Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") 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 Part II, Item 8 of Part II of this Annual Report and also with "Risk Factors" in Item 1A 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, 2021and 2020. Refer to our proxy statement/prospectus (File No. 67
November 3, 2021for discussion and analysis of the changes in results of operations between the years ended December 31, 2020and 2019. 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.
We are a well capitalized company
Our approach includes a cash flow-based investment mandate focused on operated working interests and is complemented by non-operating working interests, mining and royalty interests and midstream infrastructure, as well as an active asset management strategy. risks. We are pursuing our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.
December 7, 2021, we completed the Merger Transactions, pursuant to which Contango's business combined with Independence's business under a new publicly traded holding company named " Crescent Energy Company." Our 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 Crescent Finance, the issuer of the Senior Notes) and those of Contango held by us, as the sole managing member of OpCo and indirect sole managing member of Crescent Finance. Former Contango shareholders now own shares of our Class A Common Stock, which has both voting and economic rights with respect to our Company. The former owners of Independence now own OpCo Units and Class B CommonStock, which have voting (but no economic) rights with respect to our Company. We are a holding company. Our sole material assets consist of OpCo Units. We are the sole managing member of OpCo and are responsible for all operational, management and administrative decisions relating to OpCo's business and consolidate the financial results of OpCo and its subsidiaries, including Crescent Finance, the issuer of the Senior Notes.
For year ended and month ended
August 2020, through a series of transactions, we underwent a reorganization (the "Independence Reorganization") in connection with the Titan Acquisition, carried out under the direction of Independence's Managing Member, as provided within its Amended and Restated Limited Liability Company Agreement dated August 18, 2020, whereby certain entities previously owned and under the common control of affiliates of the KKR Group(the "Contributed Entities") were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Independence Reorganization, which is the date we obtained a controlling financial interest in the Contributed Entities on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Independence Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. The merger of Independence with and into OpCo on December 7, 2021, (as a part of the Merger Transactions) was also accounted for as a reorganization of entities under common control. Because the Independence Reorganization and the Merger Transactions resulted in changes in the reporting entity, and in order to furnish comparative financial information prior to the Independence Reorganization and the Merger Transactions, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities and Independence, our accounting predecessor (the "Predecessor"), on a combined basis.
We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations. In
April 2021, certain minority interest owners exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of our Predecessor's Class A Units as part of the April 2021Exchange. 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 exchange. In December 2020, certain owners of noncontrolling equity interests in certain of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Predecessor's Class A Units (the " December 2020Exchange"). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 millionfrom noncontrolling interest to members' equity with no gain or loss recognized on the exchange. In August 2020, in connection with the Independence Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Predecessor. These interests were reclassified from members' equity to noncontrolling interest as of the date of the Independence Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests for the period from the date of the Independence Reorganization through the year-ended December 31, 2021. In May 2021, these noncontrolling equity interests were redeemed 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 millionto repay its proportionate share of the underlying debt outstanding under the various agreements to which certain of our operating subsidiaries had historically been party to (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%.
Impact of COVID-19
In early 2020, the
World Health Organizationdeclared the COVID-19 outbreak a pandemic. There have been mandates from international, federal, state and local authorities requiring forced closures of various schools, businesses and other facilities and organizations. Our workforce worked remotely for a period of time since the pandemic began. Working remotely did not significantly impact our ability to maintain operations and did not cause us to incur significant additional expenses. The initial spread of the COVID-19 virus in 2020 had a negative impact on the global demand for oil and natural gas, 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 since the beginning of 2021. However, 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.
Acquisitions, divestitures and related reorganizations
Related acquisitions and reorganizations
February 2022, we entered into a Membership Interest Purchase Agreement (the "Purchase Agreement" and the transactions contemplated therein, the "Uinta Transaction") with Verdun Oil Company II LLC, a Delawarelimited liability company (the "Seller"), pursuant to which we agreed to purchase from Seller all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a to-be formed Texaslimited liability company which will hold all exploration and production assets of and certain obligations of EP Energy E&P Company, L.P.("EP") located in the State of Utah(the "Utah Assets"). Upon closing of the Uinta Transaction, Seller will receive aggregate consideration of approximately $815 millionin cash and the assumption of certain hedges, subject to certain customary purchase price adjustments set forth in the Purchase Agreement. The Uinta Transaction is subject to customary closing conditions, including approval by the US Federal Trade Commission of the Transactionor the expiration or termination of any applicable waiting period under the HSR Act (as defined in the Purchase Agreement), and the closing of a transaction between Seller and EP pursuant to which Seller will receive the Utah Assets. 69
In connection with the closing of the Uinta Transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to
$1.3 billion. However, there can be no assurances we will consummate the Uinta Transaction or that we will enter into such amendment to our Revolving Credit Facility. In December 2021, we acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texasand 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). We accounted for the Central Basin Platform Acquisition as an asset acquisition. 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 as part of the "Noncontrolling Interest Carve-out". Additionally, the third-party investor contributed cash of approximately $35.5 millionto repay its proportionate share of the underlying debt outstanding under 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 our Class A Units, representing 0.77% of our consolidated ownership pursuant to (the " April 2021Exchange"). 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 2021Exchange. In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basinfrom an unrelated third-party operator for total consideration of $60.8 million(the "DJ Basin Acquisition"). The DJ BasinAcquisition was funded using cash on hand and borrowings under our Prior CreditAgreements. 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, LLCto 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 millionof equity consideration in the form of 0.4 million Class A units of our Predecessor. Divestitures In December 2021, we entered into an assignment, conveyance and bill of sale with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Payne County, Oklahomain 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 Basinin exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 milliongain 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. In December 2019, we entered into a term assignment of oil and gas leases conveying all of our interest in the Midlandand Ector countyleases between the top of the Mississippian formation down to the base of the Woodfordformation, "deep rights", for total bonus consideration of $7.9 millionand a primary term of four years from the effective date, January 1, 2020.
Environmental, social and corporate governance initiatives
We are committed to developing industry-leading ESG programs and continually improving our ESG performance. We view exceptional ESG performance as an opportunity to differentiate Crescent from our peers, provide for increased access to capital markets, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In
December 2021, we released our inaugural ESG report, which included key performance metrics according to Value Reporting Foundation'sSASB Standard for Oil & Gas - Exploration & Production and also established our key ESG priorities. We also established an ESG Advisory Councilto advise management and Crescent Energy Company'sBoard of Directors on ESG-related issues. We are working to reduce greenhouse gas ("GHG") emissions by implementing aggressive methane reduction targets and eliminating routine flaring, among other initiatives.
How we evaluate our operations
We use a variety of financial and operational measures to assess the performance of our oil, natural gas and NGL operations, including:
•Volumes of production sold;
•Raw material prices and differentials;
•Operating Expenses ;
•Adjusted EBITDAX (non-GAAP); and
• Leveraged free cash flow (non-GAAP)
Development program and investment 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
$375 millionto $425 million, excluding acquisition capital and any development capital related to acquisitions, for our 2022 capital program. Our program is allocated 70 to 75% to our operated assets primarily in the Eagle Ford, 15 to 20% to non-operated activity and approximately 10% to other capital expenditures. We expect to fund our 2022 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that our acreage is 98% 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 income
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 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: Year Ended December 31, 2021 2020 2019 Oil 62 % 69 % 75 % Natural gas 25 % 21 % 17 % NGLs 13 % 10 % 8 % 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, 2021, 2020 and 2019. 71
Production volumes sold
The following table shows the historical sales volumes of our properties:
Year Ended December 31, 2021 2020 2019 Oil (MBbls) 13,237 13,132 13,752 Natural gas (MMcf) 89,455 78,541 73,747 NGLs (MBbls) 6,099 5,078 5,188 Total (MBoe) 34,245 31,300 31,232 Daily average (MBoe/d) 94 86 86 Total sales volume increased 2,945 MBoe during the year ended
December 31, 2021compared to 2020. The increase is primarily due to the Titan Acquisition, which contributed an additional 5,912 MBoe, and the DJ Basin Acquisition, Central Basin Platform Acquisition and Merger Transactions (combined the "2021 Acquisitions"), which contributed an additional 1,266 MBoe. Sales volumes from our other assets decreased by 4,233 MBoe primarily due to the natural decline from our existing asset base that resulted from the reduction in development capital expenditures in 2020 as a response to the low commodity price environment.
Commodity prices and differentials
Our results of operations depend on many factors, including commodity prices and our ability to effectively market our production.
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
OPECcaused 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. Although commodity prices increased during 2021, uncertainty persists regarding OPEC'sactions and continued effect from the COVID-19 pandemic. 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 shows the percentages of our production economically hedged by the use of derivative contracts:
Year Ended December 31, 2021 2020 2019 Oil 81 % 81 % 74 % Natural gas 83 % 76 % 81 % NGLs 67 % 60 % 55 %
The following table sets forth NYMEX average oil and natural gas prices and our average realized prices for the periods presented:
T able of Contents Year Ended December 31, 2021 2020 2019 Oil (Bbl): Average NYMEX
$ 68.04 $ 39.40 $ 57.03Realized price (excluding derivative settlements) 66.71
Realized price (including derivative settlements) (1) 53.07 48.85 53.92
Natural Gas (Mcf):
Realized price (excluding derivative settlements) 3.96
Realized price (including derivative settlements) 3.06
Realized price (excluding derivative settlements)
Realized price (including derivative settlements) 19.15 16.61 19.18 (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 millionin June 2021. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.
Results of operations:
The following table shows the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:
Year Ended December 31, 2021 2020 $ Change % Change Revenues (in thousands): Oil
$ 883,087 $ 491,780 $ 391,30780 % Natural gas 354,298 149,317 204,981 137 % Natural gas liquids 185,530 69,902 115,628 165 % Midstream and other 54,062 43,222 10,840 25 % Total revenues $ 1,476,977 $ 754,221 $ 722,75696 % Average realized prices, before effects of derivative settlements: Oil ($/Bbl) $ 66.71 $ 37.45 $ 29.2678 % Natural gas ($/Mcf) $ 3.96 $ 1.90 $ 2.06108 % NGLs ($/Bbl) $ 30.42 $ 13.77 $ 16.65121 % Total ($/Boe) $ 41.55 $ 22.72 $ 18.8383 % Net sales volumes: Oil (MBbls) 13,237 13,132 105 1 % Natural gas (MMcf) 89,455 78,541 10,914 14 % NGLs (MBbls) 6,099 5,078 1,021 20 % Total (MBoe) 34,245 31,300 2,945 9 % Average daily net sales volumes: Oil (MBbls/d) 36 36 - - % Natural gas (MMcf/d) 245 215 30 14 % NGLs (MBbls/d) 17 14 3 21 % Total (MBoe/d) 94 86 8 9 % 73
Oil revenue. Oil revenue increased
$391.3 million, or 80%, in 2021 compared to 2020, driven by $387.4 millionof higher realized oil prices (an increase of 78%) and a $3.9 millionincrease in sales volumes (0.3 MBbl/d, or 1%). The increase in sales volumes was primarily driven by our Titan Acquisition (1,708 MBbls of the increase) and our 2021 Acquisitions (430 MBbls of the increase), partially offset by the natural decline from our existing assets that resulted from the reduction in development capital expenditures in 2020. Natural gas revenue. Natural gas revenue increased $205.0 million, or 137%, in 2021 compared to 2020, driven by $184.3 millionof higher realized natural gas prices (an increase of 108%), and a $20.7 millionincrease in sales volumes (30 MMcf/d, or 14%). The price increase was due in part to the severe winter storms in February 2021and the increase in sales volumes was primarily driven by our Titan Acquisition (15,807 MMcf of the increase) and our 2021 Acquisitions (4,060 MMcf of the increase), partially offset by the natural decline from our existing assets. NGL revenue. NGL revenue increased $115.6 million, or 165%, in 2021 compared to 2020, driven by $101.5 millionof higher realized NGL prices (an increase of 121%) and a $14.1 millionincrease in sales volumes (3 MBbl/d, or 20%). The increase in sales volumes was primarily driven by our Titan Acquisition (1,570 MBbls of the increase) and our 2021 Acquisitions (159 MBbls) partially offset by the natural decline from our existing assets.
Intermediate and other income. Middle and other incomes increased
The following table summarizes our expenditures for the periods indicated and includes a presentation by boe, as we use this information to assess our performance against our peers and to identify and measure trends that we believe may require further analysis:
Year Ended December 31, 2021 2020 $ Change % Change Expenses (in thousands): Operating expense
$ 596,334 $ 481,834 $ 114,50024 % Depreciation, depletion and amortization 312,787 372,300 (59,513) (16 %) Impairment of oil and natural gas properties - 247,215 (247,215) NM* General and administrative expense 78,342 16,542 61,800 374 % Other operating costs 5,775 9,958 (4,183) (42 %) Total expenses $ 993,238 $ 1,127,849 $ (134,611)(12 %) Expenses per Boe: Operating expense $ 17.41 $ 15.39 $ 2.0213 % Depreciation, depletion and amortization 9.13 11.89 (2.76) (23 %) Impairment of oil and natural gas properties - 7.90 (7.90) NM* General and administrative expense 2.29 0.53 1.76 332 % Other operating costs 0.17 0.32 (0.15) (47 %) Total expenses per Boe $ 29.00 $ 36.03 $ (7.03)(20 %) *NM = Not meaningful.
Exploitation charges. Total operating expenses increased
(i)Total lease and asset operating expenses increased
$48.2 million, or 20%, in 2021 compared to 2020. This increase was driven primarily by higher production during 2021, due in part to the Titan Acquisition, which contributed $16.4 millionto the increase, the 2021 Acquisitions, which contributed $11.2 millionto the increase, and certain costs are indexed to oil commodity prices, such as CO2 purchase costs related to our CO2 flood asset in Wyoming. These commodity indexed operating expenses move in tandem with oil commodity prices and are partially offset by changes in our price realizations. 74
(ii)Gathering, transportation and marketing expense increased
$13.9 million, or 8%, in 2021 compared to 2020. This increase was driven primarily by increased production and higher gathering and processing expenses of $35.8 millionassociated with the Titan Acquisition, which included assets that have a higher mix of natural gas and NGLs. This increase was offset by $12.0 millionof nonrecurring expense incurred during 2020 associated with the termination of a midstream contract at our Eagle Fordbusiness. In addition, during 2021, we reached a settlement with a third-party operator to recoup $3.4 millionof disputed gathering charges that we had paid in historical periods. (iii)Production and other taxes increased $47.9 million, or 78%, in 2021 compared to 2020, 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 $4.5 million, or 70%, due to higher well workover activity.
Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased
Impairment of oil and natural gas properties. In 2020, because of significant declines in crude prices as a result of the COVID-19 pandemic, we recorded an impairment charge of
$247.2 millionto oil and natural gas properties. We did not record impairment expense in 2021 or 2019. See Part II, Item 8. "Notes to the combined and consolidated financial statements - NOTE 6 - Fair Value Measurements" for additional discussion regarding the impairment in 2020. General and administrative expense. General and administrative expense increased $61.8 million, or 374%, in 2021 compared to 2020, driven primarily by an increase in our equity-based compensation of $40.7 millionprimarily due to the Merger Transactions and the additional cost recognized due to the modification of Contango equity-classified PSUs (see Item 8. Financial Statements, NOTE 13 - Incentive Compensation Arrangements for additional information) and an increase in legal, accounting and other nonrecurring transaction-related costs of $21.1 million. Year Ended December 31, 2021 2020 $ Change % Change General and administrative expense (in thousands) Recurring general and administrative expense $ 14,359 $ 14,339 $ 20- % Nonrecurring and transaction expenses 24,064 3,000 21,064 702 % Equity-based compensation 39,919 (797) 40,716 5109 % Total expense $ 78,342 $ 16,542 $ 61,800374 % Other operating costs. Other operating costs include midstream operating expense, exploration expense and gain on sale of assets. Other operating costs decreased $4.2 million, or 42%, in 2021 compared to 2020, driven primarily by the recognition of a $8.8 milliongain on sale of assets during 2021, partially offset by $2.2 millionof additional midstream expenses from our Titan Acquisition and $1.6 millionof additional midstream expense from our 2021 Acquisitions.
In 2021, we incurred interest expense of
$50.7 million, as compared to $38.1 millionin 2020, a 33% increase. The increase was primarily driven by the write-off of deferred financing charges associated with our Prior CreditAgreements in May 2021and higher interest rates associated with the issuance of the Senior Notes in April of 2021.
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. In
June 2021, we settled certain of our outstanding derivative oil contracts associated with calendar years 2022 and 2023 for $198.7 million, using cash on hand and borrowings of $160.0 millionfrom our Revolving Credit Facility. The following table presents our total unrealized and realized gain (loss) on derivatives for the periods presented: 75
T able of Contents Year Ended December 31, 2021 2020 $ Change % Change Gain (loss) on derivatives (in thousands) Gain (loss) on commodity derivatives
$ (865,994) $ 205,645 $ (1,071,639)(521 %) Gain (loss) on interest rate derivatives (26) (10,361) 10,335 (100 %) Total gain (loss) on derivatives $ (866,020) $ 195,284 $ (1,061,304)(543 %)
Adjusted EBITDAX (non-GAAP) and leveraged 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 provides a reconciliation of Adjusted EBITDAX (non-GAAP) and leveraged free cash flow (non-GAAP) to net income, the most directly comparable financial measure calculated in accordance with GAAP:
Year Ended December 31, 2021 2020 $ Change % Change (in thousands) Net income (loss)
$ (432,227) $ (216,124) $ (216,103)100 % Adjustments to reconcile to Adjusted EBITDAX: Interest expense 50,740
Realized (gain) loss on interest rate derivatives 7,373
Income tax expense (benefit) (306)
Depreciation, depletion and amortization 312,787
Exploration expense 1,180
Non-cash (gain) loss on derivatives 330,368
Impairment of oil and natural gas properties -
Non-cash equity-based compensation expense 39,919 (797) (Gain) loss on sale of assets (8,794) - Other (income) expense (120) (341) Certain redeemable noncontrolling interest distributions made by OpCo related to Management Compensation (2,706)
Transaction and nonrecurring expenses (1) 23,149
Early settlement of derivative contracts (2) 198,688
Adjusted EBITDAX (non-GAAP)
$ 520,051 $ 465,064 $ 54,98712 % Adjustments to reconcile to Levered Free Cash Flow: Interest expense, excluding non-cash deferred financing cost amortization (40,551)
Realized (gain) loss on interest rate derivatives (7,373)
Current income tax provision (629)
Current tax-related redeemable noncontrolling interest distributions by OpCo -
Development of oil and natural gas properties (194,828)
Levered Free Cash Flow (non-GAAP)
$ 276,670 $ 309,323 $ (32,653)(11 %) (1)Transaction expenses of $23.1 millionduring the year ended December 31, 2021were primarily related to legal, consulting and other fees incurred for the Noncontrolling Interest Carve-out, the April 2021Exchange and the Merger Transactions, partially offset by $3.4 millionreceived in connection with a midstream legal settlement. Transaction expenses of $22.7 millionfor the year ended December 31, 2020included (i) $7.9 millionrelated to the formation of Independence, the Titan Acquisition and the related reorganization transactions, (ii) $12.0 millionfor the termination of a midstream contract at our Eagle Fordbusiness, (iii) $1.9 millionof severance costs and (iv) $0.9 millionfor settlement of a royalty owner lawsuit. 76
(2)Represents the settlement in
June 2021of 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 $55.0 millionor 12% in 2021, compared to 2020, primarily 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 the Titan Acquisition and our 2021 Acquisitions. This increase was partially offset by a corresponding increase in lease operating expense and production tax from increased production volumes and commodity prices, as well as realized losses on our commodity derivatives in 2021 compared to 2020.
Leveraged Free Cash Flow decreased by
Cash 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 and 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. Our 2021 capital program reflected that flexibility; our capital expenditures incurred during the second half of 2021 were higher than the first half of 2021 as we elected to increase capital spend as the commodity price environment improved. 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 shows our cash balances and outstanding borrowings at the end of each period presented:
At December 31, (in thousands) 2021 2020 Cash and cash equivalents
$ 128,578 $ 36,861Long-term debt 1,030,406 751,075 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:
(in thousands) 2021
Net cash provided by operating activities
Net cash used in investing activities (244,595)
Net cash (used in) provided by financing activities 105 145
Net cash from operating activities. Net cash provided by operating activities for the year ended
related to the early settlement of certain commodity derivative contracts outstanding in
Net cash used in investing activities. Net cash used in investing activities for the year ended
December 31, 2021increased by $119.7 million, or 96%, compared to 2020, primarily due to $115.1 millionnet cash used in the 2021 Acquisitions and $29.4 millionof additional development capital expenditures. These uses of cash were partially offset by $16.4 millionadditional cash proceeds in 2021 from our divestitures. Net cash provided by (used in) financing activities. Net cash provided by financing activities for the year ended December 31, 2021was $105.1 million, as compared to $272.1 millionnet cash used in financing activities in 2020. The increase was primarily due to net cash inflows as a result of our debt borrowings exceeding our repayments during 2021 compared to net long-term debt repayments cash outflow of $224.4 millionin 2020.
Previous credit agreements
Certain of our subsidiaries entered into the Prior Credit Agreements with syndicates of lenders with original expiration dates between 2022 and 2024. The amounts we were able to borrow under each of the Prior Credit Agreements was limited by a borrowing base, which was based on our oil and natural gas properties, proved reserves and total indebtedness, as well as other factors, and was consistent with customary lending criteria. On
May 6, 2021, we terminated the Prior Credit Agreements with the proceeds from the issuance of the Senior Notes and the Noncontrolling Interest Carve-Out and borrowings under the Revolving Credit Facility (as discussed below).
The prior credit agreements contained certain covenants limiting the payment of cash dividends, certain borrowings, sales of assets, loans to third parties, investments, merger activities, commodity swap agreements, liens and other transactions. We complied with the clauses of credit agreements prior to the
May 6, 2021, Crescent Finance issued $500.0 millionaggregate principal amount of the Senior Notes. The Senior Notes bear interest at an annual rate of 7.250%, which is payable on May 1and November 1of each year and mature on May 1, 2026. 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. We may, at our option, redeem all or a portion of the Senior Notes at any time on or after May 1, 2023at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the Senior Notes before May 1, 2023with 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 Senior 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 Senior 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. 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. In February 2022Crescent Finance issued an additional $200.0 millionaggregate principal amount of our Senior Notes (the "New Notes"). The New Notes were issued as additional notes pursuant to our $500.0 millionissuance in May 2021described 78
above. The New Notes will be treated as a single series and will vote together as a single class with the Senior Notes, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment, as the Senior Notes. Revolving Credit Facility In connection with the issuance of the Senior Notes, Crescent Finance entered into a credit agreement (as amended, restated or otherwise modified to date, the "Revolving Credit Facility") with
Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The initial committed amount and borrowing base under the Revolving Credit Facility are $500.0 millionand $850.0 million, respectively. The Revolving Credit Facility matures on May 6, 2025. In September 2021, we entered into the first amendment to the Revolving Credit Facility, which amongst other things, increased our committed amount from $500.0 millionto $700.0 million, increased our borrowing base from $850.0 millionto $1.3 billionand permitted the issuance of up to $300 millionof additional senior notes (including the New Notes described above) without causing a reduction in our borrowing base. At December 31, 2021, we had $543.0 millionof outstanding borrowings under the Revolving Credit Facility and $20.7 millionin outstanding letters of credit. In connection with the closing of the Uinta Transaction, we anticipate entering into an amendment to our Revolving Credit Facility to, among other things, increase the elected commitment amount to $1.3 billion. However, there can be no assurances we will consummate this transaction or that we will enter into such amendment to our Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at either a U.S.dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted LIBOR), plus an applicable margin or LIBOR, 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, 2021was 3.125%. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1and October 1of 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.
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. 79
We expect to fund our 2022 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 shows our capital expenditures and related metrics we use to assess our business for the periods presented:
Year Ended December 31, (in thousands) 2021 2020 2019 Total development of oil and natural gas properties
$ 194,828 $ 110,126 $ 315,430Change in accruals and other non-cash adjustments (39,221) 16,038 23,216 Cash used in development of oil and natural gas properties 155,607 126,164 338,646 Cash used in acquisition of oil and natural gas properties 115,076 - - Non-cash acquisition of oil and natural gas properties 647,579 454,599 - Total expenditure on acquisition and development of oil and natural gas properties $ 918,262$
Our development of oil and natural gas properties was higher during the year ended
December 31, 2021, compared to the year ended December 31, 2020. 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 have resumed development activities in 2021 as commodity prices have recovered. We used cash of $115.1 millionin 2021 for the acquisition of oil and natural gas properties, primarily related to our DJ Basinand Central Basin Acquisitions, and had non-cash acquisitions of $647.6 millionand $454.6 millionin 2021 and 2020 related to our Merger Transactions and the Titan Acquisition (see Our Combined and Consolidated Financial Statements-NOTE 3 - Acquisitions and Divestitures).
The following table presents our material contractual obligations at
December 31, 2021: Due within Due after (in thousands) one year one year Total Long-term debt - principal (1) $ - $ 1,043,000 $ 1,043,000Derivative liabilities 253,525 133,471 386,996 Asset retirement obligations (2) 7,905 258,102 266,007
Process, transport and storage contracts (3) 105,606
303,143 408,749 Total
$ 367,036 $ 1,737,716 $ 2,104,752(1)Long-term debt represents our outstanding borrowings as of December 31, 2021consisting of our Senior Notes (maturing on May 1, 2026) and borrowings under our Revolving Credit Facility (maturing on May 6, 2025). (2)Amounts represent estimated discounted costs for future dismantlement and abandonment of our crude 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 natural gas production to market, as well as, pipeline, processing and storage capacity. 80
We target future dividends to shareholders of 10% of Adjusted EBITDAX, but payments will 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 indenture governing the Senior Notes. On
March 9, 2022, the Board approved a quarterly cash dividend of $0.12per share, or $0.48per share on an annualized basis, to be paid to our shareholders with respect to the fourth quarter of 2021. The quarterly dividend is payable on March 31, 2022to shareholders of record as of the close of business on March 18, 2022. 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 of Part II 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.
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, 2021proved reserves for each property, the benchmark prices issued by the SECwere 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, 2021, 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 elements of our most important financial estimates, including the calculation of depreciation, depletion and amortization (DD&A) and depreciation of proven crude oil and natural gas properties. .
Oil and gas properties
Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See Part II, Item 8. Financial Statements of this Annual Report, "Notes to our Combined and Consolidated Financial Statements-NOTE 2 - Summary of Significant Accounting Policies" 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 81
the amount and timing of costs amortized, depreciated, or amortized to profit or loss and the disclosure of additional information about oil and gas production activities. In addition, the expected future cash flows to be generated by producing properties used for impairment testing are also based in part on estimates of net reserve quantities.
Depreciation, depletion and amortization
The DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units of production method. Over the years ended
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 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 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 achieving projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.
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 millionduring 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 have not incurred any impairment charges during the years ended
Buildings acquired as part of 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 82
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.
Prior to the Merger Transactions, we were organized as
Delawarelimited liability companies and Delawarelimited 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, 2020and 2019 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 assesses 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 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 10 - Income Taxes in Part II, Item 8 of this Annual Report for more information.
New and revised accounting standards
See “Notes to 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
•Adjusted EBITDAX; and
• Leveraged 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 of oil and natural gas properties, non-cash equity-based compensation, write-offs of other long-term assets, (gain) loss on sale of assets, other (income) expense, certain redeemable noncontrolling interest distributions made by OpCo related to Management 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 83
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 (provision), 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. 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.
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