CRESCENT ENERGY CO Management’s Discussion and Analysis of Financial Condition and Results of Operations (Form 10-K)

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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, 2021 and 2020. Refer to our proxy
statement/prospectus (File No.
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333-258157), dated November 3, 2021 for discussion and analysis of the changes
in results of operations between the years ended December 31, 2020 and 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.

Company presentation

We are a well capitalized company we independent energy company with a portfolio of assets in proven key basins in the lower 48 states, including Eagle Ford, Rockies, Barnett, Permian and Mid-Con.

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.

Merge operations

On 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 Common
Stock, 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 December 31, 2021our results include only 25 days of impact for assets acquired in merger transactions.

Reorganizations

In 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.

Non-majority interests

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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 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 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 2020 Exchange"). Since we already consolidate the
results of these subsidiaries, this transaction was accounted for as a
reclassification of $657.4 million from 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 million to 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 Organization declared 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

In 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 Delaware limited 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 Texas limited 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 million in 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 Transaction or 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.

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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 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). 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 million to 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 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 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, Oklahoma 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.

In December 2019, we entered into a term assignment of oil and gas leases
conveying all of our interest in the Midland and Ector county leases between the
top of the Mississippian formation down to the base of the Woodford formation,
"deep rights", for total bonus consideration of $7.9 million and a primary term
of four years from the effective date, January 1, 2020.

In September 2019we entered into a purchase, sale and exchange agreement with an unaffiliated third party which included the sale of certain producing properties and the exchange of oil and gas leases in Eagle Ford for the consideration of $15.2 million and additional post-closing consideration of $1.8 million.

Environmental, social and corporate governance initiatives

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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's SASB Standard for
Oil & Gas - Exploration & Production and also established our key ESG
priorities. We also established an ESG Advisory Council to advise management and
Crescent Energy Company's Board 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 million to $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.

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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, 2021
compared 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 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. Although commodity prices increased during 2021, uncertainty
persists regarding OPEC's actions 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:

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                                                                 Year Ended December 31,
                                                             2021          2020         2019
  Oil (Bbl):
  Average NYMEX                                           $   68.04      $ 39.40      $ 57.03
  Realized price (excluding derivative settlements)           66.71        

37.45 57.14

Realized price (including derivative settlements) (1) 53.07 48.85 53.92

Natural Gas (Mcf):

  Average NYMEX                                           $    3.91      $  

2.08 $2.63

  Realized price (excluding derivative settlements)            3.96         

1.90 2.35

  Realized price (including derivative settlements)            3.06         

2.32 2.41

NGL (Bbl):

Realized price (excluding derivative settlements) $30.42 $13.77 $16.67

  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 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, 2021 compared to the year ended December 31, 2020

Revenue

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          $ 391,307                       80  %
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          $ 722,756                       96  %
Average realized prices, before effects of
derivative settlements:
Oil ($/Bbl)                                $        66.71          $   37.45          $   29.26                       78  %
Natural gas ($/Mcf)                        $         3.96          $    1.90          $    2.06                      108  %
NGLs ($/Bbl)                               $        30.42          $   13.77          $   16.65                      121  %
Total ($/Boe)                              $        41.55          $   22.72          $   18.83                       83  %
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  %



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Oil revenue. Oil revenue increased $391.3 million, or 80%, in 2021 compared to
2020, driven by $387.4 million of higher realized oil prices (an increase of
78%) and a $3.9 million increase 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 million of higher realized natural gas
prices (an increase of 108%), and a $20.7 million increase in sales volumes (30
MMcf/d, or 14%). The price increase was due in part to the severe winter storms
in February 2021 and 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 million of higher realized NGL prices (an increase of
121%) and a $14.1 million increase 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 $10.8 millioni.e. 25%, in 2021 compared to 2020, driven mainly by additional revenues from $4.3 million intermediate assets acquired during the acquisition of Titan, $2.7 million from rental premium income, and $1.2 million from additional intermediate processing income.

Expenses

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          $  114,500                      24  %
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          $     2.02                      13  %
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 $114.5 millioni.e. 24%, in 2021 compared to 2020, mainly driven by the following factors:

(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
million to the increase, the 2021 Acquisitions, which contributed $11.2 million
to 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.
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(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 million
associated with the Titan Acquisition, which included assets that have a higher
mix of natural gas and NGLs. This increase was offset by $12.0 million of
nonrecurring expense incurred during 2020 associated with the termination of a
midstream contract at our Eagle Ford business. In addition, during 2021, we
reached a settlement with a third-party operator to recoup $3.4 million of
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 $59.5 millionor 16%, compared to 2020, thanks to a reduction in the rate of our depreciation in 2020 offset by an increase in our total production resulting from the acquisition of Titan and the 2021 acquisitions.

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 million to 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 million primarily 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          $  61,800                      374  %



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 million gain on sale of assets during 2021, partially
offset by $2.2 million of additional midstream expenses from our Titan
Acquisition and $1.6 million of additional midstream expense from our 2021
Acquisitions.

Interest expense

In 2021, we incurred interest expense of $50.7 million, as compared to $38.1
million in 2020, a 33% increase. The increase was primarily driven by the
write-off of deferred financing charges associated with our Prior Credit
Agreements in May 2021 and 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 million from our Revolving
Credit Facility. The following table presents our total unrealized and realized
gain (loss) on derivatives for the periods presented:

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                                                  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              

38 107

Realized (gain) loss on interest rate
derivatives                                          7,373              

12,435

Income tax expense (benefit)                          (306)                 

14

Depreciation, depletion and amortization           312,787             

372,300

Exploration expense                                  1,180                 

486

Non-cash (gain) loss on derivatives                330,368             

(10,910)

Impairment of oil and natural gas properties             -             

247 215

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              

22,679

Early settlement of derivative contracts (2)       198,688                  

Adjusted EBITDAX (non-GAAP)                  $     520,051          $  465,064          $   54,987                      12   %
Adjustments to reconcile to Levered Free
Cash Flow:
Interest expense, excluding non-cash
deferred financing cost amortization               (40,551)            

(33,166)

Realized (gain) loss on interest rate
derivatives                                         (7,373)            

(12,435)

Current income tax provision                          (629)                

(14)

Current tax-related redeemable
noncontrolling interest distributions by
OpCo                                                     -                  

Development of oil and natural gas
properties                                        (194,828)           

(110,126)

Levered Free Cash Flow (non-GAAP)            $     276,670          $  309,323          $  (32,653)                    (11  %)




(1)Transaction expenses of $23.1 million during the year ended December 31, 2021
were primarily related to legal, consulting and other fees incurred for the
Noncontrolling Interest Carve-out, the April 2021 Exchange and the Merger
Transactions, partially offset by $3.4 million received in connection with a
midstream legal settlement. Transaction expenses of $22.7 million for the year
ended December 31, 2020 included (i) $7.9 million related to the formation of
Independence, the Titan Acquisition and the related reorganization transactions,
(ii) $12.0 million for the termination of a midstream contract at our Eagle Ford
business, (iii) $1.9 million of severance costs and (iv) $0.9 million for
settlement of a royalty owner lawsuit.
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(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 $55.0 million or 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 $32.7 million i.e. 11% in 2021 compared to 2020, mainly driven by $84.7 million higher capital expenditures related to 2021 development activities following higher raw material prices, partially offset by an increase in adjusted EBITDA of $55.0 million.

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      $ 36,861
                 Long-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:

                                                             Year Ended 

the 31st of December,

 (in thousands)                                                2021         

2020

 Net cash provided by operating activities             $     233,147        

$411,028

 Net cash used in investing activities                      (244,595)       

(124,940)

Net cash (used in) provided by financing activities 105 145

    (272,089)



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Net cash from operating activities. Net cash provided by operating activities for the year ended December 31, 2021 decreased by $177.9 millioni.e. 43%, compared to 2020, mainly due to cash payments of $198.7 million
related to the early settlement of certain commodity derivative contracts outstanding in June 2021.

Net cash used in investing activities. Net cash used in investing activities for
the year ended December 31, 2021 increased by $119.7 million, or 96%, compared
to 2020, primarily due to $115.1 million net cash used in the 2021 Acquisitions
and $29.4 million of additional development capital expenditures. These uses of
cash were partially offset by $16.4 million additional 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, 2021 was $105.1 million, as
compared to $272.1 million net 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 million in 2020.

Debt agreements

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 December 31, 2020 and 2019 and by the termination of previous credit agreements in May 2021.

Senior Notes

On May 6, 2021, Crescent Finance issued $500.0 million aggregate principal
amount of the Senior Notes. The Senior 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.

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, 2023 at certain redemption prices. We may also redeem up to
40% of the aggregate principal amount of the Senior 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 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 2022 Crescent Finance issued an additional $200.0 million aggregate
principal amount of our Senior Notes (the "New Notes"). The New Notes were
issued as additional notes pursuant to our $500.0 million issuance in May 2021
described
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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 million and $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 million to $700.0
million, increased our borrowing base from $850.0 million to $1.3 billion and
permitted the issuance of up to $300 million of 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 million of outstanding
borrowings under the Revolving Credit Facility and $20.7 million in 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, 2021 was 3.125%.

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.

Capital expenditure

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.
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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          $  315,430
Change 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          $  

580 763 $338,646



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 million in 2021 for the acquisition of oil and natural gas
properties, primarily related to our DJ Basin and Central Basin Acquisitions,
and had non-cash acquisitions of $647.6 million and $454.6 million in 2021 and
2020 related to our 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, 2021:

                                                        Due within           Due after
(in thousands)                                           one year             one year              Total
Long-term debt - principal (1)                         $        -          $ 1,043,000          $ 1,043,000
Derivative 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, 2021
consisting 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.

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Dividends

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 $0.12 per
share, or $0.48 per 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, 2022 to 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, 2021 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, 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
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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 December 31, 20212020 and 2019, we recorded DD&A charges of $312.8 million, $372.3 millionand $311.2 millionrespectively.

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.

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 have not incurred any impairment charges during the years ended December 31, 2021
and 2019.

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
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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, 2020 and 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 we GAAP. These non-GAAP measures include the following:

•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
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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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