]]
[["(in thousands)","Due within one year","","Due after one year","","Total"],["Long-term debt \u2013 principal (1)","$","\u2014","","","$","1,259,449","","","$","1,259,449"],["Derivative liabilities","312,975","","","63,737","","","376,712"],["Asset retirement obligations (2)","18,746","","","346,868","","","365,614"],["Oil and natural gas transportation and gathering agreements (3)","13,542","","","27,377","","","40,919"],["Total","$","345,263","","","$","1,697,431","","","$","2,042,694"]]
[[/GREPCENT_TABLE]]

(1)Long-term debt represents our outstanding borrowings as of December 31, 2022 consisting of our 2026 Notes (maturing on May 1, 2026) and borrowings under our Revolving Credit Facility (maturing on September 23, 2027).

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(2)Amounts represent estimated discounted costs for future dismantlement and abandonment of our oil and natural gas properties. See “Notes to the combined and consolidated financial statements—NOTE 9 - Asset Retirement Obligation” for additional discussion of our asset retirement obligations.

(3)Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our oil and natural gas production to market, as well as, pipeline, processing and storage capacity.

General and Administrative Expense

Our general and administrative expense includes corporate overhead costs, professional service fees, insurance, software applications, fees for transaction expenses, expenses payable under the Management Agreement with KKR Energy Assets Manager LLC, incentive compensation award agreements granting profits interests, restricted stock units, performance stock units and other incentive awards granted to our employees and non-employee directors.

The incentive compensation portion relates to certain equity-classified and liability-classified profits interests awards issued by our subsidiaries (collectively, “Profits Awards”). These Profits Awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Compensation cost for these awards is presented within general and administrative expense on our combined and consolidated statements of operations. As of December 31, 2022, (i) unrecognized compensation cost related to unvested equity-classified profits interest awards was $67.5 million, and (ii) we carried $10.1 million in Other long term liabilities on the consolidated balance sheet and had unrecognized compensation of $3.7 million related to unvested liability-classified profits interest awards. Actual amounts paid towards equity-classified profits interests awards in the future will be shown as distributions to non-controlling interests in our consolidated financial statements, and may differ from the amounts shown for unrecognized compensation cost related to unvested equity-classified profits interest awards.

For additional information, see NOTE 13 – Incentive Compensation Arrangements in the notes to our audited financial statements for the year ended December 31, 2022 included herein.

Dividends

Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the indentures governing the Senior Notes.

We paid cash dividends of $0.63 per share of our Class A Common Stock to shareholders during the year ended December 31, 2022.

On March 7, 2023, the Board of Directors approved a quarterly cash dividend of $0.17 per share, or $0.68 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the fourth quarter of 2022. The quarterly dividend is payable on March 31, 2023 to shareholders of record as of the close of business on March 20, 2023. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.

Critical accounting estimates

Our significant accounting policies are described in NOTE 2 – Summary of Significant Accounting Policies, in "Item 8. Financial Statements and Supplementary Data" of this Annual Report. The Company's combined and consolidated financial statements are prepared in accordance with GAAP. The preparation of combined and consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of our combined and consolidated financial statements. These accounting policies, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of our control could have significant adverse impact to our financial condition, results of operations and cash flows.

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Crude oil, natural gas and NGL reserves

One of the most significant estimates the Company makes is the estimate of proved crude oil, natural gas and NGL reserves. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Our crude oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Technologies used in our reserves estimation includes decline curve analysis, statistical analysis of production performance, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. In addition, periodic revisions of our estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, crude oil and natural gas prices, changes in costs, capital funding and drilling plans (including our five-year development plan), technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.

When determining the December 31, 2022 proved reserves for each property, the benchmark prices issued by the SEC were adjusted using price differentials that account for property-specific quality and location differences. If the future average crude oil prices are below the average prices used to determine proved reserves at December 31, 2022, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see "Part I., Item 1A. Risk Factors."

Estimates of proved reserves are key components of our most significant financial estimates including the computation of depreciation, depletion and amortization ("DD&A") and impairment of proved oil and natural gas properties.

Oil and natural gas properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See “Notes to our Combined and Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies” in "Item 8. Financial Statements and Supplementary Data" of the Annual Report for further discussion of the accounting policies applicable to the successful efforts method of accounting.

The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

Depreciation, depletion and amortization

DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units-of-production method. During the years ended December 31, 2022, 2021, and 2020, we recognized DD&A expense of $532.9 million, $312.8 million, and $372.3 million, respectively.

While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates, any reduction in proved reserves, could result in an acceleration of future DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of oil and natural gas properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated

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undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:

•Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from our actual production.

•Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated at 2.5% thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.

•Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.

•Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.

During 2022, we determined that there was a triggering event requiring an evaluation of whether the carrying value of our oil and natural gas properties was recoverable as a result of our annual goodwill impairment test. Following an assessment of our oil and natural gas properties, we recorded impairment expense of $65.2 million during the year ended December 31, 2022. In March 2020, crude oil demand experienced significant declines due to the COVID-19 pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it become apparent that the pandemic would continue with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and recorded impairment expense of $247.2 million during the year ended December 31, 2020. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

We did not incur any impairment expense during the year ended December 31, 2021.

Properties acquired in business combinations

When sufficient market data is not available, we determine the fair values of proved and unproved oil and natural gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.

Significant reductions in the proved reserves used to determine the fair value of the acquired properties could result in future impairments of the properties. See the discussion above under "Depreciation, depletion and amortization: on the practicability of a sensitivity analysis due to changes in our fair value calculations.

Income taxes

Prior to the Merger Transactions, we were organized as Delaware limited liability companies and Delaware limited partnerships and were treated as flow-through entities for U.S. federal income tax purposes. As a result, our tax provision for the years ended December 31, 2021 and 2020 were minimal. Subsequent to the Merger Transactions, we are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if

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required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. Refer to NOTE 11 – Income Taxes in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for more information.

New and revised accounting standards

See “Notes to the combined and consolidated financial statements—NOTE 2-Summary of Significant Accounting Policies.”

Non-GAAP financial measures

Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes financial measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following:

•Adjusted EBITDAX; and

•Levered Free Cash Flow

These are supplemental non-GAAP financial measures used by our management to assess our operating results and assist us make our investment decisions. We believe that the presentation of these non-GAAP financial measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results.

We define Adjusted EBITDAX as net income (loss) before interest expense, realized (gain) loss on interest rate derivatives, income tax expense, depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivative contracts, impairment expense, non-cash equity-based compensation, (gain) loss on sale of assets, other (income) expense, certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation, transaction and nonrecurring expenses and early settlement of derivative contracts. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash deferred financing cost amortization, realized gain (loss) on interest rate derivatives, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions or proceeds received from asset sales. Levered Free Cash Flow is not a measure of performance as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP performance measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful performance measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies.

Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our combined and consolidated financial statements prepared in accordance with GAAP. For a reconciliation of these non-GAAP measures to the nearest comparable GAAP measures, see “—Results of Operations—Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)” above.

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