PDC Energy (PDCE) 8-K/A Index to Consolidated Financial Statements

EXHIBIT 99.1

Annual Report

Consolidated financial statements as of December 31, 2021 (Successor) and 2020 (Predecessor) and for the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
GREAT WESTERN PETROLEUM, LLC
Reports of Independent Auditors
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2021 (Successor) and 2020 (Predecessor)	F-1
Consolidated Statements of Operations for the Period from February 23, 2021 through December 31, 2021 (Successor) and from January 1, 2021 through February 22, 2021 (Predecessor), and for the Year Ended December 31, 2020 (Predecessor)	F-2
Consolidated Statements of Members’ Equity for the Period from February 23, 2021 through December 31, 2021 (Successor) and from January 1, 2021 through February 22, 2021 (Predecessor), and for the Year Ended December 31, 2020 (Predecessor)	F-3
Consolidated Statements of Cash Flows for the period February 23, 2021 through December 31, 2021 (Successor) and from January 1, 2021 through February 22, 2021 (Predecessor), and for the Year Ended December 31, 2020 (Predecessor)	F-4
Notes to the Consolidated Financial Statements	F-5
Supplemental Oil and Natural Gas Information (Unaudited)	F-26

Report of Independent Auditors

To the Board of Managers of Great Western Petroleum, LLC

We have audited the accompanying consolidated financial statements of Great Western Petroleum, LLC and its subsidiaries (Predecessor Company), which comprise the consolidated balance sheet as of December 31, 2020 and the related consolidated statements of operations, of changes in members' equity and of cash flows for the period from January 1, 2021 to February 22, 2021, and for the year ended December 31, 2020.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Great Western Petroleum, LLC and its subsidiaries (Predecessor Company) as of December 31, 2020 and the results of their operations and their cash flows for the period from January 1, 2021 to February 22, 2021, and for the year ended December 31, 2020 in accordance with accounting principles generally accepted in the United States of America.

Denver, Colorado

March 10, 2022

Report of Independent Auditors

To the Board of Managers of Great Western Petroleum, LLC

Opinion

We have audited the accompanying consolidated financial statements of Great Western Petroleum, LLC and its subsidiaries (Successor) (the “Company”), which comprise the consolidated balance sheet as of December 31, 2021 and the related consolidated statements of operations, of changes in members' equity and of cash flows for the period from February 23, 2021 to December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”).

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and the results of its operations and its cash flows for the period from February 23, 2021 to December 31, 2021 in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audit in accordance with auditing standards generally accepted in the United States of America (US GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the financial statements are available to be issued.

Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with US GAAS, we:

•Exercise professional judgment and maintain professional skepticism throughout the audit.

•Identify and assess the risks of material misstatement of the consolidated financial statements,whether due to fraud or error, and design and perform audit procedures responsive to those risks.Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.

•Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, no such opinion is expressed.

•Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements.

•Conclude whether, in our judgment, there are conditions or events, considered in the aggregate,that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

Other Information

Management is responsible for the other information included in the annual report. The other information comprises management’s discussion and analysis of financial condition and results of operations, but does not include the consolidated financial statements and our auditors' report thereon. Our opinion on the consolidated financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the consolidated financial statements or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report.

/s/PricewaterhouseCoopers LLP

Denver, Colorado

March 10, 2022

GREAT WESTERN PETROLEUM, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS EXCEPT PER SHARE INFORMATION)

	(Successor)		(Predecessor)
	December 31,		December 31,
	2021		2020
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	34,104	$	38,335
Accounts receivable	110,258		71,949
Derivative instruments	226		22,776
Prepaid expenses and other assets	25,630		15,061
Total current assets	170,218		148,121
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method, net	1,459,144		1,654,300
Other property and equipment	7,964		8,583
Total property, plant and equipment, net	1,467,108		1,662,883
NON-CURRENT ASSETS:
Restricted cash	8,080		8,080
Investment in unconsolidated entity	18,906		19,031
Derivative instruments	3,102		—
Other assets	8,253		8,054
Total assets	$	1,675,667	$	1,846,169
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accrued liabilities	$	216,930	$	136,884
Accounts payable	17,143		13,403
Production taxes payable	42,940		56,355
Current portion of asset retirement obligations	7,297		6,984
Derivative instruments	103,495		2,871
Debt, net	—		251,981
Unit appreciation rights liability	—		2,852
Other liabilities	507		1,267
Total current liabilities	388,312		472,597
NON-CURRENT LIABILITIES:
Revolving credit facility	242,000		339,000
Debt, net	300,883		72,992
Production taxes payable	79,053		38,023
Asset retirement obligations	4,749		9,697
Derivative instruments	3,436		2,100
Other liabilities	5,632		6,844
Total non-current liabilities	635,753		468,656
Total liabilities	1,024,065		941,253
COMMITMENTS AND CONTINGENCIES (see NOTE 11)
TEMPORARY EQUITY:
Preferred units, $1,000 par value, 8.0% cumulative, liquidation preference equaling a multiple of invested capital (“MOIC”) of the greater of 1.50 MOIC or 16.5% internal rate of return; 295,859 Preferred Units authorized, issued and outstanding as of December 31, 2020.	—		400,000
MEMBERS’ EQUITY:
Members’ equity	651,602		504,916
Total liabilities and equity	$	1,675,667	$	1,846,169

See accompanying notes to the consolidated financial statements

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GREAT WESTERN PETROLEUM, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(IN THOUSANDS)

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021 through February 22, 2021		Year Ended December 31, 2020
REVENUES:
Oil, NGL and natural gas revenue	$	609,971	$	96,659	$	342,323
OPERATING EXPENSES:
Lease operating expense	37,051		6,953		49,550
Gathering and transportation expense	9,377		1,481		12,054
Exploration expense	3,983		722		6,751
Production and severance tax	50,842		9,937		30,738
Depreciation, depletion and amortization	127,608		45,670		298,552
General and administrative expense	16,507		6,887		31,590
Unit appreciation rights benefit	—		—		(3,464)
Other operating expense	865		—		3,134
Total operating expenses	246,233		71,650		428,905
Operating income (loss)	363,738		25,009		(86,582)
OTHER INCOME (EXPENSE):
Interest expense, net	(38,678)		(6,509)		(41,558)
(Loss) gain on derivative instruments, net	(182,130)		(99,527)		228,866
Gain on purchase of 2021 Notes	—		—		15,856
Other (expense) income	1,172		23		(916)
Total other income (expense)	(219,636)		(106,013)		202,248
NET INCOME (LOSS)	$	144,102	$	(81,004)	$	115,666

See accompanying notes to the consolidated financial statements

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GREAT WESTERN PETROLEUM, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

(IN THOUSANDS)

Predecessor balance at December 31, 2019	$	476,738
Preferred units paid-in-kind dividends, deemed dividends, and return (16.5% IRR)	(87,488)
Net income	115,666
Predecessor balance at December 31, 2020	504,916
Preferred units paid-in-kind dividends, deemed dividends, and return (16.5% IRR)	(3,353)
Net loss	(81,004)
Predecessor balance at February 22, 2021	$	(84,357)
Successor initial investment at February 23, 2021	$	507,500
Net income	144,102
Successor balance at December 31, 2021	$	651,602

See accompanying notes to the consolidated financial statements

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GREAT WESTERN PETROLEUM, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	144,102	$	(81,004)	$	115,666
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Exploration expense	3,983		722		6,751
Depreciation, depletion and amortization	127,608		45,670		298,552
Unit appreciation rights benefit	—		—		(3,464)
Amortization of debt discount and issuance costs	3,071		601		5,895
(Gain) loss on derivative instruments	182,130		99,527		(228,866)
Equity in (income) loss of unconsolidated entity	148		(23)		345
Gain on purchase of 2021 Notes	—		—		(15,856)
Other non-cash gain	(3,269)		—		—
Change in current assets and liabilities:
Accounts receivable	12,433		(57,583)		2,827
Prepaid expenses and other assets	(11,224)		(11,634)		8,527
Accrued liabilities	50,441		(2,417)		(3,521)
Accounts payable	(23,554)		27,352		(8,672)
Production taxes payable	14,240		13,375		(7,265)
Due to/from affiliates	—		—		75,169
Unit appreciation rights settlement	(2,852)		—		(2,649)
Net cash provided by operating activities	497,257		34,586		243,439
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and natural gas properties	(243,186)		(34,482)		(354,426)
Acquisition of oil and natural gas properties and land	(2,919)		—		(4,845)
Business combinations, net of restricted cash acquired	—		—		6,055
Other property and equipment	(23)		—		(137)
Investment in unconsolidated entity	—		—		(1,250)
Net cash receipts (payments) on settled derivative instruments and premiums	(145,700)		5,170		177,724
Net cash used in investing activities	(391,828)		(29,312)		(176,879)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	480,000		—		334,500
Repayments of revolving credit facility	(577,000)		—		(319,500)
Prepayment on redemption of senior notes	—		(27,139)		—
Repayments of senior notes	—		—		(30,130)
Payments of debt issuance costs	(245)		(697)		(2,043)
Distribution to preferred unitholders	—		(3,353)		(14,941)
Net cash used in financing activities	(97,245)		(31,189)		(32,114)
Net increase (decrease) in cash, cash equivalents and restricted cash	8,184		(25,915)		34,446
Cash, cash equivalents and restricted cash at beginning of period	34,000		46,415		11,969
Cash, cash equivalents and restricted cash at end of period	$	42,184	$	20,500	$	46,415
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest, net of capitalized interest	32,170		3,562		38,667
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Oil and natural gas properties—change in due to/from affiliates	—		—		(51,995)
Oil and natural gas properties—change in accruals and accounts payable	8,086		7,660		5,647
Prepayment on senior notes	251,514		—		—
Accounts receivable included in derivative instrument	—		5,476		6,158
Accrued liability included in derivative instrument	11,393		2,850		2,725
Preferred unit dividends declared but not paid	—		—		2,555

See accompanying notes to the consolidated financial statements

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GREAT WESTERN PETROLEUM, LLC AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Organization and Nature of Operations

Great Western Petroleum, LLC (the “Company” or “GWP”) is owned by EIG Dunedin Equity Aggregator, L.P. (“EIG”), TPG Energy Solutions Green, L.P. (“TPG”), GWP Holdings Corp 1 (“GWPHC”), EP Synergy Investments, Inc. (“EPSI”), ActOil Colorado, LLC (“ACTOIL”) and Great Western Oil and Gas Company, LLC (“GWOG”) and was formed to explore, produce and develop oil and natural gas in northern Colorado. The Company was initially formed on September 4, 2013 through the contribution of cash and assets to the proportion of 50.1% interest to GWOG and 49.9% interest to ACTOIL. On July 1, 2017, the 50.1% interest owned by GWOG was allocated 1.95% to GWOG and 48.15% to GWPHC. On February 22, 2021, the Company completed a recapitalization (“Recapitalization Transaction”) where all of GWP’s outstanding preferred units and common members’ equity interests, along with cash contributed by one of the common members, were exchanged for new common units. Subsequent to the Recapitalization Transaction EIG owns 47.6%, TPG owns 21.8%, GWPHC owns 12.0%, EPSI owns 10.6%, ACTOIL owns 7.5% and GWOG owns 0.5% of the outstanding common units of GWP. GWP has a 100% interest in Grizzly Petroleum Company, LLC, Great Western Finance Corp and Great Western Petroleum Midstream Holdings, LLC (“GWPMH”) (collectively with GWP, the “Company”). GWPMH has a 100% interest in Great Western Petroleum Midstream 1, LLC (“GWPM”).

Through July 17, 2020, the Company had a Management Services Agreement (“MSA”) with Great Western Operating Company, LLC (“GWOC”), a wholly owned subsidiary of GWM Holdings, LLC, through which GWOC performed the daily operations of GWP. GWOC operated GWP and costs were passed through to GWP as incurred. Pursuant to the MSA the Company indemnified GWOC for any losses, liabilities, and claims that were not a result of gross negligence or willful misconduct. On July 17, 2020, GWP acquired GWOC and GWOC became a wholly owned subsidiary of GWP. Please see Note 4—Acquisitions, Exchanges and Divestitures to our consolidated financial statements for more information.

The Company is organized as a limited liability company under the laws of the State of Delaware. As such, the members have limited liability unless an act by the member is undertaken with deliberate intent to cause injury or with reckless disregard for the best interests of the Company.

NOTE 2—Basis of Presentation and Principles of Consolidation and Recapitalization Transaction

These consolidated financial statements include the accounts of GWP and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated.

These consolidated financial statements and related notes are stated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. The Company assessed the carrying value of its long-lived assets with the information reasonably available to it and the unknown future impacts of the coronavirus disease 2019 (COVID-19), volatile oil, natural gas and NGL prices and inflation as of December 31, 2021 and 2020 and through the date of this report. As a result of these assessmentsthe Company did not identify any impairment as of December 31, 2021 and 2020. A future assessment of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to the consolidated financial statements in future reporting periods. Note 3—Summary of Significant Accounting Policies describes the Company’s significant accounting policies. The Company believes the major estimates and assumptions impacting its consolidated financial statements are as follows:

•estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties;

•depreciation and depletion of property and equipment;

•impairment of undeveloped properties and other assets;

•estimates of asset retirement obligations;

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•valuation of commodity derivative instruments;

•valuation of Unit Appreciation Rights;

•valuation of convertible preferred units and related embedded features;

•assignment of fair value to assets acquired and liabilities assumed in connection with acquisitions that are considered business combinations and allocating purchase price in connection with acquisitions that are considered asset acquisitions;

•revenue and capital accruals; and

•valuation of assets acquired and liabilities assumed as part of the Recapitalization Transaction.

Actual results may differ from estimates and assumptions of future events and these revisions could be significant. Future production may vary significantly from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. The Company operates as a single reportable segment: the oil and natural gas exploration and production industry in the United States. All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

The Recapitalization Transaction resulted in EIG controlling the majority of the voting power of GWP through its ability to appoint 3 of the 5 board members of GWP. EIG’s control of the majority of the voting power of GWP results in EIG being the acquirer of GWP. The following is a summary of certain key aspects of the Recapitalization Transaction on February 22, 2021:

•All of the Company’s outstanding preferred and common members’ equity interest, along with cash contributed by one of the common unitholders, were exchanged for new authorized, issued and outstanding common units and common unit warrants. Please see Note 8—Members’ Equity and Note—9 Preferred Units to the Company’s consolidated financial statements for more information.

•The Company used the proceeds from the issuance of the 2025 Secured Notes along with cash on hand to redeem all outstanding principal on the 2021 Notes. Please see Note 6—Debt to the Company’s consolidated financial statements for more information.

•The Company exchanged all outstanding principal on the 2025 Notes for additional 2025 Secured Notes. Please see Note 6—Debt to the Company’s consolidated financial statements for more information.

The exchange of outstanding preferred and common members’ equity interest, along with cash by one of the common unitholders for new common units and common unit warrants noted above resulted in a change of control and is a business combination under ASC 805. The assets acquired and liabilities assumed have been recorded as of the February 23, 2021 at fair value and are summarized as follows (in thousands):

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Consideration	$	507,500
Allocation of Purchase Price
Assets acquired1,2
Current assets	$	428,073
Oil and gas properties	1,329,276
Long-term assets	44,371
Total assets acquired	1,801,720
Liabilities Assumed
Current liabilities2	(579,996)
Long-term liabilities	(714,224)
Total liabilities assumed	(1,294,220)
Fair value of net assets acquired	$	507,500

_____________

1)Within current assets is $13.5 million in cash received from one of the new common unitholders which was paid contemporaneously with the Recapitalization Transaction. This cash is excluded from the Predecessor’s Statement of Cash Flows as it relates to funding of the Successor.

2)The balances of current assets and current liabilities do not include the prepaid assets and current debt of $251.5 million related to the repayment of the 2021 Notes which occurred in March 2021. Please see Note 6—Debt to the Company’s consolidated financial statementsand the Statement of Cash Flows in the consolidated financial statements for details.

To account for the transaction described above, the Company has elected to apply pushdown accounting. Accordingly, the Company has reflected the new basis of accounting established by EIG through its application of ASC 805 to the individual assets and liabilities of the Company. The financial statements of the Company have been presented as follows, which are not comparable due to push down accounting and therefore have been segregated between a predecessor and successor period:

•Consolidated Balance Sheet: The Balance Sheet as of December 31, 2021 is presented under the new basis (“Successor”) with a black line separating the Balance Sheet as of December 31, 2020 which is presented under the old basis (“Predecessor”).

•Consolidated Statement of Operations and Consolidated Statement of Cash flows: The period from February 23, 2021 through December 31, 2021 is presented under the new basis (“Successor”) with a black line separating the period from January 1, 2021 through February 22, 2021 and the year ended December 31, 2020 which are presented under the old basis (“Predecessor”).

NOTE 3—Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Accounts Receivable

As of December 31, 2021 and 2020 accounts receivable primarily consist of receivables from oil and natural gas purchasers and joint interest owners. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover nonpayment of joint interest billings. The Company routinely assesses the creditworthiness of its oil and natural gas purchasers and the recoverability of all material trade and other receivables to determine their collectability. The Company routinely assesses the recoverability of all material trade and

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other receivables to determine their collectability. As of December 31, 2021 the Company’s allowance for uncollectible accounts was $0.9 million. As of December 31, 2020, no allowance for uncollectible accounts was recorded.

Prepaid Expenses and Other Assets

The Company has prepaid expenses primarily related to well connections, various insurance premiums, dues and subscriptions that are paid at the beginning of the term and extend past year end. The Company records well equipment inventory and materials included in other assets at the lower of cost or net realizable value.

Oil and Natural Gas Producing Properties

Proved—The Company uses the successful efforts method of accounting for oil and natural gas properties. In accordance with this method, all property acquisition costs and costs of exploratory wells are capitalized as incurred, pending the determination of proved reserves. If proved reserves are not found, costs are expensed. Costs associated with developmental activities are capitalized as incurred regardless of proved reserves being found.

Unproved—Investments in unproved properties are not depleted until it is determined proved reserves exist. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties are grouped for purposes of assessing impairment. Management considers the primary lease terms of the properties, the holding period of the properties, success of holding leases through drilling, and geographic and geologic data obtained relating to the properties while grouping properties to assess impairment. The amount of impairment is reported as a period expense within exploration expense.

Wells in Progress—Wells in progress represent the costs associated with wells that have not been completed as of the balance sheet date. At the time a well is completed and producing, the accumulated capitalized costs for the well is reclassified to proved property and included in the depletion calculation.

    Capitalized Interest—The Company capitalizes interest on expenditures made in connection with exploration and development projects that are in progress. Interest is capitalized during the period that activities occur to bring the projects to their intended use.

Oil and natural gas properties, net, consist of the following (in thousands):

	(Successor)		(Predecessor)
	December 31,		December 31,
	2021		2020
Proved oil and natural gas properties	$	1,447,256	$	2,584,641
Unproved oil and natural gas properties	17,469		48,071
Wells in progress	120,010		95,891
Total oil and natural gas properties	1,584,735		2,728,603
Less: accumulated depletion	(125,591)		(1,074,303)
Total oil and natural gas properties, net	$	1,459,144	$	1,654,300

In conjunction with pushdown accounting, oil and natural gas properties were measured at fair value as of the Acquisition Date. Please see Note 2— Basis of Presentation and Principles of Consolidation and Recapitalization Transaction to the Company’s consolidated financial statements.

Costs of oil and natural gas properties include capitalized interest of $6.4 million and $7.0 million for the period the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor). There was no capitalized interest recorded for the period January 1, 2021 through February 22, 2021 (Predecessor).

Property acquisition and development costs are depleted using the units of production method on a field basis aggregated by common geological structure or stratigraphic condition. Costs to carry, retain, maintain and repair properties are expensed as incurred, and new leases and improvements are capitalized as property and equipment.

F-8

The Company evaluates its long-lived assets, to be held and used, including proved oil and natural gas properties, by field on an annual basis or when events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. If an impairment loss is indicated, the Company recognizes the impairment loss for the amount that the carrying amount of the asset exceeds its estimated fair value. The Company did not recognize any impairment expense for proved properties for the years ended December 31, 2021 and 2020. Unproved properties were amortized and impaired using the individually insignificant lease basis and charged to exploration expense in the amount of $0.7 million, $3.7 million and $6.3 million for the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020, respectively (Predecessor).

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (“SEC”) and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a first of the month average price for the most recent twelve months ended with no provision for price and cost escalations in future years except by contractual arrangements. The Company’s oil and natural gas reserves as of December 31, 2021 were prepared by the Company and audited by an independent reserve engineer, Ryder Scott, L.P.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and natural gas properties are depleted by field using the units of production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property and Equipment

Other property and equipment includes land, which is not depreciated, furniture and fixtures, leasehold improvements, computer hardware and software and gathering lines which are depreciated on the straight-line depreciation method, based upon estimated useful lives of the assets, which range from three to ten years.

Restricted Cash

The Company entered into a firm sales agreement that requires the Company to deliver minimum quantities of oil. If the Company is unable to fulfill all contractual obligations, the Company may be required to pay penalties or damages pursuant to the agreement. The Company was required to open a letter of credit with cash designated as collateral for any penalties associated with minimum quantities of oil not delivered. The cash designated to fund the letter of credit is considered restricted cash.

Debt Issuance Costs

Unamortized debt issuance costs related to the revolving credit facility as of December 31, 2021 and 2020 were $3.4 million and $4.0 million and are included in other assets. The Company amortized the debt issuance costs related to the revolving credit facility using the straight-line method and had $0.2 million, $1.1 million and $1.1 million amortized to interest expense for the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor), respectively. Unamortized debt issuance costs related to the 2025 Secured Notes as of December 31, 2021 were $11.0 million. Debt issuance costs on the 2025 Secured Notes are presented net against outstanding debt on the December 31, 2021 consolidated balance sheets – see Note 6—Debt. The Company amortized the debt issuance costs related to the 2025 Secured, 2021 and 2025 Notes using the effective interest method of amortization and had $0.5 million, $1.9 million and $3.1 million of amortization in interest expense for the period January 1, 2021 through February 22, 2021 (Predecessor),

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the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor), respectively.

Deferred Salaries

Certain employees of the Company, upon hire, had the option of deferring payment of a portion of their salaries which is held at an affiliate. The Company has recorded $3.6 million and $4.1 million as of December 31, 2021 and 2020, respectively, which is included in non-current other liabilities. 

Investment in Unconsolidated Entity

On April 4, 2019, GWPM entered into an agreement with a midstream company, which is a limited liability company, where GWPM contributed cash equal to a 10% equity interest in that company. The company was formed to design, construct and operate a gas gathering and compression system, gas processing plant and other midstream facilities. The natural gas processing plant and gathering system started full operations on September 16, 2019. GWP’s investment in the unconsolidated entity is accounted for using the equity method in which investments are initially recognized at cost and subsequently adjusted for GWP’s proportionate share of earnings, losses and distributions. The carrying value of GWP’s investment as of December 31, 2021 was $18.9 million which was made up of the following activity during the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) (in thousands):

Predecessor investment in unconsolidated entity, December 31, 2020	$	19,031
GWP's proportionate share of the unconsolidated entity's net income	23
Predecessor investment in unconsolidated entity, February 22, 2021	$	19,054
Successor investment in unconsolidated entity, February 23, 2021	$	19,054
GWP's proportionate share of the unconsolidated entity's net loss	(148)
Successor investment in unconsolidated entity, December 31, 2021	$	18,906

Other Than Temporary Impairment

On a continuous basis, management assesses whether there are any indicators, including the underlying investment’s operating performance and general market conditions, that the value of the Company’s investments in unconsolidated entity may be impaired. An investment’s value is impaired only if management’s estimate of the fair value of the investment is less than the carrying value of the investment and such difference is deemed to be other-than-temporary. To the extent impairment has occurred, the loss shall be measured as the excess of the carrying amount of the investment over the estimated fair value of the investment. The Company did not recognize any impairment expense for the investment in unconsolidated entity for the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor).

Fair Value Measures

Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at the reporting date. Assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs, and consists of three levels:

•Level 1—Measurements are obtained using unadjusted quoted prices in active markets for identical, unrestricted assets or liabilities that the reporting entity has the ability to access at the measurement date.

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•Level 2—Measurements use inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

•Level 3—Measurements are based on one or more unobservable inputs that are significant in establishing a fair value estimate. These unobservable inputs are developed based on the best information available and may include the Company’s internal data.

In determining fair value, the Company uses observable market data when available, or models that incorporate observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account when measuring fair value. Reclassifications and transfers of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.

Accrued Liabilities

Accrued liabilities include the following as of December 31, 2021 and 2020, respectively (in thousands). 

`	(Successor)		(Predecessor)
	December 31,		December 31,
	2021		2020
Accrued capital and operating expenses	$	54,776	$	40,269
Revenue payable	130,071		74,924
Accrued compensation expense	5,473		10,415
Interest payable	13,147		7,463
Dividends payable	—		3,137
Derivative payable	13,463		—
Other accrued expenses	—		676
Total accrued liabilities	$	216,930	$	136,884

Production Taxes Payable

Production taxes payable primarily consists of ad valorem taxes payable. Ad valorem taxes are paid two years in arrears in the state of Colorado. Ad valorem taxes are based on revenues from the production of oil, natural gas and natural gas liquids (“NGLs”). The current portion of ad valorem taxes accrued as of December 31, 2021 will be paid to the counties in which the Company produces oil, natural gas and NGLs in April of 2022. The current portion of ad valorem taxes accrued as of December 31, 2020 were paid in February and June of 2021.

Asset Retirement Obligations

Asset retirement obligations (“ARO”) represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and remediation of the land. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of the cost to plug and abandon and remediate can be made. The corresponding asset retirement cost is capitalized with the related long-lived asset. The liability is accreted to its present value each period.

Inherent to the present value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the total cost of remediation, inflation factors, the Company’s credit adjusted risk free rate, timing of settlement and changes in the legal, regulatory, environmental and political environments. Revisions to these estimates may impact the ARO. The Company makes corresponding adjustments to both the ARO and the related oil and natural gas property asset balance for these revisions. These revisions result in prospective changes to depreciation, depletion and amortization expense and the associated accretion of the discounted abandonment liability (“DD&A”).

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On February 22, 2021, ARO was remeasured as part of the pushdown accounting adjustments. Please see Note 2— Basis of Presentation and Principles of Consolidation and Recapitalization Transaction to our consolidated financial statements for more information.

The following table summarizes the activities for the Company’s ARO (in thousands):

Predecessor asset retirement obligations, December 31, 2019	$	20,699
Liabilities incurred and acquired	162
Liabilities settled	(8,402)
Accretion expense	1,477
Revisions in estimated liabilities	2,745
Predecessor asset retirement obligations, December 31, 2020	16,681
Liabilities settled	(750)
Accretion expense	261
Predecessor asset retirement obligations, February 22, 2021	$	16,192
Successor liability acquired, February 23, 2021	$	14,076
Liabilities incurred and acquired	278
Liabilities settled	(5,768)
Accretion expense	1,168
Revisions in estimated liabilities	2,292
Successor asset retirement obligations, December 31, 2021	$	12,046
Current portion of asset retirement obligations	7,297
Long term portion of asset retirement obligations	4,749
Successor asset retirement obligations, December 31, 2021	$	12,046

The fair value of ARO is measured using Level 3 inputs in the fair value hierarchy.

Energy Group Long-Term Incentive Plan

The Energy Group Long Term Incentive Plan (“LTIP”) was established for the benefit of certain employees. The LTIP includes a profit-sharing award (“PSA”). The PSA was terminated effective November 18, 2019. The remaining PSA liability of $1.6 million was paid in December 2020 and $1.7 million was paid in October 2021.

The LTIP awards were accounted for in accordance with Accounting Standards Codification (“ASC”) 718, Compensation—Stock Compensation (“ASC 718”). As of January 1, 2015, the PSA was frozen and replaced with the Unit Appreciation Rights Plan, as described below.

Profits Participation Plan and Deferred Compensation Arrangement

The Profits Participation Plan (the “PPP”) became effective on January 1, 2015 for the benefit of certain employees based on the performance of the Company, though no awards were granted under that plan until 2016. For periods prior to 2016, the Company established a deferred compensation arrangement (the “Deferred Comp Arrangement”) based on the employee’s length of service.

The PPP includes a Target Deferred Bonus (the “TDB”) and a sale bonus. The TDB provides employees the opportunity to participate in additional cash bonuses based on individual employee performance and Company performance. The Sale Bonus allows certain employees to participate in up to 10% of Net Sales Proceeds, at the discretion of the managers as defined by the PPP, triggered by certain monetization events. The TDB and Sale Bonus vest one-third on the first June 30 following the date of grant and one-third as of the last day of the following two fiscal years. Upon a change in control, as defined in the PPP, the TDB and sale bonus fully vest. The Recapitalization

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Transaction on February 22, 2021 caused a change in control, as defined in the PPP, and therefore the TDB became fully vested. Final payment of the TDB in the amount of $1.4 million was made on May 15, 2021. There was no sale bonus established as part of the change in control.

The PPP awards and Deferred Comp Arrangement were accounted for in accordance with ASC Topic 710, Compensation. The awards were vested over three years and were expensed using a graded method. The deferred compensation liability associated with the PPP and the Deferred Comp Arrangement was approximately $1.4 million as of December 31, 2020.

Unit Appreciation Rights Plan

The Unit Appreciation Rights Plan (the “UAR Plan”) was established by the Company effective January 1, 2015, to provide long-term incentives to key members of management. The Recapitalization Transaction on February 22, 2021 caused a change in control, as defined in the UAR Plan, and therefore all unvested Class B Units granted as part of the UAR Plan became fully vested and redeemable. Final payment of all redeemed Class B Units in the amount of $2.9 million was made in June 2021.

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices and interest rates. These transactions are in the form of swaps, purchased puts, and collars.

The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk associated with derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit-worthy financial institutions deemed by management as competent and competitive market-makers. The Company also utilizes master netting agreements to minimize credit-risk exposure.

The Company reports the fair value of all derivative instruments on the consolidated balance sheets. The commodity and interest rate derivative instruments are not designated as hedges for accounting purposes for the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change.

Financial Instruments

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, derivative instruments, and accounts receivable. The Company’s cash and cash equivalents and derivative instruments are with major financial institutions. The Company attempts to minimize credit risk exposure from purchasers of the Company’s oil and natural gas through formal credit policies and monitoring procedures. A portion of the Company’s derivative contracts currently in place are with lenders under its revolving credit facility that have investment grade ratings.

Revenue Recognition

The Company recognizes revenue in accordance with FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). Revenue is recognized at the point in time at which the Company’s performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering and transportation expense, and fees incurred after control transfers are included as a reduction to the transaction price. The table below presents the disaggregation of revenue by product type for the period from January 1, 2021 through February 22, 2021 (Predecessor), for the period from February 23, 2021 through December 31, 2021 (Successor), and for the year ended December 31,2020 (Predecessor) (in thousands):

F-13

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
REVENUE:
Oil revenue	$	424,260	$	53,138	$	313,373
NGL and natural gas revenue	185,711		43,521		28,950
Oil, NGL and natural gas revenue	$	609,971	$	96,659	$	342,323

The Company records sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement, which is variable based on commodity pricing. The Company estimates its sales volumes based on company-measured volume readings. Oil, natural gas and NGL sales are adjusted in subsequent periods based on data received from the Company’s purchasers that reflects actual volumes and prices received which is typically within two months of transfer of control to the purchaser. Historically, the difference between estimated and actual sales revenues has not been material. For the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor), and for the year ended December 31, 2020 (Predecessor), the impact of any natural gas imbalances was not significant.

From time to time the Company may enter into short term marketing contracts where the Company purchases and re-sells oil and natural gas to meet its marketing commitments. The Company acts as an agent in these transactions as the oil and natural gas is not controlled by the Company and therefore the associated purchase and sale are presented net on the consolidated statements of operations. Historically, the difference between purchases and sales have not been material.

Comprehensive Income (Loss)

The Company has no elements of comprehensive income (loss) other than net income (loss).

Income Taxes

The Company is organized as a limited liability company and is accounted for as a pass-through entity for U.S. federal income tax purposes. As a result, the net taxable income of the Company and any related tax credits are passed through to the members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no U.S. federal tax provision has been recorded in the financial statements of the Company. The U.S. Tax Cuts and Jobs Act passed in December 2017 has not had an impact on the Company as it is a pass-through entity.

Reclassifications

Certain prior period balances have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company’s operating income, net income, cash flows or members’ equity previously reported.

NOTE 4—Acquisitions, Exchanges and Divestitures

In July 2020, the Company acquired GWOC for aggregate consideration of $5,000 in cash. The acquisition provides for the consolidation of GWOC for better visibility into the assets and liabilities recorded at GWOC. The acquired assets from GWOC did not contribute any revenue or net income to the Company for the year ended December 31, 2020 as GWOC operated the assets of the Company and costs were passed through to the Company as incurred at no markup.

The acquisition is accounted for using the acquisition method in accordance with ASC Topic 805, Business Combinations (“ASC 805”), which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of July 17, 2020. The fair value of assets acquired and liabilities assumed is the balance sheet of GWOC on July 17, 2020 as no intangible assets were acquired as part of the acquisition.

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The following table summarizes the purchase price of assets acquired and liabilities assumed (in thousands):

Purchase Price (in thousands)	July 17, 2020
Consideration
Cash	$	5
Total consideration	$	5
Allocation of Purchase Price
Assets acquired
Accounts receivable	$	57,681
Prepaid and other assets	21,111
Other property and equipment, net	3,738
Non-current restricted cash	6,060
Intercompany receivable (current and non-current)	173,346
Total acquired assets	$	261,936
Liabilities assumed
Accounts payable and accrued expenses	$	(147,551)
Production tax payable (current and non-current)	(101,643)
Line fill liability (current and non-current)	(3,802)
Non-current debt, net	(3,269)
Other liabilities	(5,666)
Total assumed liabilities	$	(261,931)
Fair value of net assets acquired	$	5

For the period January 1, 2021 through February 22, 2021 (Predecessor) and the period February 23, 2021 through December 31, 2021 (Successor) the Company spent $0.2 million and $3.0 million on leasing and did not close any other acquisitions. For the year ended December 31, 2020 (Predecessor), the Company spent $4.6 million on leasing and closed $0.8 million of various other acquisitions.

NOTE 5—Derivative Instruments

The Company uses financial derivative instruments as part of its price and interest rate risk management program to achieve a more predictable, economic cash flow from its oil and natural gas production and limiting exposure to interest rate changes by reducing its exposure to commodity price and interest rate fluctuations. Historically, the Company has entered into financial swaps, purchased puts and collars.

Each swap contract has an established contractually set fixed price (the “Fixed Price”). When the settlement price of the commodity is above the Fixed Price, the Company pays its counterparty an amount equal to the difference between the settlement price of the commodity and the Fixed Price multiplied by the contract volume. When the settlement price of the commodity is below the Fixed Price, the counterparty pays the Company an amount equal to the difference between the settlement price of the commodity and the Fixed Price multiplied by the contract volume.

Basis swaps are designed to establish a fixed price differential between pricing at two different locations. The Price the Company receives for natural gas production generally varies from the NYMEX Henry Hub price used in swap and collar contracts, due to adjustments for delivery location and other factors.

The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between

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the commodity settlement price and the price floor multiplied by the contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the commodity derivative contract volume.

    Interest-rate swaps are used to fix interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to interest-rate changes. The fair value of the Company’s current interest-rate swap portfolio is subject to changes in interest rates.

Below is a summary of the Company’s open commodity derivative instrument positions as of December 31, 2021, by product and strategy:

	Location1	2022		2023
Crude Swaps:
Notional volume (Bbl)	NYMEX	4,715,018		150,000
Weighted average price ($/Bbl)		$	53.81	$	62.50
Crude Collars:
Notional volume (Bbl)	NYMEX	—		—
Weighted average floor price ($/Bbl)		$	—	$	—
Weighted average ceiling price ($/Bbl)		$	—	$	—
Natural Gas Swaps:
Notional volume (MMbtu)	NYMEX	16,400,003		7,083,333
Weighted average price ($/MMbtu)		$	3.08	$	3.24
Natural Gas Basis Swaps:
Notional volume (MMbtu)	NYMEX &	9,000,012		3,180,000
Weighted average price ($/MMbtu)	ROCKIES	$	(0.27)	$	(0.35)
Natural Gas Collars:
Notional volume (MMbtu)	NYMEX	1,349,996		1,266,667
Weighted average floor price ($/MMbtu)		$	2.80	$	3.11
Weighted average ceiling price ($/MMbtu)		$	3.39	$	4.00

_____________

1)NYMEX refers to quoted prices on the New York Mercantile Exchange and ROCKIES refers to quoted CIG natural gas prices.

Below is a summary of the Company’s open interest rate swaps as of December 31, 2021 (in thousands except percentages):

Notional Principal Amount		Maturity Date	Interest Rate
$	75,000	June 25, 2024	0.46	%
$	25,000	June 25, 2024	0.45	%
$	25,000	June 25, 2024	0.36	%
$	25,000	June 25, 2024	0.36	%
$	25,000	June 25, 2024	0.22	%
$	25,000	June 25, 2024	0.22	%
$	25,000	June 25, 2024	0.23	%

Balance sheet presentation

Derivative instruments are reported at fair value on the consolidated balance sheets as derivative instruments under current assets, non-current assets, current liabilities and non-current liabilities. The Company nets the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the financial right to

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offset exists. The following table presents the fair value of the derivative instruments on a net basis as of December 31, 2021 and 2020 (in thousands):

	Asset Derivatives				Liability Derivatives
	(Successor)		(Predecessor)		(Successor)		(Predecessor)
	December 31,		December 31,		December 31,		December 31,
	2021		2020		2021		2020
Commodity derivatives not designated as hedging instruments	$	—	$	22,776	$	106,931	$	4,297
Interest rate derivatives not designated as hedging instruments	3,328		—		—		674
Total derivatives not designated as hedging instruments	$	3,328	$	22,776	$	106,931	$	4,971

Gains and losses

Gains or losses resulting from changes in the fair values of the Company’s derivatives along with the gains or losses resulting from settlement of derivatives are all included in gain (loss) on derivative instruments, net in the consolidated statements of operations.

The following table presents gain (loss) on derivative instruments for the periods presented (in thousands):

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
Realized (loss) gain on derivative instruments	$	(157,092)	$	(3,157)	$	186,604
Unrealized (loss) gain on derivative instruments	(25,038)		(96,370)		42,262
(Loss) gain on derivative instruments, net	$	(182,130)	$	(99,527)	$	228,866

The following table presents gross commodity derivative balances prior to applying netting adjustments and net balances as recorded in the consolidated balance sheets (in thousands):

	Gross Amounts		Netting Adjustments1		Net Amounts Presented in the Balance Sheet2
December 31, 2021 (Successor)
Current commodity derivative assets	$	172	(172)		$	—
Non-current commodity derivative assets	$	523	(523)		$	—
Current commodity derivative liabilities	$	103,668	(173)		$	103,495
Non-current commodity derivative liabilities	$	3,958	(522)		$	3,436
December 31, 2020 (Predecessor)
Current commodity derivative assets	$	24,326	$	(1,550)	$	22,776
Non-current commodity derivative assets	$	143	$	(143)	$	—
Current commodity derivative liabilities	$	3,996	$	(1,550)	$	2,446
Non-current commodity derivative liabilities	$	1,994	$	(143)	$	1,851

_____________

1)With all of the Company’s financial trading counterparties, there are agreements in place that allow for the financial right of offset for commodity derivative assets and commodity derivative liabilities at settlement or in the event of a default under the agreements.

2)There are no amounts of related financial collateral received or pledged.

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The following table presents gross interest rate derivative balances prior to applying netting adjustments and net balances as recorded in the consolidated balance sheets (in thousands):

	Gross Amounts		Netting Adjustments1		Net Amounts Presented in the Balance Sheet2
December 31, 2021 (Successor)
Current interest rate derivative assets	$	404	(178)		$	226
Non-current interest rate derivative assets	$	3,102	—		$	3,102
Current interest rate derivative liabilities	$	178	(178)		$	—
Non-current interest rate derivative liabilities	$	—	—		$	—
December 31, 2020 (Predecessor)
Current interest rate derivative assets	$	—	$	—	$	—
Non-current interest rate derivative assets	$	92	$	(92)	$	—
Current interest rate derivative liabilities	$	425	$	—	$	425
Non-current interest rate derivative liabilities	$	341	$	(92)	$	249

_____________

1)With all of the Company’s financial trading counterparties, there are agreements in place that allow for the financial right of offset for interest rate derivative assets and interest rate derivative liabilities at settlement or in the event of a default under the agreements.

2)There are no amounts of related financial collateral received or pledged.

Netting for balance sheet presentation is performed by current and non-current classification. The Company does have amounts subject to enforceable master netting arrangements that are not netted on the consolidated balance sheets. As of December 31, 2021, amounts for counterparties in a net asset position totaled $3.3 million and a net liability position totaled $106.9 million. As of December 31, 2020, amounts for counterparties in a net asset position totaled $22.1 million and a net liability position of $3.6 million.

NOTE 6—Debt

On June 25, 2019, the Company entered into a Third Amended and Restated Credit Agreement with MUFG Union Bank, N.A. (formerly known as Union Bank, N.A.), as administrative agent (“Administrative Agent”), and the lenders party thereto (“Lenders”) with respect to the Company’s revolving credit facility in the maximum aggregate principal amount of $1.5 billion, with a sublimit for letters of credit issued thereunder of $20.0 million and no swing line loans. The initial borrowing base on the revolving credit facility was $650 million; however, to reduce associated fees, the Company elected to a commitment amount of $550 million. On August 23, 2019, the Company entered into Amendment No. 1 to the Third Amended and Restated Credit Agreement, which allows the Company to purchase in cash up to an aggregate amount of $50.0 million of the 2021 Notes and/or 2025 Notes. For the year ended December 31, 2020 the Company purchased $46.0 million of 2021 Notes for $30.1 million recording a gain of $15.9 million. As of December 31, 2020, the Company has purchased a total of $31.8 million and can purchase an additional $18.2 million in senior notes. On November 15, 2019 the Company entered into Amendment No. 2 to the Third Amended and Restated Credit Agreement that increased the borrowing base from $650 million to $700 million. However, to reduce associated fees, the Company elected a commitment amount of $630 million. On April 8, 2020 the Company entered into Amendment No. 3 to the Third Amended and Restated Credit Agreement that, among other things, decreased the borrowing base from $700 million to $600 million. On July 13, 2020, the Company entered into Amendment No. 4 to the Third Amended and Restated Credit Agreement that allows the Company to incur second-lien, third-lien and unsecured debt in an aggregate principal amount of up to $375 million and, subject to the aggregate maximum amount of $375 million and up to $175 million of new third lien notes the Company may issue to Preferred Investors in exchange of Preferred Units. On September 29, 2020, the Company entered into Amendment No. 5 to the Third Amended and Restated Credit Agreement that, among other things, decreased the borrowing base from $600 million to $485 million.

The revolving credit facility is secured by liens and security interests on substantially all of the Company’s properties and the properties of its subsidiaries. The credit facility contains restrictive covenants that may limit the Company’s ability to (i) grant liens, (ii) incur additional debt, (iii) enter into mergers, (iv) sell assets, (v) make

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distributions and redemptions, (vi) make certain acquisitions and investments, (vii) enter into transactions with affiliates, (viii) hedge future production, and (ix) engage in certain other prohibited transactions without the prior consent of the lender.

The amount available to be borrowed on the Company’s revolving credit facility is subject to a borrowing base that is required to be redetermined semi-annually and will be based on proved reserves reflected in the midyear and year end reserve reports as being attributable to the oil and natural gas properties, the financial condition and projected financial condition of the Company, and other information deemed relevant by the Administrative Agent. Additionally, at the request of (i) the Lenders or the Administrative Agent or (ii) the Company, the borrowing base may be redetermined, in each case one additional time during any period between two scheduled redeterminations. As of December 31, 2021, the borrowing base under the revolving credit facility was $485.0 million and there were $242.0 million of outstanding borrowings thereunder. As of December 31, 2020, the borrowing base under the revolving credit facility was $485.0 million and there were $339.0 million of outstanding borrowings thereunder.

Outstanding principal amounts borrowed (and accrued but unpaid interest thereon) are required to be repaid in full on the maturity date (or earlier, upon any acceleration of such obligations pursuant to the terms of the revolving credit facility), and interest will be payable quarterly for reference rate loans and at the end of the applicable interest period for Eurodollar loans, or, if the applicable interest period is greater than six months, on the three month anniversary of the first day of such interest period. The Company has a choice of borrowing at an adjusted Eurodollar rate or an adjusted reference rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to a fraction (expressed as a decimal), the numerator of which is the applicable LIBOR rate and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the Administrative Agent is required to maintain reserves according to the regulations of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. Reference rate loans bear interest at a rate per annum equal to the greatest of (i) the Administrative Agent’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the one-month LIBOR rate plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of the borrowing base utilized. The Company may prepay any amounts borrowed prior to the maturity date without any premium or penalty other than the prepayment of accrued interest and customary Eurodollar breakage costs.

The revolving credit facility requires the Company to maintain, on a consolidated basis with its subsidiaries, the following financial ratios:

•a current ratio, which is the ratio of: (i) the Company’s consolidated current assets (including the aggregate unused commitments under the revolving credit facility and joint interest billing suspense through March 30, 2021, but excluding restricted cash and certain derivative assets) to (ii) the Company’s consolidated current liabilities (excluding the current portion of long-term obligations under the revolving credit facility, certain derivative assets and the 2021 Notes through March 30, 2021), of not less than 1.0 to 1.0 as of the last day of each fiscal quarter; and

•a maximum leverage ratio, which is the ratio of (i) the Company’s consolidated total debt (excluding certain debt attributed to hedging arrangements and obligations under the 2018 Preferred Units as long as they are not classified as debt) to (ii) the Company’s consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 3.5 to 1.0 as of the last day of each fiscal quarter.

The revolving credit facility also contains customary events of default, including, without limitation, the failure to make payments, cross-default to other material indebtedness, certain events related to bankruptcy or insolvency proceedings, and failure to comply with specified covenants. Upon an event of default, the lender commitments under the revolving credit facility may be terminated and indebtedness thereunder declared immediately due and payable.

On February 22, 2021, the Company completed a private offering of $235.0 million in aggregate principal amount of 12.0% senior secured notes (the “2025 Secured Notes”) which resulted in net proceeds of approximately $222.7 million net of the initial purchasers discount of 2.5% of the aggregate principal and offering expenses. The 2025 Secured Notes mature on September 1, 2025. Interest on the 2025 Secured Notes is payable on March 1 and September 1 of each year with the first interest payment made on September 1, 2021. The net proceeds from the issuance of the 2025

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Secured Notes along with cash on hand of $36.8 million were deposited in an irrevocable trust on February 22, 2021 until March 3, 2021 when certain requirements in 2025 Secured Note agreement were satisfied. On March 3, 2021, the funds deposited in the irrevocable trust were used to fund the redemption of all remaining outstanding principal of $251.5 million on the $300.0 million aggregate principal amount 9.0% senior notes due in 2021 issued on September 22, 2016 (“2021 Notes”). Further, in connection with the closing of the 2025 Secured Notes, on February 22, 2021 the Company exchanged all outstanding principal of $75.0 million on the $75.0 million aggregate principal amount 8.5% senior notes due in 2025 issued on April 11, 2018 (“2025 Notes”) for additional 2025 Secured Notes of $76.875 million. The $1.875 million difference between the $76.875 million exchange price on the additional 2025 Secured Notes and exchanged for the $75.0 million carrying value of the 2025 Notes was recorded to equity as part of the push down accounting adjustments as this is not a transaction of the Predecessor and represents part of the initial basis of the Successor. The redemption of the 2021 Notes and exchange of the 2025 Notes were accounted for as a debt extinguishment and therefore unamortized debt issuance costs of $1.4 million and $2.9 million on the 2021 Notes and 2025 Notes were adjusted to zero as part of the push down accounting adjustments. Please see Note 2—Basis of Presentation and Principles of Consolidation and Recapitalization Transaction to our consolidated financial statements for more information.

The Company is entitled to redeem up to 35% of the aggregate principal amount of the 2025 Secured Notes prior to March 1, 2023 with an amount of cash not greater than the net proceeds that the Company could raise in certain equity offerings at a redemption price equal to 112.0% of the principal amount of the 2025 Secured Notes being redeemed plus accrued and unpaid interest. The Company is also entitled to redeem all or a part of the 2025 Secured Notes prior to March 1, 2023 at a redemption price equal to 100.000% of the principal amount thereof, plus accrued and unpaid interest plus the greater of (i) 1% of the principal amount of the 2025 Secured Notes or (ii) the present value of 106.0% of the principal amount of the 2025 Secured Notes plus all required interest payments through March 23, 2023 (excluding accrued but unpaid interest through the redemption date) using a discount rate on the redemption date equal to the treasury rate plus 50 basis points discounted to the redemption date on a semi-annual basis divided by the principal amount of the 2025 Secured Notes. If the 2025 Secured Notes are redeemed on or after March 23, 2023, the Company may redeem some or all of the 2025 Secured Notes at a price equal to 106.0% of the principal amount if redeemed between March 1, 2023 and March 1, 2024, 103.0% of the principal amount if redeemed between March 1, 2024 and March 1, 2025 and 100.00% of the principal amount if redeemed between April 2025 and thereafter, plus accrued and unpaid interest. If the Company experiences a change of control, as defined in the note agreement in respect of the 2025 Secured Notes, the Company will be required to offer to holders of the 2025 Secured Notes to repurchase their notes at 101.0% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase.

As of December 31, 2021 and 2020, the Company had $311.9 million and $326.5 million, respectively, in principal outstanding on the senior notes with unamortized discount and debt issuance costs of $11.0 million and $4.8 million, respectively, and accrued interest of $12.5 million and $7.0 million, respectively.

The Company incurred interest on long-term debt of $5.9 million, $41.9 million and $44.2 million for the period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor), respectively, and capitalized interest of $6.4 million and $7.0 million for the period the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor). There was no capitalized interest recorded for the period January 1, 2021 through February 22, 2021 (Predecessor).

As of December 31, 2021 and 2020, the Company was in compliance with all debt covenants.

Paycheck Protection Program Loan

On April 14, 2020, the Company entered into a loan agreement with PNC Bank N.A. as the lender of the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) administered by U.S. Small Business Administration (“SBA”) and obtained a loan in the amount of $3.3 million to help retain employees due to the impact of the COVID-19 pandemic. The Company’s Paycheck Protection Program loan (“PPP Loan”) is fully forgivable if the Company meets certain requirements and receives formal approval, as defined by the CARES Act, subject to an audit by the SBA. The $3.3 million PPP Loan was fully forgiven in May 2021 and was recorded as a reduction of general and administrative expense in the consolidated statement of operations.

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NOTE 7 – Fair Value Measures

Commodity Derivative Instruments

The following summarizes the fair value of the Company’s derivative assets and liabilities, by input level within the fair-value hierarchy (in thousands):

	Level 1		Level 2		Level 3
Assets (liabilities) at December 31, 2021 (Successor):
Commodity derivatives	$	—	$	(106,931)	$	—
Interest rate derivatives	$	—	$	3,328	$	—
Assets (liabilities) at December 31, 2020 (Predecessor):
Commodity derivatives	$	—	$	18,479	$	—
Interest rate derivatives	$	—	$	(674)	$	—

The fair value of the Company’s commodity and interest rate derivatives are determined using industry standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, non-performance risk, as well as other relevant economic measures. These are considered Level 2 inputs as substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

No transfers between levels have occurred for the years ended December 31, 2021 and 2020, respectively.

Fair Value of Financial Instruments

The carrying values of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

The portion of the Company’s long-term debt related to its revolving credit facility approximates fair value due to the variable nature of related interest rates. The Company has not elected to account for the portion of its debt related to its senior notes under the fair value option; however, the Company has determined an estimate of the fair value based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the Company’s long-term debt (in thousands):

	Carrying Value		Estimated Fair Value
At December 31, 2021 (Successor):
Revolving credit facility	$	242,000	$	242,000
2025 Secured Notes (105.3% of par)1	$	300,883	$	328,404
At December 31, 2020 (Predecessor):
Revolving credit facility	$	339,000	$	339,000
2021 Notes (57.0% of par)2	$	249,718	$	143,363
2025 Notes (40.1% of par)3	$	71,987	$	30,088

_____________

1)The carrying amount of the 2025 Secured Notes includes unamortized debt issuance costs and discounts of $11.0 million as of December 31, 2021.

2)The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs and discounts of $1.8 million as of December 31, 2020.

3)The carrying amount of the 2025 Senior Notes includes unamortized debt issuance costs and discounts of $3.0 million as of December 31, 2020.

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NOTE 8—Members’ Equity

On February 22, 2021, the Company completed the Recapitalization Transaction wherein all of the Company’s outstanding preferred and common units, along with cash contributed by one of the common unitholders, were exchanged for 1,000,000 new authorized, issued and outstanding common units (“Common Units”). Additional Common Units will be issued upon any exercise of common unit Warrants. The common unitholders are not required to make any additional capital contributions to the Company or its subsidiaries, and distributions will be made to the Common Unitholders at the discretion of the Company’s Board in proportion to each Common Unitholder’s ownership percentage in the Company at the time of distribution, as defined in the Company’s Third Amended and Restated Limited Liability Agreement.

As part of the Recapitalization Transaction, the Company granted 41,667 freestanding common unit warrants at a strike price of $325.00 per warrant to ACTOIL. The warrants are exercisable at the election of ACTOIL with cash or net common unit settled at any time before February 22, 2024, upon the sale of all or substantially all of the assets of the Company or immediately prior to an initial public offering. The common unit warrants cannot be net cash settled and are not contingently or mandatorily redeemable and therefore are equity classified.

NOTE 9—Preferred Units

In 2018, in connection with the acquisition of mineral rights, royalty interests and other associated assets, the Company issued to private investors (the “Preferred Investors”) 275,000 Preferred Units (“Preferred Units”), par value of $1,000 per Preferred Unit, for an aggregate purchase price of $275.0 million, less an original issuance discount of $4.1 million, and transaction costs and advisory fees of $9.8 million.

The Preferred Investors received cumulative quarterly dividends at a rate of 8.0% per annum. The Company was required to pay dividends to the Preferred Investors within ten business days after each fiscal quarter (March 31, June 30, September 30, and December 31). Dividends were eligible to be paid in additional shares of Preferred Units (“PIK dividends”) for eight non-consecutive quarters. Subsequent to the eight quarters, all dividends were required to be paid in cash.

As the Preferred Investors have an option to redeem the Preferred Units at a future date, the proceeds from the Preferred Units have been included in temporary equity. Through September 30, 2020, the Preferred Units were remeasured each reporting period by accreting the initial value to the expected redemption value at the Preferred Investors’ first non-contingent redemption date of January 1, 2028. Upon completion of the Recapitalization Transaction in February 2021, the Preferred Units were remeasured to recognize the estimated change in redemption value triggered by the exchange. Please see Note 2—Basis of Presentation and Principles of Consolidation and Recapitalization Transaction to our consolidated financial statements for more information. Accumulated accretion, including the remeasurement at December 31, 2020, was $118.1 million as of December 31, 2020. The estimated redemption value, excluding unpaid dividends, was $402.7 million as of December 31, 2020. The accretion is presented as a deemed dividend within the statements of members’ equity and recorded in temporary equity on the consolidated balance sheets.

The Preferred Units had no voting rights. The Preferred Units were evaluated for embedded derivative features, some of which require bifurcation; however, those features had insignificant value upon issuance. The Company determined that the inputs and assumptions used to value the embedded derivative features of the Preferred Units had not significantly changed since issuance and no value has been assigned to the embedded features as of December 31, 2020.

As of December 31, 2020, the Company had 295,859 Preferred Units authorized, issued and outstanding. For the year ended December 31, 2020, the Company declared dividends of $23.1 million on the Company’s outstanding Preferred Units. The Company elected to pay PIK Dividends resulting in a distribution of 10,755 Preferred Units at a par value of $1,000 per Preferred Unit for an aggregate amount of $10.8 million and a $12.3 million tax related cash distribution for the year ended December 31, 2020. As of December 31, 2020, $3.1 million of the dividends were accrued, which were paid in January 2021.

On February 22, 2021, as part of the Recapitalization Transaction all 295,859 Preferred Units were exchanged for 800,000 Common Units at a redemption value of approximately $400.0 million.

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The following table summarizes the activities for the Company’s Preferred Units (in thousands):

Beginning balance as of January 1, 2020 (Predecessor)	$	324,893
Accretion of preferred units	64,352
PIK dividends	10,755
Ending balance as of December 31, 2020 (Predecessor)	$	(400,000)
Recapitalization transaction	(400,000)
Ending balance as of December 31, 2021 (Successor)	$	—

NOTE 10—Related Party Transactions

Midstream Transactions

During the periods from January 1, 2021 through February 22, 2021 (Predecessor), February 23 through December 31, 2021 (Successor) and the year ended December 31, 2020 (Predecessor), the Company received $4.1 million, $37.3 million and $19.6 million, respectively, in revenue and incurred $2.2 million, $11.6 million and $16.8 million in gathering and transportation fees, respectively, with a midstream company that is accounted for using the equity method. Please see Note 3—Summary of Significant Accounting Policies to the Company’s consolidated financial statements for more information regarding the investment in unconsolidated entity. During the period from February 23, 2021 through December 31 2021 (Successor), the Company received $93.5 million in revenue from a midstream company in which one of our members has an investment.

MSA with GWOC 

For the period January 1, 2020 to July 17, 2020, costs incurred by GWOC on behalf of GWP were $16.2 million. Costs related to the MSA were passed through to GWP as incurred with no markup and are in general and administrative expense on the consolidated statements of operations. There is no proforma statement of operations related to GWP’s acquisition of GWOC as there was no markup of general and administrative expenses incurred by GWOC on behalf of GWP.

Due to/from Affiliates

As of December 31, 2021 and 2020, there were amounts included in other assets, primarily related to deferred compensation of $4.7 million and $4.1 million, respectively.

NOTE 11—Commitments and Contingencies

Volume Commitments

The Company has entered into firm sales agreements that require the Company to deliver minimum quantities of oil and natural gas to certain third parties through 2029. If the Company is unable to fulfill all contractual obligations, the Company may be required to pay penalties or damages pursuant to these agreements. Additionally, the Company has entered into agreements to purchase oil from certain third parties in 2021. If no deliveries were made, the Company

would pay $115.2 million in 2022, $74.4 million in 2023, $72.0 million in 2024, $58.6 million in 2025, $51.6 million in 2026 and $74.4 million thereafter. As of December 31, 2021, the Company anticipates meeting all delivery commitments.

In anticipation of the Company’s future drilling activities in the Wattenberg Field, in 2019 the Company entered into a ten-year water disposal agreement with a midstream company. The Company will be bound by the volume requirements in the agreement on the actual in-service-date of the pipeline connection. As of December 31, 2021, the pipeline is not in service, and therefore, the Company does not have any contractual commitment. In January 2022, the agreement was terminated.

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Pipeline Connections

Well connection costs include costs the Company is liable for to connect production from the Company’s wells to existing pipelines. As of December 31, 2021, there are no unpaid well connection costs for wells that have commenced construction prior to December 31, 2021.

Other Commitments

The other balance includes commitments for debt, drilling, operating rent and surface use agreement commitments. If the Company is unable to fulfill all contractual obligations, the Company may be required to pay penalties or damages pursuant to these agreements of $3.8 million in 2022, $2.8 million in 2023, $1.7 million in 2024, $1.0 million in 2025, $1.0 million in 2026 and $0.7 million thereafter.

The Company has secured insurance policies including general property and liability, among others, to protect the Company against the risk of a release of hydrocarbons into the atmosphere due to excess pressure built up in the well and also environmental liability insurance to provide protection in the event of leaks in its pipes, tanks, or pits, which could potentially create environmental contamination.

Litigation

The Company is party to ongoing legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, the Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations or liquidity.

General

The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax and other matters. The Company records liabilities when it is probable that future costs will be incurred, and such costs can be reasonably estimated. Such liabilities are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations or cash flows.

NOTE 12—Significant Customers and Other Concentrations

Significant Customers

During the periods from January 1, 2021 through February 22, 2021 (Predecessor), February 23, 2021 through December 31, 2021 (Successor) and the year ended December 31, 2020 (Predecessor), presented in the tables below, the Company’s revenues consisted of certain customers whose purchases exceeded 10% of the total oil, natural gas and NGL

F-24

revenues of the Company. The Company believes that the loss of a single purchaser would not materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells production.

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021 through February 22, 2021		Year Ended December 31, 2020
Customer A	33	%	31	%	16	%
Customer B	14	%	13	%	15	%
Customer C	18	%	11	%	9	%
Customer D	12	%	9	%	10	%
Customer E	3	%	18	%	16	%
Customer F	8	%	9	%	12	%
Total	88	%	91	%	78	%

Concentration of Market Risk

The future results of the Company’s oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for crude oil and natural gas in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with any certainty.

The Company operates in the exploration, development, and production phases of the oil and natural gas industry. Its receivables include amounts due from purchasers of oil and natural gas production and amounts due from joint interest owners for its respective portions of operating expense and exploration and development costs. While certain of these customers and joint interest owners are affected by periodic downturns in the economy in general or in its specific segment of the natural gas or oil industry, the Company believes its level of credit related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s consolidated results of operations and cash flows in the long term. Trade receivables are generally not collateralized.

NOTE 13—Employee Benefit Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. In accordance with the 401(k) plan, the Company provides matching contributions equal to 50% of the first 6% of employees’ eligible compensation contributed to the plan. As of August 1, 2021 the plan was amended and the Company is now providing matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.1 million, $0.5 million and $0.4 million for period January 1, 2021 through February 22, 2021 (Predecessor), the period February 23, 2021 through December 31, 2021 (Successor) and for the year ended December 31, 2020 (Predecessor).

NOTE 14—Recently Issued and Adopted Accounting Pronouncements

In June 2016, the FASB issued Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (Topic 326) (“ASU 2016-13”). ASU 2016-13 affects trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The Company is currently evaluating the impact of adoption of ASU 2016-13 on its consolidated financial statements. 

In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (Topic 842) (“ASU 2016-02”). The new standard requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding lease liability, including today’s operating leases. The standard is effective for fiscal years beginning after December 15, 2021, and interim periods within fiscal years beginning after December 15, 2022,

F-25

with early adoption permitted. The FASB subsequently issued ASU 2018-01, which provided additional implementation guidance. The Company is currently evaluating the impact of ASU 2016-02 on its consolidated financial statements and related disclosures. ASU 2016-02 does not apply to mineral leases.

NOTE 15—Subsequent Events

The Company has evaluated all subsequent events through the date the financial statements are available to be issued of March 10, 2022, for items that should potentially be recognized or disclosed in these financial statements.

In January 2022, the Company purchased all issued and outstanding membership interests in Pioneer Water Pipeline LLC for a purchase price of $1.0 million.

In January 2022, the Company consented to the termination and distribution of the GWOC portion of the Broe Deferred Compensation Plan (“Broe DCP”) which was completed in February 2022. The termination and distribution of the GWOC portion of the Broe DCP resulted in a reduction of other non-current assets (Due from Affiliates) by approximately $4.7 million (Please see Note 10 – Related Party Transactions) and the reduction of other non-current liabilities by approximately $3.6 million as a result of the full distribution of funds to participants in the GWOC portion of the Broe DCP.

On February 26, 2022, PDC Energy, Inc. (“PDC”) entered into a definitive membership interest purchase agreement with the Company and all of its common unitholders under which PDC will acquire all of the membership interests of the Company directly from the common unitholders in a transaction valued at approximately $1.3 billion. The transaction is expected to close in the second quarter of 2022. In the event the acquisition closes, GWPM, the entity that owns a 10% equity interest in a midstream company (Please see Note 3), will be spun-off to all of the Company’s common unitholders on a pro rata basis. This spun-off entity (“Transition Services Company”) will enter into an agreement with PDC to provide transition services for a period of up to six months after the closing of the acquisition for a transaction services fee. A currently undetermined number of the Company’s current employees will become employees of the Transition Services Company. All of GWP’s current common unitholders will contribute a portion of the cash proceeds that they receive directly from PDC into the Transition Services Company to fund the costs of managing it and to pay severance and incentive-related costs that are contingent upon the acquisition closing (collectively, the “Contingent Employee Costs”). All Contingent Employee Costs will be incurred and paid by the Transition Services Company, and no liability for Contingent Employee Costs will be assumed by PDC at the close of the transaction. Due to the variability in the number of employees that will become employed by PDC, variability in the number of employees that will become employees of the Transition Services Company, and the variability of the contingent incentive-related costs due to any transaction-related purchase price adjustments, the Contingent Employee Costs are not estimable at this time.

NOTE 16— Oil and Natural Gas Information (Unaudited)

Capitalized Costs

A summary of the Company’s capitalized costs are contained in the table below (in thousands).

	December 31,
	2021		2020
Proved oil and natural gas properties	$	1,447,256	$	2,584,641
Unproved oil and natural gas properties	17,469		48,071
Wells in progress	120,010		95,891
Gross oil and gas properties	1,584,735		2,728,603
Less: accumulated depletion	(125,591)		(1,074,303)
Oil and gas properties, net	1,459,144		1,654,300

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    Results of Operations for Oil, Natural Gas and NGL Producing Properties

    The following are the results of operations of the Company’s oil and natural gas producing activities before corporate overhead and interest expenses (in thousands):

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
Revenues	$	609,971	$	96,659	$	342,323
Operating Expenses:
Production expenses	97,270		18,371		92,342
Exploration expenses	3,983		722		6,751
Depreciation, depletion and amortization	127,608		45,670		298,552
Total operating expenses	228,861		64,763		397,645
Results of Operations	$	381,110	$	31,896	$	(55,322)

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

    A summary of the Company’s costs incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
Acquisition costs
Proved properties	$	—	$	—	$	794
Unproved properties	3,009		211		4,604
Development costs	256,219		40,879		288,360
Exploration costs	3,983		722		6,751
Total acquisition, development and exploration costs	$	263,211	$	41,812	$	300,509

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2021 and 2020, which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2021 and 2020 was based on an unweighted 12-month average WTI posted price per Bbl for oil, a Henry Hub spot natural gas price per Mcf for natural gas, and a percentage of WTI posted price per barrel for NGLs, adjusted for differential to realized prices, as set forth in the following table (in thousands):

	2021		2020
Oil (per Bbl)	$	63.54	$	36.09
Natural gas (per Mcf)	26.50		1.53
NGLs (per Bbl)	3.11		11.06

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Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the DJ Basin of Colorado. Moreover, the Company may be required to write down its proved undeveloped reserves if it revises its drill plan to not drill those reserves with five years of initial booking. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, primarily in the Denver-Julesburg of Colorado. All of the estimates of the proved reserves at December 31, 2021, 2020 and 2019 were audited by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a roll-forward of the total proved reserves for the years ended periods ended December 31, 2021 and February 22, 2021 and for the year ended December 31, 2020 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year (in thousands):

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			Natural Gas
	Oil	Natural Gas	Liquids	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)
End of year, December 31, 2019 (Predecessor)	92,775	500,610	44,945	221,155
Revisions	(18,387)	(56,712)	5,161	(22,678)
Extensions and discoveries	7,554	36,767	3,998	17,680
Acquisition of reserves	372	1,867	195	878
Production	(8,872)	(40,809)	(5,141)	(20,815)
End of year, December 31, 2020 (Predecessor)	73,442	441,723	49,158	196,220
Revisions	297	2,113	355	1,004
Extensions and discoveries	289	1,882	216	819
Production	(1,651)	(9,029)	(1,113)	(4,269)
End of period, February 22, 2021 (Predecessor)	72,377	436,689	48,616	193,774
February 23, 2021 (Successor)	72,377	436,689	48,616	193,774
Revisions	(10,341)	(25,647)	7,246	(7,369)
Extensions and discoveries	4,885	28,317	3,800	13,404
Production	(5,862)	(29,929)	(4,042)	(14,892)
End of period, December 31, 2021 (Successor)	61,059	409,430	55,620	184,917
Proved developed reserves:
December 31, 2020	22,935	201,084	21,834	78,283
February 22, 2021	22,504	199,730	21,688	77,480
December 31, 2021	23,526	212,011	28,340	87,201
Proved undeveloped reserves:
December 31, 2020	50,507	240,639	27,324	117,937
February 22, 2021	49,873	236,959	26,928	116,294
December 31, 2021	37,533	197,419	27,280	97,716

The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbl.

Extensions and discoveries of 13.4 MMBoe of proved reserves during the period February 23, 2021 through December 31, 2021, were primarily the result of a 12.8 MMBoe increase due to drilling new wells during the period and a 0.6 MMBoe increase of new proved undeveloped locations added during the period that were not previously considered proved reserves. Extensions and discoveries of 0.8 MMBoe of proved reserves during the period January 1, 2021 through February 22, 2021, were primarily the result of a 0.8 MMBoe increase due to drilling new wells during the period and no increase of new proved undeveloped locations added during the period that were not previously considered proved reserves. Extensions and discoveries of 17.7 MMBoe of proved reserves during the year ended December 31, 2020, were primarily the result of a 7.4 MMBoe increase due to drilling new wells during the period and a 10.3 MMBoe increase of new proved undeveloped locations added during the period that were not previously considered proved reserves.

No divestitures of reserves during the year ended periods ended February 23, 2021 through December 31, 2021 and January 1, 2021 through February 22, 2021 and for the year ended December 31, 2020.

Revisions of 7.4 MMBoe of proved reserves during the period February 23, 2021 through December 31, 2021 were primarily the result of the Company adjusting the well spacing from a maximum 30 wells per 1-mile wide drilling block to a maximum of 24 wells per 1-mile wide drilling block as a result of well performance and other operators results in immediately offset locations, resulting in a downward revision of 13.8MMBoe. Additionally, the Company

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made adjustments to their well type curves, currently producing forecasts, and updated completion designs during the year, resulting in an upward revision of 6.4MMBoe. Revisions of 1.0 MMBoe of proved reserves during the period from January 1, 2021 through February 22, 2021 were due to working interest changes in certain wells. Revisions of 22.7 MMBoe of proved reserves during the year ended December 31, 2020 were primarily the result of the Company adjusting the well spacing from a maximum 30 wells per 1-mile wide drilling block to a maximum of 24 wells per 1-mile wide drilling block as a result of well performance and other operators results in immediately offset locations, resulting in a downward revision of 7.1MMBoe. Additionally, the Company made adjustments to their well type curves, currently producing forecasts, and updated completion designs during the year, resulting in a downward revision of 15.6MMBoe.

Acquisitions of 0.9 MMBoe and 3.6 MMBoe of proved reserves during the year ended December 31, 2020 and 2019, respectively, related to acquiring proved reserves.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2021, February 22, 2021, and December 31, 2020 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
Future cash inflows (total revenues)	$	6,625,320	$	3,789,211	$	3,869,537
Future production costs (severance and ad valorem taxes plus LOE)	(2,566,371)		(1,976,056)		(2,001,843)
Future development costs (capital costs)	(1,002,123)		(923,648)		(932,478)
Future income tax expense1	—		—		—
Future net cash flows	3,056,826		889,507		935,216
10% annual discount for estimated timing of cash flows	(1,107,397)		(354,180)		(368,722)
Standardized measure of discounted future net cash flows	$	1,949,429	$	535,327	$	566,494

_____________

(1)    Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company is a limited liability company not subject to entity-level federal income taxation as of December 31, 2021 and 2020.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

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    Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

	(Successor)		(Predecessor)		(Predecessor)
	Period from February 23, 2021 through December 31, 2021		Period from January 1, 2021, through February 22, 2021		Year Ended December 31, 2020
Standardized Measure, beginning of the year	$	535,327	$	566,494	$	1,876,715
Net change in prices and production costs	1,613,618		23,153		(1,244,422)
Net change in future development costs	115,936		(412)		(124,306)
Sales, Less production costs	(512,702)		(78,288)		(249,979)
Extensions	223,657		6,357		78,274
Acquisitions	—		—		2,031
Divestitures	—		—		—
Revisions of previous quantity estimates	18,951		152		(97,984)
Previously estimated development costs incurred	70,049		8,895		173,719
Accretion of discount	48,423		8,226		187,671
Changes in timing and other	(163,830)		750		(35,225)
Standardized Measure, end of the year	$	1,949,429	$	535,327	$	566,494

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