Document

EX-99.1 4 ex991-bighornpermianresour.htm EX-99.1 Document

Exhibit 99.1

Bighorn Permian Resources, LLC

Consolidated Financial Statements as of December 31, 2021 (successor) and December 31, 2020 (predecessor) and for the period from February 2, 2021 to December 31, 2021 (successor), the period from January 1, 2021 to February 1, 2021 (predecessor) and for the year ended December 31, 2020 (predecessor), and Independent Auditors’ Report

Table of Contents

Page


Report of Independent Auditors’			1
Consolidated Balance Sheets as of December 31, 2021 (successor) and 2020 (predecessor)			3
Consolidated Statements of Operations for the period from February 2, 2021 to December 31, 2021 (successor); for the period from January 1, 2021 to February 1, 2021 (predecessor); and for the year ended December 31, 2020 (predecessor)			4
Consolidated Statements of Changes in Members’ Capital for the period from February 2, 2021 to December 31, 2021 (successor); for the period from January 1, 2021 to February 1, 2021 (predecessor); and for the year ended December 31, 2020 (predecessor)			5
Consolidated Statements of Cash Flows for the period from February 2, 2021 to December 31, 2021 (successor); for the period from January 1, 2021 to February 1, 2021 (predecessor); and for the year ended December 31, 2020 (predecessor)			6
Notes to Consolidated Financial Statements			8

INDEPENDENT AUDITOR’S REPORT

To the Members of Bighorn Permian Resources, LLC

Opinion

We have audited the consolidated financial statements of Bighorn Permian Resources, LLC and subsidiary (the “Company”), which comprise the consolidated balance sheets as of December 31, 2021 (“successor”) and 2020 (“predecessor”), and the related consolidated statements of operations, changes in members’ capital, and cash flows for the period from February 2, 2021 to December 31, 2021 (successor); for the period from January 1, 2021 to February 1, 2021 (predecessor); and for the year ended December 31, 2020 (predecessor) and the related notes to the consolidated financial statements (collectively referred to as the "financial statements").

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 (successor) and December 31, 2020 (predecessor), and the results of its operations and its cash flows for the period from February 2, 2021 to December 31, 2021 (successor), for the period from January 1, 2021 to February 1, 2021 (predecessor) and for the year ended December 31, 2020 (predecessor) in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the 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 audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Emphasis of Matter Regarding Fresh-Start Reporting

As discussed in Note 3 to the financial statements, on January 29, 2021, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective on February 1, 2021. Accordingly, the accompanying financial statements have been prepared in conformity with FASB Accounting Standard Codification 852, Reorganizations, for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note 1 to the financial statements. Our opinion is not modified with respect to this matter.

Responsibilities of Management for the Financial Statements

Management is responsible for the preparation and fair presentation of the 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 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 that the financial statements are issued.

Auditor’s Responsibilities for the Audit of the 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 auditor’s 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 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 GAAS, we:

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

•Identify and assess the risks of material misstatement of the 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 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 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.

May 27, 2022


BIGHORN PERMIAN RESOURCES, LLC
CONSOLIDATED BALANCE SHEETS
(In thousands)
	Successor	Predecessor
	December 31, 2021	December 31, 2020
Assets
Current assets
Cash and cash equivalents	$ 14,996	$ 47,664
Restricted cash	─	162
Accounts receivable − oil, natural gas and NGLs	54,493	43,495
Accounts receivable − joint operations and other, net	6,249	2,240
Receivables from related party	31,789	4,910
Other current assets	4,065	8,105
Total current assets	111,592	106,576
Noncurrent assets
Oil and natural gas properties, successful efforts method	864,612	2,194,922
Less: accumulated depreciation, depletion and amortization	(52,950)	(1,496,832)
Oil and natural gas properties, net	811,662	698,090
Other property and equipment, net	776	8,603
Other assets	83	7,666
Total assets	$ 924,113	$ 820,935

Liabilities and members' capital
Current liabilities
Debtor-in-possession financing	─	75,000
Accrued interest payable	─	362
Accounts payable	16,450	28,235
Revenue payable	─	20,509
Commodity derivatives	13,471	─
Commodity derivatives – related party	52,008	─
Total current liabilities	81,929	124,106
Noncurrent liabilities
Debt	150,802	─
Asset retirement obligations	27,430	24,774
Commodity derivatives	24,496	─
Commodity derivatives – related party	7,993	─
Suspense payable	17,536	─
Warrant liability	30,562	─
Liabilities subject to compromise	─	1,378,512
Total liabilities	340,748	1,527,392
Members' capital (deficit)	583,365	(706,457)
Total liabilities and members' capital	$ 924,113	$ 820,935

The accompanying notes are an integral part of these consolidated financial statements.


BIGHORN PERMIAN RESOURCES, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
	Successor	Predecessor
	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 1, 2021	Year ended December 31, 2020
Revenues
Oil, natural gas, and NGL sales	$ 479,692	$ 25,360	$ 233,556
Oil, natural gas, and NGL sales − related party	─	3,386	39,534
Total revenues	479,692	28,746	273,090
Operating expenses
Lease operating expense	53,255	5,113	70,594
Production and ad valorem taxes	31,648	(1,982)	17,335
Transportation, gathering, and processing	42,148	3,521	37,553
Depreciation, depletion, amortization, and accretion2	54,347	6,912	484,185
General and administrative expenses (Includes management fees to related party of $14,691 for the successor period from February 2, 2021 to December 31, 2021; there were no management fees to related party for the predecessor period from January 1, 2021 to February 1, 2021 and for the year ended December 31, 2020.)	24,161	12,960	36,516
Prepetition professional fees	─	─	18,228
Impairment expense	─	─	3,175,786
Exploration and other expense	─	4	4,708
Total operating costs and expenses	205,559	26,528	3,844,905
Income (loss) from operations	274,133	2,218	(3,571,815)
Other income (expense)
Net (loss) gain on commodity derivatives – realized	(75,670)	─	37,877
Net loss on commodity derivatives − unrealized	(97,968)	─	─
Net loss on sale of other property and equipment	(177)	─	─
Change in fair value of warrant liability	(4,912)	─	─
Interest expense	(9,332)	(1,850)	(76,704)
Other income (expense)	─	8	(1,261)
Reorganization items, net	─	703,747	(178,308)
Net income (loss) before income taxes	86,074	704,123	(3,790,211)
Income tax (expense) benefit	(1,300)	─	11,997
Net income (loss)	84,774	704,123	(3,778,214)
Net loss attributable to noncontrolling interest	─	10,351	(7,654)
Net income (loss) attributable to controlling interest	$ 84,774	$ 693,772	$ (3,770,560)

The accompanying notes are an integral part of these consolidated financial statements.


BIGHORN PERMIAN RESOURCES, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(In thousands)
	Members' Capital	Noncontrolling Interest	Total Members' Capital
Balances as of January 1, 2020 (Predecessor)	$ 2,984,241	$ 87,100	$ 3,071,341
Members' contributions	419	─	419
Unit based compensation	(38)	─	(38)
Issuance of common units upon exercise of warrants	─	35	35
Net income (loss)	(3,770,560)	(7,654)	(3,778,214)
Balance as of December 31, 2020 (Predecessor)	(785,938)	79,481	(706,457)
Members' contributions	2,374	─	2,374
Distributions	(40)	─	(40)
Net income (loss)	693,772	10,351	704,123
Cancellation of Predecessor members’ capital	89,832	(89,832)	─
Issuance of Successor common units	498,591	─	498,591
Balance as of February 1, 2021 (Predecessor)	498,591	─	498,591

Balance as of February 2, 2021 (Successor)	498,591	─	498,591
Net income	84,774	─	84,774
Balance as of December 31, 2021 (Successor)	$ 583,365	$ ─	$ 583,365

The accompanying notes are an integral part of these consolidated financial statements.


BIGHORN PERMIAN RESOURCES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
	Successor	Predecessor
	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 2, 2021	Year ended December 31, 2020

Cash flows from operating activities:
Net income (loss)	$ 84,774	$ 704,123	$ (3,778,214)
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities:
Depreciation, depletion, amortization, and accretion	54,347	6,912	484,185
Net loss (gain) on derivative contracts	97,968	─	(37,877)
Change in fair value of warrant liability	4,912	─	─
Accretion of debt discount	─	─	7,373
Amortization of debt issuance costs	─	─	3,179
Impairment expense	─	─	3,175,786
Reorganization items, net	─	(723,468)	134,909
Settlement of commodity derivative	─	─	36,705
Other	177	5,871	1,930
Changes in operating assets and liabilities:
Accounts receivable − oil, natural gas and NGLs	(25,633)	(4,585)	11,339
Accounts receivable − joint operations and other	8,961	(4,343)	2,760
Accounts receivable − oil, natural gas and NGLs - related party	─	─	9,169
Other assets	184	325	2,024
Accounts payable and other liabilities	(10,693)	(42,340)	(82,799)
Deferred income tax liability	─	─	(11,814)
Asset retirement obligations	(59)	─	(2,048)
Net cash flows provided by (used in) operating activities	214,938	(57,505)	(43,393)
Cash flows from investing activities:
Additions of oil and natural gas properties	─	(5)	(5,779)
Development of oil and natural gas properties	(40,914)	─	─
Purchase of other property and equipment	(78)	─	(3,875)
Proceeds from sale of oil and natural gas properties	5,120	─	─
Proceeds from sale of other property and equipment	2,697	─	2,056
Change in amount due from related party, net	(33,319)	─	─
Net cash flows used in investing activities	(66,494)	(5)	(7,598)


Cash flows from financing activities:
Long-term debt borrowings	─	38,100	95,000
DIP financing costs	─	─	(1,755)
Members’ contributions	─	2,334	420
Exercise of warrants	─	─	35
Payment of debt principal	(164,198)	─	(15,090)
Net cash flows (used in) provided by financing activities	(164,198)	40,434	78,610
Change in cash and cash equivalents	(15,754)	(17,076)	27,619
Cash and cash equivalents
Beginning of period	30,750	47,826	20,207
End of period	$ 14,996	$ 30,750	$ 47,826

The accompanying notes are an integral part of these consolidated financial statements.

BIGHORN PERMIAN RESOURCES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2021 (SUCCESSOR) AND DECEMBER 31, 2020 (PREDECESSOR) AND FOR THE PERIOD FROM FEBRUARY 2, 2021 TO DECEMBER 31, 2021 (SUCCESSOR), THE PERIOD FROM JANUARY 1, 2021 TO FEBRUARY 1 (PREDECESSOR), 2021 AND FOR THE YEAR ENDED DECEMBER 31, 2020 (PREDECESSOR)

Note 1 – Description of Business and Summary of Significant Accounting Policies

Description of Business

Bighorn Permian Resources, LLC (“BPR”, the “Company”, the “Successor”, the “Parent”, “we”, “us”, and “our”), a Delaware limited liability company, and its subsidiary, Bighorn Asset Company, LLC were formed to own and operate oil and gas properties and other assets of the reorganized Sable Land Company, LLC, which was a subsidiary of Sable Permian Resources, LLC (and its affiliates) (“SPR”, or the “Predecessor”). As the context may require, the Successor refers to the period after February 1, 2021. References to historical activities of the “Company” prior to February 2, 2021, refer to activities of the Predecessor.

SPR was a Delaware limited liability company formed in October 2014. SPR's earnings and operating cash flows were also derived from its direct 99% ownership in SPR Holdings, LLC (“SPR Holdings”, formerly known as American Energy Permian Holdings, LLC, Sable Permian Resources Holdings, LLC and Permian Resources Holdings, LLC), which was the parent of Sable Permian Resources Finance, LLC (“SPR Finance”, formerly known as American Energy - Permian Basin, LLC, Sable Permian Resources Land, LLC, and Permian Resources, LLC), and indirect 1% ownership in SPR Holdings, through its wholly-owned subsidiary, SPR Stock Holdings, LLC. Sable Land Company, LLC ("Sable Land", formerly known as AEPB Acquisition Company, LLC and Sable Acquisition Company, LLC) was a wholly owned subsidiary of SPR Finance, and pursued the acquisition, development, and production of unconventional oil and natural gas reserves entirely in the southern Midland Basin within the greater Permian Basin of west Texas.

During the predecessor period, our indirect subsidiary, SPR Finance, was owned 98.43% by SPR Holdings, 0.1% by SPRH Finance Corporation, and 1.47% by third-parties who were issued SPR Finance common units upon exercise of warrants in April 2020.

PRES New Equity, LLC ("PRES NE"), together with PRES Initial Capital Aggregator, LLC ("PRES ICA"), collectively "Members", owned 100% of our Predecessor equity. SPR Holdings was formed in April 2014 as a Delaware limited liability company by investment funds affiliated with and managed by The Energy & Minerals Group ("EMG"), First Reserve Corporation and other investors (collectively, the "Formation Sponsors"), to act as the parent for SPR Finance.

BPR entered into a Management Services Agreement (the “MSA”) with FDL SMB Management Company LLC (“FDL SMB”) on February 1, 2021. FDL SMB was engaged to act as an Agent for the Company while providing all the personnel, facilities, goods and equipment not otherwise provided by the Company as may be reasonable and necessary to support the day-to-day operations of the Company’s oil and gas properties, under the direction of the Company and its board of directors. FDL Operating, LLC, an affiliate of FDL SMB, operates all of the Company’s wells that are not operated by others. See Note 10 Related Party Transactions.

On June 25, 2020 (the “Petition Date”), SPR and its subsidiaries (together, the “Debtors”) filed for voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the Southern District of Texas (the “Bankruptcy Court”). The chapter 11 proceedings were jointly administered under the caption In re Sable Permian Resources, LLC, et al. (Case No. 20-33193) (the “Chapter 11 Cases”).

In connection with the Chapter 11 Cases, on June 25, 2020, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash and collateral and debtor-in-possession financing. On June 26, 2020, the U.S. Bankruptcy Court approved the DIP Motion on an interim basis and on a final basis on August 4, 2020.

On December 1, 2020, the Debtors filed with the Bankruptcy Court the Joint Plan of Reorganization and Liquidation for Sable Permian Resources, LLC and its Affiliate Debtors, which was subsequently amended on December 14, 2020, December 15, 2020, and January 26, 2021 (as amended or supplemented, the “Plan”) and the related disclosure statement.

On January 29, 2021, the Bankruptcy Court entered an order approving the Debtors’ disclosure statement and confirming the Plan (the “Confirmation Order”) with respect to SPR pursuant to section 1129 of the Bankruptcy

Code. On February 1, 2021 (the “Effective Date”), the Plan became effective in accordance with its terms, Sable Land Company, LLC emerged from the Chapter 11 Cases and was renamed as Bighorn Asset Company, LLC while retaining all the powers of a limited liability company under the applicable non-bankruptcy law. Operating activities of February 1, 2021 were not deemed material and were included in the Successor period. In accordance with the Plan, SPR and its remaining subsidiaries will in due course be wound down and dissolved in accordance with applicable law.

Upon emergence, the Company applied fresh start accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852 “Reorganizations” (“ASC 852”). The application of fresh start accounting resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. Accordingly, our financial statements and notes after the Effective Date are not comparable to our financial statements and notes on and prior to that date. See Note 4 Fresh Start Accounting for additional information.

Summary of Significant Accounting Policies

Basis of Presentation

These consolidated accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The Company had no items of other comprehensive income in any of the periods.

Principles of Consolidation

The consolidated financial statements include the accounts of all our wholly owned subsidiaries. All intercompany accounts and balances have been eliminated in consolidation.

Risk and Uncertainties

The Company’s revenue, profitability, and future rate of growth are substantially dependent on prevailing prices for oil, natural gas, and natural gas liquids (“NGLs”). Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital, and on the quantities of oil, natural gas, and NGL reserves that we can economically produce. Other risks and uncertainties that we could be affected by in a low oil and natural gas price environment also include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks, and our ability to meet covenants in our credit facility.

The Company considered the impact of the ongoing COVID-19 pandemic on the assumptions and estimates used in the consolidated financial statements. The effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which has and could continue to contribute to price volatility, impact prices the Company receives for crude oil, natural gas and NGLs, and materially and adversely affect the demand for and marketability of its production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity.

Additionally, in February 2022 the Russia and Ukraine conflict led to economic sanctions imposed against Russia by the U.S. and certain European nations. Such sanctions may impact companies in many sectors and could lead to price volatility in the global energy industry, particularly for the Company’s crude oil, natural gas, and NGLs. The extent and strength of the sanctions are still developing, and the corresponding effect on the Company remains uncertain.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of expenses during the reporting periods. Significant estimates include, but are not limited to, (i) oil and natural gas reserves, (ii) depreciation and depletion, (iii) impairment evaluations, (iv) fair value of assets and liabilities reflected as part of BPR’s reorganization and emergence from Chapter 11, (v) fair value of derivative instruments, (vi) asset retirement obligations, (vii) the amount of accrued assets and liabilities, and (viii) the fair value of warrants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including

the current economic environment. Although management believes its estimates and assumptions are reasonable, changes in facts and circumstances or the discovery of new information may result in revised estimates, and actual results may differ from these estimates.

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are maintained with a major financial institution in the United States. Deposits with this financial institution may exceed the amount of insurance provided on such deposits; however, the financial stability of this financial institution is regularly monitored, and the Company believes that it does not have exposure to any significant default risk.

Restricted Cash

No restricted cash existed as of December 31, 2021. As of December 31, 2020, our restricted cash balance included $0.2 million which represented adequate assurance related to utilities that is included in current assets.

Accounts Receivable

Accounts receivable consists of receivables from oil, natural gas, and NGL production delivered to purchasers, joint interest owners on properties the Company operates, and counterparties to the Company’s derivative contracts. Accounts receivables are recorded at the invoiced amount and do not bear interest. Any receivables outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for doubtful accounts by considering the length of time accounts are past due and the history of collecting receivables. Bad debt expense is recorded when it becomes probable the Company will not collect all amounts due in accordance with the contractual terms of the receivable.

As of December 31, 2021, there was no allowance for doubtful accounts. As of December 31, 2020, the allowance for doubtful accounts was $4.0 million.

Fair Value of Financial Instruments

Financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, warrants, and long-term debt. The carrying amounts of the Company’s financial instruments other than derivatives, warrants, and long-term debt approximate fair value because of the short-term nature of the items. Derivatives and warrants are recorded at fair value and marked to market each reporting period. See Note 9 Fair Value Measurements for the fair value of the Company’s debt instruments.

Revenue Recognition

Sales of oil, natural gas, and NGLs are recognized at the point in time when control of the product is transferred to the customer and collectability is reasonably assured. For the Company’s crude oil contracts, transfer of control occurs at the delivery point stipulated in the contract. For the Company’s gas and NGL contracts, transfer of control occurs either at the plant tailgate after processing or at the delivery point stipulated in the contract. The Company’s contracts’ pricing provisions are typically tied to a market index, with certain adjustments based on, among other factors, physical location, quality of the oil or gas, and prevailing supply and demand conditions. As a result, the price of the oil, gas and NGLs fluctuate to remain competitive with other available oil, gas, and NGL supplies in the market. The Company believes that the pricing provisions of our oil, gas, and NGL contracts are customary in the industry. Revenues associated with proved properties for which we operate and have a working interest with other producers are recognized based on the actual volumes sold attributable to our interest, net of any royalty interest. Any amounts due to royalty and working interest owners in predecessor period were recognized as revenue payable. There were no material gas imbalances as of December 31, 2021 and 2020.

Oil and Natural Gas Properties

The Company applies the successful efforts method of accounting for its oil and natural gas properties whereby costs incurred to acquire mineral interests in oil and natural gas properties and to drill, equip and complete productive exploratory wells and development wells are capitalized. In addition, costs associated with enhanced recovery operations and replacements or upgrades that appreciably improve the efficiency or productive capacity of existing properties or extend their economic lives are capitalized. Ordinary repairs and maintenance costs are expensed as incurred.

Under the successful efforts’ method of accounting, exploratory drilling costs are capitalized on the balance sheets and not subject to depletion, pending determination of whether a well has found proved reserves in economically producible quantities. If proved reserves are found by an exploratory well, the associated capitalized costs become part of the oil and natural gas properties depletion base.

Acquisition costs of unproved properties are reclassified to prove properties when all necessary conditions are met for associated reserves to be classified as proved.

Costs associated with drilling exploratory wells that were unsuccessful in finding economically producible quantities are recognized as exploration expense as incurred. Geological and geophysical costs, seismic costs related to an area with no proved reserves, amortization of the costs of unproved properties assessed for impairment on a group basis, and the costs of carrying and retaining unproved properties are charged to exploration expense as incurred.

When individual proved properties that are amortized as part of a group of properties are sold, the proceeds from the sale and the associated capitalized costs of the proved properties are credited and charged, respectively, to accumulated depletion. Gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.

Proceeds from the sales of all or a part of an interest in individual unproved properties assessed for impairment on a group basis are treated as a recovery of cost. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain would be recognized for the excess.

Impairment

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties assessed at the field level annually. For purposes of assessing its proved oil and natural gas properties for potential impairment, the Company reviews the expected undiscounted future cash flows for its total proved reserves on a held and used basis which is largely dependent on future capital and operating plans. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to the field is less than the carrying value of the field. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value.

The Company calculates the estimated fair values using a discounted future cash flow model. Management’s assumptions associated with the calculation of undiscounted future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, and (v) estimated reserves. A discount is applied to the undiscounted cash flows in order to estimate fair value.

The Company also reviews its unproved properties annually for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s geologists’ evaluation of the property, and the remaining months in the lease term for the property.

No impairment was recognized on proved or unproved oil and natural gas properties for the period from February 2, 2021 to December 31, 2021 and for the period from January 1, 2021 to February 1, 2021. For the year ended December 31, 2020, the Company recognized an impairment charge of $3.0 billion related to proved oil and natural gas properties and $221.0 million related to unproved oil and natural gas properties.

Other Property and Equipment

Other property and equipment primarily consist of field offices, furniture and fixtures, automobiles, office equipment, and building improvements, which are recognized at cost, however, were fair valued upon emergence through fresh-start accounting. Acquisitions, renewals and betterments are capitalized, while expenditures for repairs and maintenance are expensed as incurred. Net gains or losses on other property and equipment disposed of are included in net loss on sale of other property and equipment in the period in which the transaction occurs. The Company realized a net loss on sale of other property and equipment of $0.2 million for the period from February 2, 2021 to December 31, 2021.

Depreciation, Depletion, and Amortization (DD&A)

Capitalized acquisition costs of proved properties are depleted using the unit-of-production method based on total proved reserves. Drilling and completion and retirement costs are depreciated using the unit-of-production method based on estimated proved developed reserves. Costs of significant non-producing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed and proved developed reserves are established or, if unsuccessful, impairment is determined. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the related assets, which range from 2 to 20 years for predecessor period and 5 to 10 years for successor period, depending on asset class.

Debt Issuance Costs

Costs incurred in connection with debt, issued by us and our consolidated subsidiaries, are amortized as interest expense over the scheduled maturity period under the effective interest method. Debt issuance costs related to the predecessor debt were written off to reorganization items, net in 2020. All the debt issuance costs related to the BPR Revolving Credit Facility were expensed as incurred in the predecessor period from January 1, 2021 to February 1, 2021.

Derivatives

The Company utilizes financial instruments to manage risks related to changes in commodity prices. As of December 31, 2021, the Company utilized financial instruments, such as oil swaps to reduce the volatility of oil prices, and natural gas swaps to reduce the volatility of natural gas prices on a portion of the Company’s future expected oil and gas production.

The Company has not designated any derivative instruments as a hedge for accounting purposes. The Company records all derivative instruments on the consolidated balance sheets at estimated fair value. Realized gains and losses on the settlement of commodity derivative instruments and changes in unrealized gains and losses are reported separately in the consolidated statements of operations. If the Company terminates a derivative instrument prior to maturity, any cash paid or received upon settlement is recognized immediately and reported separately in the consolidated statements of operations. Unrealized gains are included in current and long-term commodity derivative assets and unrealized losses are included in current and long-term commodity derivative liabilities on the consolidated balance sheets.

In connection with the Chapter 11 proceedings, we were required to unwind all of our predecessor commodity derivative contracts prior to the Petition Date and had no open commodity derivative positions as of December 31, 2020. During the successor period we entered new commodity derivatives. See Note 8 Derivatives.

Asset Retirement Obligations

An asset retirement obligation (“ARO”) represents the future dismantlement and abandonment costs of tangible assets, such as platforms, wells, service assets, pipelines, and other facilities. The Company records an ARO and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the estimated fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis.

Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement.

Noncontrolling Interest

Noncontrolling interest represents third-party ownership in the net assets of the Predecessor’s consolidated subsidiary, SPR Finance, in the form of warrants, classified as permanent equity in the consolidated balance sheets because the warrants were indexed to SPR Finance’s own equity and met all conditions for equity classification. All the shares of noncontrolling interest were cancelled as a result of the bankruptcy. Upon emergence from bankruptcy, Bighorn does not have any noncontrolling interest. See Note 11 Equity for further details.

Unit Based Compensation

The Predecessor’s unit based compensation awards include incentive units, management warrants, management units and phantom units. Our unit based compensation cost is measured based on the fair value of the award on the grant date and re-measured each reporting period until the service conditions and, as applicable market conditions are met. Compensation expense is recognized over the requisite service period, net of estimated forfeitures, and included in general and administrative expenses in the consolidated statements of operations. See Note 12 Unit Based Compensation.

Income Taxes

The Predecessor is a multi-member limited liability company, as such was treated as a partnership for federal income tax purposes. As a partnership, each partner is separately taxed on their share of our taxable income. Accordingly, no federal tax provision has been recorded for the partnership. The Predecessor also holds an interest in three subsidiary C-Corporations. One of these corporations, SPRH Finance Corporation ("SPRH Finance Corp"), owns a minor interest in our subsidiary, SPR Finance. As such, these corporations are subject to federal income tax, however; these corporations have no material effect on the Predecessor's determination of income tax expense, or income taxes payable.

Our operations are located in Texas and are subject to entity-level tax, the Texas margin tax, at a statutory rate of up to 0.75% of income. The Predecessor filed a combined Texas franchise report with certain affiliates. The Predecessor did not enter into a tax sharing agreement with its affiliates. The estimated annual effective rate and related income tax obligations of the Predecessor were calculated using the separate return allocation method. Under this method, income tax is calculated as if the Predecessor filed a separate return. We recognize deferred tax liabilities and assets for expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statements and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that some portion or all of the related tax benefits will not be realized.

We have also established a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Furthermore, we recognize potential penalties and interest related to unrecognized tax benefits as a component of income tax expense. We had no uncertain tax positions as of December 31, 2021 or December 31, 2020.

The Successor is treated as a partnership for federal income tax purposes with each member separately taxed on its respective share of the Successor’s income (loss). The Successor is similarly treated as a partnership for state income tax purposes. The accompanying consolidated financial statements contain state taxes, including the Texas Margin Tax, that are imposed upon the Successor directly, and which is subject to ASC 740, Income Taxes. The Successor recorded $1.3 million to income tax expense for the period from February 2, 2021 to December 31, 2021.

Warrant Liabilities

The Company evaluates all our financial instruments, including issued unit purchase warrants, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) 480 “Distinguishing Liabilities from Equity” (“ASC 480”) and FASB ASC Topic 815, “Derivatives and Hedging” (“ASC 815”). The classification of financial instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.

The Company issued 1.1 million warrants (“Warrants”) on the Effective Date, with three-year expiration, for the purchase of up to 1.1 million units at an exercise price of $31.50 per unit in connection with its emergence from Chapter 11 bankruptcy. In accordance with the guidance in FASB ASC Subtopic 815-40, “Derivatives and Hedging- Contracts in Entity’s Own Equity” (“ASC 815-40”), the Company concluded that a provision in the warrant agreement related to certain related-party fee payments related to indexation of the equity-linked financial instrument precludes the warrants from being accounted for as components of equity. As the Warrants do not meet the definition of a derivative as contemplated in ASC 815-40 related to the absence of a net settlement provision, the Warrants were recorded as liabilities on the consolidated balance sheets and measured at fair value upon issuance on the Effective Date in accordance with FASB ASC Topic 820, “Fair Value Measurement” using a Black-Scholes option-pricing model and the Warrants are subsequently remeasured at fair value at each reporting period with

changes in the Warrant liabilities recorded in the consolidated statements of operations. Warrant liabilities are classified as long-term liabilities as their liquidation is not reasonably expected to require the use of current assets or require the creation of current liabilities.

These warrant liabilities did not exist as of December 31, 2020. As part of the initiation of bankruptcy proceedings, the Predecessor incentive-based warrants were cancelled. See Note 12 Unit Based Compensation for more details.

Defined Contribution Plan

In May 2016, the Predecessor established a defined contribution plan covering eligible employees. The Company provided matching contributions equal to 100% of the first 10% of an employee’s pay, as defined in the plan agreement ("eligible pay"), up to the maximum allowed by regulations promulgated by the Internal Revenue Service and make a qualified non-elective contribution for eligible employees of 3% of employee's eligible pay as of December 31 of each year. Employee salary deferrals and the qualified nonelective contributions are immediately vested. Our matching contributions vest over four years at 25% per year. For the period January 1, 2021 to February 2021 and for the year ended December 31, 2020 the Company made cash contributions of $0.3 million and $4.4 million, respectively. Upon emergence from bankruptcy the defined contribution plan was ceased. Bighorn does not have any such plan for the period February 2, 2021 to December 31, 2021.

Commitments and Contingencies

The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. There are no loss contingencies which require recognition or disclosure in the consolidated financial statements.

Concentration of Risk

All of our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties to our derivative transactions typically have an “investment grade” credit rating. We monitor on an ongoing basis the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. We enter into derivative contracts with multiple counterparties to minimize our exposure to an individual counterparty.

We do not require collateral or other security from counterparties to support derivative instruments. We have master

netting agreements with all of our derivative counterparties, which allow us to net our derivative assets and liabilities

with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative

transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.

Leases

The Company accounts for leases in accordance with ASC Topic 840, Leases. The Company’s leases are accounted for as operating leases. The Company records its lease expense during the lease term on a straight-line basis over the term of the lease.

Note 2 – Recent Accounting Guidance

Recent Accounting Pronouncements, Adopted

In August 2018, the FASB issued an update which modifies the disclosure requirements on fair value measurements in Topic 820. The ASU 2018-13 is effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. The Company adopted the update effective January 1, 2020 and the impact was not material to the consolidated financial statements.

In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting."

This ASU expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees and largely aligns the accounting for share-based payment awards issued to employees and to nonemployees. We adopted this standard in the fourth quarter of 2020. The adoption of this standard had no impact on our consolidated financial statements.

In March 2020, the FASB issued ASU 2020-03, “Codification Improvements to Financial Instruments”, which improves and clarifies various financial instruments topics. ASU 2020-03 includes seven different issues, including the treatment of revolving debt arrangements, that describe the areas of improvement and the related amendments to U.S. GAAP that are intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. The guidance was adopted on February 2, 2021 and did not have a material impact on the consolidated financial statements.

Recent Accounting Pronouncements, Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842), and subsequently issued other amendments to the initial guidance (collectively, “ASC 842”). ASC 842 amends various aspects of existing guidance for leases. The new guidance requires an entity to recognize assets and liabilities arising from a lease for both financing and operating leases, along with additional qualitative and quantitative disclosures. The main difference between previous U.S. GAAP and the new standard is the recognition of lease assets and lease liabilities by lessees on the balance sheets for those leases classified as operating leases under previous U.S. GAAP. The new standard will also require new disclosures, including qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements. The new guidance is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company is currently evaluating the impact of adopting the new guidance on the financial statements.

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments” (Topic 326), and subsequently issued other amendments to the initial guidance (collectively, “ASC 326”). ASC 326 represents a significant change in the Accounting for Credit Losses. The ASU introduced a new accounting model, the Current Expected Credit Losses model (CECL), which required earlier recognition of credit losses and additional disclosures related to credit risk. The CECL model utilizes a lifetime expected credit loss measurement objective for the recognition of credit losses for loans and other receivables at the time the financial asset is originated or acquired. The expected credit losses are adjusted each period for changes in expected lifetime credit losses. This model replaced the multiple existing impairment models in prior U.S. GAAP, which generally required that a loss be incurred before it is recognized. The standard applies to financial assets arising from revenue transactions such as contract assets and accounts receivables. The new guidance is effective for fiscal years beginning after December 15, 2022, with early adoption permitted. The Company is currently evaluating the impact of adopting the new guidance on the financial statements.

Note 3 – Chapter 11 Emergence

On the Effective Date, and pursuant to the terms of the Plan, the Predecessor:

Contributed certain assets and liabilities (the “Purchased Assets”) of SPR to Sable Land Company in exchange of $11.0 million of cash which was used to settle the general unsecured claims.

Cancelled all existing equity interests of SPR that were outstanding immediately prior to the Effective Date.

Cancelled the reserve-based credit facility (the “RBL Credit Facility”). The holders of the RBL Credit Facility received their pro rata share of (i) a new $315.0 million senior secured reserve-based credit facility (the “BPR Revolving Credit Facility”) and (ii) the new common equity interests (the “New Common Equity).

Transferred 10,000,000 shares of the New Common Equity to the holders of RBL Credit Facility claims.

Cancelled the 7.125% senior unsecured notes due 2020, the 7.375% senior unsecured notes due 2021, and the 12.000% senior secured notes due 2024 (together, the “Prepetition Notes”). The holders of the Prepetition Notes received their pro rata share of the Warrants.

Transferred approximately 1,111,111 of the three-year new Warrants to the holders of Prepetition Notes claims with a strike price of $31.50 and valued under the Black-Scholes pricing model.

Rolled over the DIP Facility. The holders of the DIP Facility received their pro rata shares of the BPR Revolving Credit Facility.

Distributed cash to the holders of secured mineral lien claims in the amount of $13.6 million.

Continued to pay the holders of administrative claims and other priority claims in the ordinary course of business.

Entered into a new registration rights agreement with certain parties who received New Common Equity under the Plan.

Sources of Cash for Plan Distribution. All cash payments made by the Company under the Plan on the Effective Date were funded from cash on hand (inclusive of proceeds from DIP financing), and proceeds from the BPR Revolving Credit Facility.

Liabilities subject to compromise. Prepetition unsecured and under-secured obligations that may be impacted by the Chapter 11 Cases were reported as “Liabilities subject to compromise” on the consolidated balance sheets. Accounting Standards Codification 852, Reorganizations, (“ASC 852”) requires prepetition liabilities that are subject to compromise to be reported at the expected amount of allowed claims. Thus, the Company has considered the chapter 11 motions approved by the Bankruptcy Court with respect to the amount and classification of its prepetition liabilities. The Company evaluated and adjusted the amount and classification through the Effective Date. See Note 4 Fresh Start Accounting for further details on the settlement of LSTC in accordance with the Plan.

Reorganization items, net. In accordance with ASC 852 any income, expenses, gains, and losses that are realized or incurred as of or subsequent to the Petition Date and before the Effective Date that are a direct result of the Chapter 11 Cases are recorded under “Reorganization items, net.”

The following table summarizes the components of reorganization items included in our consolidated statements of operations for the period January 1, 2021 through February 1, 2021 and the year ended December 31, 2020:


(in thousands)	Period from January 1 through February 1, 2021	Year ended December 31, 2020
Professional and legal fees (1)	$ 18,972	$ 43,399
Net gain on settlement of liabilities subject to compromise	(602,657)	─
Fresh start valuation adjustments	(120,813)	─
Other	751	─
Write-off of deferred financing costs	─	44,007
Write-off of debt discount	─	90,902
Reorganization items, net	$ (703,747)	$ 178,308

(1) Payments of $31.5 million and $30.8 million related to professional fees have been presented as cash outflows from operating activities in our consolidated statements of cash flows for the period from January 1 to February 1, 2021 and for the year ended December 31, 2020, respectively.

Note 4 – Fresh Start Accounting

Upon the Company’s emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company’s assets immediately prior to the date of confirmation was less than the total of the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as “Successor” or “Successor Company.” However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor Companies lack comparability, as required in ASC Topic 205, “Presentation of Financial Statements” (“ASC 205”). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor Companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company’s total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after the reorganization.

Reorganization Value

Reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s members’ capital and long-term debt, net of cash. In support of the Plan, the enterprise value was estimated through a credit bid process with a deadline of September 25, 2020 (“Credit Bid Deadline”) and approved by the bankruptcy court to be $500.0 million. This valuation analysis was prepared using reserve information, development schedules, acreage maps, other financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and risk weighted discounted cash flow analysis.

The Company utilized the court approved enterprise value of $500.0 million in allocating the reorganization value to the assets and liabilities at the Effective Date. From the Credit Bid Deadline through the Effective Date, the price of oil and gas increased, which increased the valuation of the Company’s oil and natural gas properties. This resulted in a bargain purchase gain of $282.8 million on the Effective Date. The Company recorded the bargain purchase gain as a component of members’ capital. Under fresh start accounting, the Company allocated the reorganization value (the fair value of the Successor’s total assets) to our individual assets based on their estimated fair values in conformity with ASC Topic 805, Business Combinations and ASC Topic 820, Fair Value Measurement.

The following reconciles the enterprise value to the fair value of members’ capital as of the Effective Date:


(in thousands)			As of February 1, 2021
Enterprise value			$ 500,000
Plus: Cash and cash equivalents			30,750
Plus: Bargain purchase gain			282,841
Less: Fair value of debt			(315,000)
Members’ capital			$ 498,591

The following represents the fair value of total assets as of the Effective Date:


(in thousands)			As of February 1, 2021
Enterprise value			$ 500,000
Plus: Cash and cash equivalents			30,750
Plus: Bargain purchase gain			282,841
Plus: Non-interest-bearing liabilities			96,896
Reorganization value of Successor assets			$ 910,487

Valuation Process

Under the application of fresh start accounting and with the assistance of valuation experts, we conducted an analysis of the Consolidated Balance Sheet to determine if any of the Company’s net assets would require a fair value adjustment as of the Effective Date. The results of our analysis indicated that our principal assets, which include oil and gas properties, ARO and warrants issued at emergence would require a fair value adjustment on the Effective Date. The rest of the Company’s net assets were determined to have carrying values that approximated fair value on the Effective Date. Further details regarding the valuation process are described further below.

Oil and Gas Properties

The Company’s principal assets are its oil and natural gas properties, which the Company account for under the successful efforts method of accounting as described in Note 1, Description of the Business and Summary of Significant Accounting Policies. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and estimated reserves quantities as of the Effective Date.

The Company principally used estimated future market prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to the oil and gas reserves, the future net revenues were discounted using the market-based weighted average cost of capital rate of 12% for proved developed producing wells, 15% for developed not

producing wells, and 25% for drilled but not yet completed wells determined appropriate at the time of the acquisition in comparison to similar market transactions.

The Company developed production models for all of our proved properties. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five-year forward prices for West Texas Intermediate oil, Henry Hub natural gas, other oil price indices, other natural gas price indices, and certain NGL component product price indices. These prices were adjusted for typical differentials realized by the Company for location and product quality adjustments. Gathering, transportation, processing and other post-production cost estimates were based on agreements in place at the Effective Date, based on FDL SMB’s experience in similar markets, or other market-based assumptions. Development and operating costs were based on historical cost trends, FDL SMB’s experience with similar oil and gas properties in similar markets, and other market-based assumptions.

Warrants

On the Effective Date, BPR issued Warrants to certain former noteholders as part of the settlement of their prepetition claims. The fair value of the warrants on the Effective Date was determined using an options pricing model while considering the contractual terms, including the exercise provisions. The key market data assumptions for the options pricing model are the estimated volatility and the risk-free rate. The volatility assumption was estimated using market data for similar upstream market participants with consideration for differences in size and leverage. The risk-free rate assumption was based on US Constant Maturity Treasury rates as of the Effective Date.

Asset Retirement obligations

ARO was fair valued by present valuing the estimated future cash outflow. The Company utilized current cost experiences and estimated well lives, obtained from the asset engineers, and adjusted for inflation to arrive at the estimated future cash flow. The future value was then discounted back to the present value using the Company’s specific credit-adjusted-risk-free interest rate, which was determined by the treasury risk free rate at the time using, 20-year 1.66%, adjusted by our interest rate of 4%, for a total of 5.66%.

Consolidated Balance Sheet at Emergence

The adjustments included in the following consolidated balance sheet as of February 1, 2021 reflect the consummation of the transactions contemplated by the Plan and carried out by the Company (“Reorganization Adjustments”) and the fair value adjustments as a result of the application of fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair value, and significant assumptions or inputs.


	As of February 1, 2021
(in thousands)	Predecessor Company		Reorganization Adjustments		Fresh Start Adjustments		Successor Company
Assets
Current assets
Cash and cash equivalents		$ 82,822	$ (52,072)	(a)	$ ─		$ 30,750
Accounts receivable – oil, natural gas and NGLs		23,922	4,938	(b)	─		28,860
Accounts receivable – oil, natural gas and NGLs – related party		4,938	(4,938)	(c)	─		─
Accounts receivable – joint interest and other, net		1,259	(1,132)	(d)	─		127
Accounts receivable – other		13,343	─		771	(p)	14,114
Restricted cash		162	(162)	(e)	─		─
Other current assets		8,224	(243)	(f)	(2,750)	(q)	5,231
Total current assets		134,670	(53,609)		(1,979)		79,082
Long-term assets
Oil and natural gas properties, successful efforts method		2,197,263	─		(1,369,469)		827,794
Less: accumulated depreciation and depletion		(1,505,745)	─		1,505,745		─
Oil and natural gas properties, net		691,518	─		136,276	(r)	827,794
Other property and equipment, net		8,430	─		(4,819)	(s)	3,611
Other assets		7,465	─		(7,465)	(t)	─
Total assets		$ 842,083	$ (53,609)		$ 122,013		$ 910,487

Liabilities and members’ capital
Current liabilities
Debtor-in-possession financing		$ 113,100	$ (113,110)	(g)	$ ─		$ ─
Accounts payable and accrued interest		30,700	(4,583)	(h)	─		26,117
Revenue payable		8,332	(8,332)	(i)	─		─
Acquired suspense		─	18,992	(j)	─		18,992
Total current liabilities		152,132	(107,023)		─		45,109
Long-term liabilities
Debt, net		─	315,000	(k)	─		315,000
Asset retirement obligations		24,936	─		1,200	(u)	26,136
Warrant liability		─	25,651	(l)	─		25,651
Total long-term liabilities		24,936	340,651		1,200		366,787
Liabilities subject to compromise		1,373,282	(1,373,282)	(m)	─		─
Predecessor members’ capital		(708,267)	587,454	(n)	120,813	(v)	─
Successor members’ capital		─	498,591	(o)	─		498,591
Total liabilities and members’ capital		$ 842,083	$ (53,609)		$ 122,013		$ 910,487

Reorganization Adjustments

(a) Reflects the net cash payments that occurred on the Effective Date as follows:


(in thousands)			As of February 1, 2021
Payment of the Purchased Asset cash for unsecured claims			$ (11,000)
Payment of the secured mineral lien claims			(13,577)
Payment of the professional fees for the carve out reserve			(9,485)
Payment of the success fees for the carve out reserve			(10,812)
Payment of the financing advisor fees			(5,284)
Payment of the plan administration cash			(506)
Payment of the accrued interest			(983)
Payment of the contract cure costs			(1,719)
Collection of joint interest receivables on the Effective Date			1,132
Return of the utility deposit on the Effective Date			162
Change in cash and cash equivalents			$ (52,072)

(b) Reflects the change in accounts receivable – oil, natural gas, and NGLs for the reclassification from related party receivables.

(c) Post emergence, this receivable is no longer related party and hence classified as Accounts receivable – oil, natural gas, and NGLs.

(d) Reflects the change in accounts receivable – joint interest and other, net for the collection of joint interest receivables.

(e) Utility deposit returned and reclassed to cash and cash equivalents on the Effective Date.

(f) Reflects the change in other current assets for the prepaid rent associated with the cancellation of the office lease.

(g) Reflects the change in current maturities of long-term debt for the rollover of the DIP Facility to the BPR Revolving Credit Facility.

(h) Reflects the change in accounts payable and accrued interest payable for the following activities:


(in thousands)			As of February 1, 2021
Payment of professional fees on the Effective Date			$ (11,141)
Payment of post petition contract cure costs			(1,399)
Reinstatement of LSTC			3,165
Payment of accrued interest related to the debtor-in-possession financing			(339)
Reclass to accounts payable from revenue payable			5,117
Other accruals paid			14
Change in accounts payable and accrued interest payable			$ (4,583)

(i) Reflects the change in revenue payable for the following activities:


(in thousands)			As of February 1, 2021
Reclass of Predecessor revenue payable to the Successor accounts payable			$ (5,117)
Reclass of Predecessor revenue payable to the Successor acquired suspense			(3,215)
Change in revenue payable			$ (8,332)

(j) Reflects the change in acquired suspense for the following activities:


(in thousands)			As of February 1, 2021
Reinstatement of revenue payable from LSTC			$ 15,777
Reclass to Successor acquired suspense from Predecessor revenue payable			3,215
Change in acquired suspense			$ 18,992

(k) Reflects the $315 million of outstanding borrowings under the BPR Revolving Credit Facility.

(l) Reflects the issuance of the New Warrants to holders of Prepetition Notes claims.

(m) Liabilities subject to compromise were settled or reinstated as follows in accordance with the Plan:


(in thousands)			As of February 1, 2021
Settled liabilities subject to compromise
RBL Credit Facility claims			$ (500,554)
Prepetition Notes claims			(804,447)
Accounts payable and liabilities			(46,082)
Revenue payable			(747)
Other long-term liabilities			(2,510)
Total settled liabilities subject to compromise			(1,354,340)
Reinstated liabilities subject to compromise
Accounts payable and liabilities			(3,165)
Revenue payable			(15,777)
Total reinstated liabilities subject to compromise			(18,942)
Total liabilities subject to compromise			(1,373,282)
Payment of the Purchased Asset cash to holders of general unsecured claims			11,000
Payment of the secured mineral liens to holders of other secured claims			13,577
Payment of the prepetition contract cure costs to holders of other unsecured claims			320
Payment of the prepetition RBL accrued interest			644
Issuance of the BPR Revolving Credit Facility to holders of RBL Credit Facility claims			201,900
Issuance of New Common Equity to holders of RBL Credit Facility claims			498,591
Issuance of New Warrants to holders of Prepetition Notes claims			25,651
Reinstatement of liabilities subject to compromise			18,942
Pre-tax gain on settlement of liabilities subject to compromise			$ (602,657)

(n) The following reconciles reorganization adjustments made to the Predecessor’s members’ capital:


(in thousands)			As of February 1, 2021
Pre-tax gain on settlement of liabilities subject to compromise			$ 602,657
Payment for plan administration on the Effective Date			(506)
Payment of professional and advisor fees recognized on the Effective Date			(14,440)
Cancellation of the office lease			(243)
Additional accrual for professional fee			(14)
Cancellation of Predecessor members’ capital			$ 587,454

(o) Reflects the reorganization adjustments made to the Successor’s members’ capital:


(in thousands)			As of February 1, 2021
Fair value of New Common Equity issued to holders of the RBL Credit Facility claims – majority lender			$ 334,769
Fair value of New Common Equity issued to holders of the RBL Credit Facility claims – other lenders			163,822
Change in Successor members’ capital			$ 498,591

Fresh Start Adjustments

(p) Reflects the fair value adjustment to accounts receivable – other of $0.8 million for the refund of prepaid general liability insurance.

(q) Reflects the fair value adjustment to other current assets of $0.2 million for inventory and $(2.9) million to write-off the current portion of prepaid insurance as there is no future benefit to be recognized by the Company.

(r) Reflects the fair value adjustment to oil and natural gas properties and the elimination of accumulated depreciation, depletion, and amortization.

(s) Reflects the fair value adjustment to other property and equipment, net and the elimination of accumulated depreciation.

(t) Reflects the adjustment to write-off the non-current portion of prepaid insurance as there is no future benefit to be recognized by the Company.

(u) Reflects the fair value adjustment to asset retirement obligations.

Note 5 – Property and Equipment

The Company reviews proved oil and natural gas properties for impairment on an annual basis. During the year ended December 31, 2020, primarily because of the decline in crude oil and natural gas future prices which resulted in reserves reductions, the Company recorded a non-cash impairment charge of $3.2 billion, of which $3.0 billion was related to proved oil and gas properties and $221.0 million was related to unproved properties that are no longer included in the Predecessor’s development plans. There was no impairment charge for the period from January 1, 2021 to February 1, 2021 and for the period from February 2, 2021 to December 31, 2021.

The following table summarizes the Company’s property and equipment for the periods presented:


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Oil and natural gas properties, successful efforts method:
Proved properties	$ 864,612	$ 5,149,714
Accumulated impairment to proved properties	-	(2,954,792)
Proved properties, net of accumulated impairments	864,612	2,194,922
Unproved properties	-	220,996
Accumulated impairment to unproved properties	-	(220,996)
Unproved properties, net of accumulated impairments	-	-
Total oil and gas properties, net of accumulated impairments	864,612	2,194,922
Accumulated depreciation, depletion, and amortization	(52,950)	(1,496,832)
Oil and natural gas properties, net	$ 811,662	$ 698,090


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Other property and equipment	$ 820	$ 16,170
Less: accumulated depreciation	(44)	(7,567)
Other property and equipment, net	$ 776	$ 8,603

The depreciation, depletion, and amortization for the period from February 2, 2021 to December 31, 2021 , the period from January 1, 2021 to February 1, 2021 and the year ended December 31, 2020 was $53.0 million, $6.8 million and $482.4 million, respectively.

Note 6 – Asset Retirement Obligations

The Company recognizes its asset retirement obligations related to the plugging, abandonment and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The liability has been accreted to its present value as of December 31, 2021.

The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented:


	Successor	Predecessor
(in thousands)	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 1, 2021	Year ended December 31, 2020
Asset retirement obligations at beginning of period	$ 26,136	$ 24,774	$ 28,615
Wells plugged	(59)	─	(391)
Revisions of estimates of existing obligations(1)	─	─	(5,272)
Accretion	1,353	162	1,822
Asset retirement obligations at end of period	$ 27,430	$ 24,936	$ 24,774

(1) Revisions of estimates during the year ended December 31, 2020 primarily relate to a decrease in estimated plugging and abandonment costs and adjustments to well production life.

Note 7 – Debt

The following table summarizes the Company’s debt for the periods presented:


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Current portion of debt:
Debtor-in-possession financing	$ ─	$ 75,000
7.125% Senior Notes due 2020	─	27,075
7.375% Senior Notes due 2021	─	9,038
12.000% Senior Secured Notes due 2024	─	707,667
New Sable Land RBL	─	499,910
Current portion of long-term debt:	─	1,318,690
Less: debt issuance cost, net	─	─
Current portion of long-term debt, net	─	1,318,690
Long-term portion of debt:
BPR Credit Facility	150,802	─
Long-term debt, net	150,802	─
Total debt, net	$ 150,802	$ 1,318,690

All of the debt issuance costs related to BPR Revolving Credit Facility were expensed as incurred. There were no unamortized debt issue costs as of December 31, 2021. As of December 31, 2020, all unamortized debt issuance costs and discounts associated with Predecessor debt had been written off.

From the Petition Date through the Effective Date, the Predecessor company operated the business as “debtor-in-possession.” Accordingly, all of our long-term debt obligations were presented as liabilities subject to compromise on our consolidated balance sheets as of December 31, 2020.

Post-Emergence Indebtedness

BPR Revolving Credit Facility

The Successor Company’s subsidiary, Bighorn Asset Company, LLC (“Borrower”) entered into a Senior Secured Reserve-Based Credit Facility Agreement (the “BPR Revolving Credit Facility”) with an initial borrowing base of $315.0 million and maturity date of February 1, 2025. The BPR Revolving Credit Facility contains a mandatory prepayment feature whereby if the Company’s consolidated cash balance exceeds $15.0 million as of the first business day of each month, the amount in excess of $15.0 million shall be used to pay down the outstanding principal on the BPR Revolving Credit Facility. The BPR Revolving Credit Facility also has a feature such that, to the extent any paydown by the Borrower reduces the Aggregate Credit Exposure (as defined in the BPR Revolving Credit Facility) to below the Aggregate Maximum Credit Amount (as defined in the BPR Revolving Credit Facility) by more than $15.0 million, the Aggregate Maximum Credit Amount is permanently reduced by the lesser of (i) 50% of the excess between the Aggregate Maximum Credit Amount and the Aggregate Credit Exposure and (ii) 50% of the paydown amount. The BPR Revolving Credit Facility is secured by a first priority lien on substantially all of the Company’s assets. The administrative agent also has a perfected security interest in the issued and outstanding equity interests owned by the Parent of the Borrower. The BPR Revolving Credit Facility is secured on a pari passu basis with the International Swap Dealers Association Master Agreements (“ISDAs”) entered into separately with two counterparties, See Note 8 Derivatives. The borrowing base was subject to redeterminations on October 1, 2021, and semi-annually thereafter based on the oil and natural gas properties including the status of required title information, reserves, other indebtedness, the financial condition of the credit party, swap agreements then in effect and other relevant factors. Additionally, the borrowing base could be adjusted for certain asset dispositions, termination of swap agreements or issuance of certain additional debt. In October 2021 the borrowing base was redetermined to be $267.5 million.

Amounts borrowed under the BPR Revolving Credit Facility carried an interest rate, equal to either: (i) LIBOR plus 3%; or (ii) the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the greater of (a) the federal funds effective rate and (b) the overnight bank funding rate, plus ½ of 1%, and (3) the adjusted LIBOR rate for a one month interest period plus 1%, plus an additional variable amount of 2%. There was no variable amount of interest

payable on outstanding borrowings, letter of credit fees, nor commitment fees associated with the BPR Revolving Credit Facility.

The BPR Revolving Credit Facility contains negative covenants, including, but not limited to covenants that limited the Company’s ability, as well as the ability of any future restricted subsidiaries to, among other things, incur additional debt, pay dividends on stock, make distributions of cash or property (except for tax distributions), change the nature of the business or operations, redeem stock or redeem or amend specified additional debt, make investments, loans, advances and acquisitions, create liens, enter into leases, sell assets, sell capital stock of subsidiaries, guarantee other indebtedness, enter into agreements that restrict dividends from subsidiaries, engage in any swap modification, enter into certain types of swap agreements, enter into take-or-pay or other prepayment arrangements, merge or consolidate and enter into transactions with affiliates. The BPR Revolving Credit Facility also contains certain affirmative covenants which, among other things, required periodic financial, operational, and reserve reporting. In addition, the BPR Revolving Credit Facility contains financial ratio requirements that requires us to maintain a Consolidated Current Ratio (as defined in the BPR Revolving Credit Facility) as of the end of each fiscal quarter of no less than 1.0 to 1.0 and a Funded Net Debt Leverage Ratio (as defined in the BPR Revolving Credit Facility) of no more than 3.5 to 1.0, with cash netting not to exceed $15.0 million (with such calculation to be subject to a customary annualization mechanic for the first three fiscal quarters post-closing). As of December 31, 2021, the Company was in compliance with all covenants associated with the BPR Revolving Credit Facility.

As of December 31, 2021, the Company had $150.8 million of total outstanding long-term debt related to the BPR Revolving Credit Facility. For the period from February 2, 2021 to December 31, 2021, the Company incurred $9.3 million of interest expense on the revolving credit facility. Since the debt was recorded at fair value on February 2, 2021, there is no unamortized debt issue costs recorded for the BPR Revolving Credit Facility.

Pre-Emergence Indebtedness

Debtor-In-Possession Financing

In connection with the Chapter 11 Cases, on June 25, 2020, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing. The Bankruptcy Court approved the DIP Motion on an interim basis on June 26, 2020 and on a final basis on August 4, 2020.

Following the Bankruptcy Court’s interim approval of the DIP Motion, the Debtors entered into that certain Debtor-in-Possession Credit Agreement, dated as of June 29, 2020 (the “DIP Credit Agreement”), among the Debtors, the financial institutions, or other entities from time-to-time party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent. The initial lenders under the DIP Credit Agreement included lenders under the New Sable Land RBL or the affiliates of such lenders.

The DIP Credit Agreement contained a $150.0 million facility (the "DIP Facility") with a maturity date of the Effective Date, of which $75.0 million of new money comprised a revolving facility (the "New Money Facility") and the other $75.0 million, upon entry of the final order on August 4, 2020, refinanced $75.0 million of the New Sable Land RBL. The proceeds of the DIP Facility were used, among other things: (i) to pay fees and expenses required under the DIP Credit Agreement or the DIP orders; (ii) to finance the working capital needs; and (iii) for general corporate purposes.

The interest rate was determined at SPR’s option, equal to either: (i) London Inter Bank Offering Rate (“LIBOR”) plus 5%, with a LIBOR floor of 1%; or (ii) an alternate base rate plus 4%, with a base rate floor of 2%.

The DIP Facility was subject to customary covenants, including: (i) compliance with an approved operating DIP budget, tested on a rolling four-week basis on disbursements excluding certain professional fees, royalty and working interest payments, capital expenditures, DIP Facility interest and fees, and adequate protection payments; (ii) permitted indebtedness, liens, investments, and swap agreements; and (iii) other provisions.

The New Money Facility had $75.0 million available upon the final order however only $38.1 million was drawn in January 2021. On the Effective Date, in accordance with the Plan, all outstanding obligations under the DIP Facility received their pro rata share of a new senior secured reserve-based credit facility.

12% Senior Secured Notes due 2024

In 2019, SPR Finance issued the 2024 Notes with an aggregate principal amount of $680.7 million at 89.25% of par, net of a $27.0 million purchase bonus issued with no associated proceeds received by SPR Finance, resulting in a $100.2 million original issuance discount (OID) and net proceeds of $607.5 million.

Prior to the filing of the Chapter 11 Cases, the 2024 Notes were due to mature on October 1, 2024 and carried interest at a fixed rate per annum, payable semi-annually in arrears on April 1 and October 1 of each year. The 2024 Notes were secured by a lien on 100% of the outstanding equity interest in Sable Land and SPR Finance Corporation. Additionally, the indenture for the 2024 Notes, listed Sable Land as a non-guarantor subsidiary and established that the lien on 100% of SPR Finance's outstanding equity interest in Sable Land was subject in priority to the lien on the Sable Land's assets under the New Sable Land RBL. Accordingly, Sable Land did not guarantee SPR Finance's debt under its indenture.

On the Effective Date, in accordance with the Plan, all outstanding obligations under our 2024 Senior Secured Notes were cancelled and the indentures governing such obligations were cancelled, except the limited extent expressly set forth in the Plan. See Note 3 Voluntary Reorganization under Chapter 11 for additional information.

New Sable Land RBL

On October 16, 2019, Sable Land entered into the New Sable Land RBL with JPMorgan Chase Bank, N.A., as administrative agent ("Administrative Agent"). The New Sable Land RBL had an initial borrowing base of $700.0 million and amended and restates the previous credit agreement dated August 15, 2018 (the "Old Sable Land RBL").

The filing of the Chapter 11 Cases constituted events of default that accelerated the Company’s obligations under the indentures governing our outstanding senior notes and under our New Sable Land RBL. In addition, the unpaid principal and interest due under our indentures and the New Sable Land RBL became immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement were subject to the applicable provisions of the Bankruptcy Code. See Note 3 Voluntary Reorganization under Chapter 11 for additional information.

Senior Notes

The 2020 Notes and the 2021 Notes bore interest at a fixed rate per annum, payable semi-annually in arrears on May 1 and November 1 of each year with the principal due upon maturity. Subject to certain exceptions, all obligations under the holdouts were fully and unconditionally guaranteed, on a joint and several basis, by our direct and indirect wholly owned material domestic subsidiaries. The 2020 Notes were due on November 1, 2020 and the 2021 Notes were due on November 1, 2021.

The 2020 and 2021 Senior Notes were cancelled and settled as per the Plan.

Interest Expense

For the period from February 2, 2021 to December 31, 2021, the period from January 1, 2021 to February 1, 2021, and year ended December 31, 2020 the interest expense on debt was $9.3 million, $1.8 million and $76.7 million, respectively. The Company discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date, except for the prepetition New Sable Land RBL Balance which per the DIP Credit Agreement, is required for paying post petition adequate protection. As a result, the Company did not record $ 7.1 million and $44.7 million of contractual interest expense related to the Senior Notes for the period January 1, 2021 to February 1, 2021 and for the year ended December 31, 2020, respectively.

Note 8 – Derivatives

The Company utilizes financial instruments to manage risks related to changes in commodity prices. In April 2020, we unwound our oil and natural gas derivative contracts with one counterparty for a $2.2 million net receipt to us. In June 2020, we unwound all of our remaining oil, natural gas and NGL derivative contracts for a $15.1 million net settlement due to us which was applied by the counterparty as a paydown on the New Sable Land RBL. In 2021, the BPR entered into new derivative instruments. As of December 31, 2021, the Company utilized financial instruments, particularly oil swaps, natural gas swaps, and NGL swaps, to reduce the volatility of oil prices on a portion of the Company’s future expected oil and gas production.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in mark-to-market valuation of these derivative contracts in net gain (loss) on commodity derivatives – unrealized on the statements of operations. Payments and receipts on settled derivative

contracts are recorded in net gain (loss) on derivative contracts – realized. All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivative and Hedging, and ASC 820, Fair Value Measurement, and included on the consolidated balance sheets as commodity derivatives within the current liabilities and long-term liabilities sections of the consolidated balance sheets.

Commodity derivative contracts are with counterparties of high credit quality and the credit ratings of counterparties are monitored on a continual basis. The Company believes the risk of significant nonperformance by any one counterparty is low.

The Company’s commodity derivative contracts outstanding as of December 31, 2021 are summarized below:


	Successor
Production Period	Notional Volumes	Wtd. Avg. Fixed Price
	December 31, 2021	December 31, 2021
Crude oil basis swaps (bbls):
2022	1,863,193	$ 49.84
2023	976,375	$ 48.97
2024	353,766	$ 51.59
Crude oil basis swaps (bbls):
2022	1,822,304	$ 0.57
2023	903,574	$ 0.50
2024	164,731	$ 0.40
Crude oil CMA roll (bbls):
2022	595,836	$ 0.39
Natural gas swaps (mmbtu):
2022	18,843,162	$ 2.72
2023	10,932,092	$ 2.59
2024	4,015,202	$ 2.61
Natural gas basis swaps (mmbtu):
2022	18,066,300	$ (0.23)
NGL swaps (bbls):
2022	477,563	$ 25.55

The fair values of the Company’s commodity and interest rate derivative contracts as of December 31, 2021 are as follows:


			Successor
			Commodity Derivatives
(in thousands)			December 31, 2021
Crude oil commodity contracts			$ (19,547)
Crude commodity contracts – related party			(43,959)
Natural gas commodity contracts			(11,140)
Natural gas commodity contracts – related party			(15,536)
NGL commodity contracts			(7,279)
NGL commodity contracts – related party			(507)
Recorded fair value			(97,968)
Balance Sheet Classification
Commodity derivatives – current			(13,471)
Commodity derivatives – current – related party			(52,008)
Commodity derivatives – long-term			(24,496)
Commodity derivatives – long-term – related party			(7,993)
Total			$ (97,968)

The Company presents the fair value of its derivative contracts at the gross amounts in the balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts as of December 31, 2021 in accordance with ASC 210-20:


			Successor
			Commodity Derivatives
(in thousands)			December 31, 2021
Gross amounts presented in the balance sheet			$ (97,968)
Amounts not offset in the balance sheet			─
Net amount			$ (97,968)

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to entering into a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

The following presents the impact of derivatives and their location within the consolidated statements of operations:


	Successor	Predecessor
(in thousands)	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 1, 2021	Year ended December 31, 2020
Net loss on commodity derivatives – realized
Crude oil commodity contracts	$ (36,038)	$ ─	$ 26,266
Natural gas commodity contracts	(17,365)	─	(6,640)
NGL commodity contracts	(22,267)	─	18,251
Total	$ (75,670)	$ ─	$ 37,877


			Successor
(in thousands)			For the period from February 2, 2021 to December 31, 2021
Net loss on commodity derivatives - unrealized
Crude oil commodity contracts			$ (63,506)
Natural gas commodity contracts			(26,676)
NGL commodity contracts			(7,786)
Total			$ (97,968)

There were no gains or losses on commodity derivatives for the periods from January 1, 2021 to February 1, 2021.

The following table presents the fair value of the commodity derivatives as of December 31, 2020 (Predecessor):


	Predecessor
	December 31, 2020
(in thousands)	Oil	Gas	NGL	Total
Beginning commodity derivative asset (liability), net	$ (7,669)	$ 4,580	$ 1,946	$ (1,143)
Intercompany netting	538	─	(538)	─
Settlement payments (receipts)	(19,161)	2,060	(19,658)	(36,759)
Total derivative gain (loss)	26,266	(6,640)	18,251	37,877
Deferred premium interest	26	─	─	26
Ending commodity derivative asset (liability), net	$ ─	$ ─	$ ─	$ ─

For the year ended December 31, 2020, cash received on settlement includes a $15.1 million net settlement from June 2020 which was not received in cash but rather applied by the counterparty as a paydown on the New Sable Land RBL.

Note 9 – Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following table represents the fair value hierarchy table for the Company’s net assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2021 (Successor) and December 31, 2020 (Predecessor):

Successor

December 31, 2021

(in thousands)

Quoted Prices in Active Markets for Identical Assets (Level 1)

Significant Other Observable Inputs (Level 2)

Significant Unobservable Inputs (Level 3)

Assets/Liabilities at Fair Value

Commodity derivatives – liabilities

$ ─

$ (97,968)

$ ─

$ (97,968)

Warrant liabilities

$ ─

$ (30,562)

There were no outstanding financial instruments measured at fair value on a recurring basis as of December 31, 2020.

The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair value determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on the Company’s own assumptions used to measure assets and liabilities at fair value.

The Company’s derivatives consist of over-the-counter (OTC) contracts which are not traded on a public exchange. These derivatives are indexed to active trading hubs for the underlying commodity and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted or validated through external sources, including third-party pricing services, brokers and market transactions, the Company has categorized these derivatives as Level 2. The Company values these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves. Estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision.

The fair value of the warrant liability is measured using the Company’s own assumptions and unobservable inputs. Therefore, the Company has categorized the warrant liability as Level 3. The warrant liability was initially measured at fair value on the Effective Date and subsequently marked to market each reporting period. The significant assumptions used in the Black-Scholes option-pricing model for valuing the warrant liability as of December 31, 2021 include (i) stock price of $49.9, (ii) strike price of $31.5, (iii) risk free interest rate of 0.7%, (iv) volatility of 75.0%, (v) annual dividend rate of $0.0, and (vi) expected term of 2.1 years.

There were no transfers of assets and liabilities measured at fair value into or out of Level 3 for the period from February 2, 2021 to December 31, 2021, the period from January 1, 2021 to February 1, 2021, and year ended December 31, 2020.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property

impairments, and the initial recognition of ARO, for which fair value is used.

The Company reviews oil and natural gas properties for impairment on an annual basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties include (i) oil and natural gas prices based on NYMEX futures price strips, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital

expenditures, (v) production volumes, (vi) estimated reserves, and (vii) estimated discount rate. See Note 5 Property and Equipment.

ARO estimates are derived from historical costs as well as our expectation of future cost environments. As there is

no corroborating market activity to support the assumptions used, we have designated these measurements as Level 3. A reconciliation of the beginning and ending balances of ARO is presented in Note 6 Asset Retirement Obligations.

Additionally, the SPR Phantom Units issued in 2020, as discussed in Note 12 Unit Based Compensation, were fair valued. The fair value was based on the price investors paid for common units of PRES New Equity, LLC as PRES New Equity, LLC common units and SPR common units were exchanged on a one for one basis.

Fair Value of Financial Instruments

The following table summarizes the net fair value and carrying value of our financial instruments:

Successor

Predecessor

December 31, 2021

December 31, 2020

(in thousands)

Fair Value

Carrying Value

Fair Value

Carrying Value

Liabilities

7.125% Senior Notes due 2020

$ ─

$ 366

$ 27,075

7.375% Senior Notes due 2021

─

158

9,038

12.000% Senior Secured Notes due 2024

─

35,383

707,667

New Sable Land RBL

─

499,910

DIP Facility

─

75,000

BPR Revolving Credit Facility

$ 150,802

$ ─

BPR Revolving Credit Facility – The carrying value of the BPR Revolving Credit Facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to the Company.

Senior Notes and Senior Secured Notes - The fair value is the estimated amount a market participant would pay to assume the debt, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date, measured using prices available from a pricing service that is corroborated by market data. Therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

Debtor-in-possession Financing - The carrying value of the Debtor-in-possession Financing approximate fair value because our current borrowing rate does not materially differ from market rates for similar bank borrowings.

New Sable Land RBL - The carrying value of the New Sable Land RBL approximates fair value because our current borrowing rate does not materially differ from market rates for similar bank borrowings.

The carrying values of all classes of cash and cash equivalents, accounts receivable, and accounts payable are representative of their respective fair values due to the short-term maturities of those instruments.

Note 10 – Related Party Transactions

Successor – Management Fee

Pursuant to the MSA, and as discussed in Note 1, Description of the Business and Summary of Significant Accounting Policies, FDL SMB was engaged to manage the day-to-day operations of the business activities of the Company, including allocating to the Company and other interest holders the production and sale of oil, natural gas, and NGLs, collection and disbursement of revenues, and operating expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Cash amounts related to the various collections and disbursements on behalf of the Company are being

settled monthly between the Company and FDL SMB. As of December 31, 2021, the Company had a net related party receivable due from FDL SMB totaling $31.8 million.

Under the MSA, FDL SMB is compensated for the services it provides as follows; the Company will pay a quarterly fee to FDL SMB (the “Management Fee”), reimburse FDL SMB for all documented “out-of-pocket expenses” as defined in the MSA, and will also provide incentive-based compensation (the “Management Incentive Program”). FDL SMB earned management fees totaling $14.7 million for the period from February 2, 2021 to December 31, 2021, of which the Company accrued $1.2 million as of December 31, 2021.

The Management Incentive Program provides for compensation in the form of two fees; (i) an annual bonus fee opportunity, subject to performance targets set forth by the board, equal to 18% of the annual Management Fee and (ii) a success fee (the “Success Fee”) to be paid out in cash equal to 18% of any Equity Distribution (as defined in the MSA) or, upon a change in control event, a success fee to be paid out in cash when the change in control occurs.

Successor – Debt

During the period ended February 2, 2021 to December 31, 2021, the Company entered into the BPR Revolving Credit Facility and certain derivative arrangements with the majority capital holder of the Company to support the capital requirements and risk management activities of the Company. The debt and derivative arrangements were entered into in the ordinary course of the business and the terms and conditions of which are consistent to transactions with unaffiliated entities. Related party derivatives are separately presented in the consolidated balance sheets as on December 31, 2021.

Predecessor – Sales and Purchases

A member of the Board of Managers, SPR Finance’s Board of Managers and Sable Land’s Board of Managers was also, a member of the Board of Directors of PAA GP Holdings, LLC, which was the general partner of Plains GP Holdings, L.P., that owned a non-economic controlling general partner interest in Plains All American Pipeline, LP ("Plains"). In the normal course of business, we marketed a portion of the oil to Plains Marketing LP, a subsidiary of Plains. Sales of the oil to Plains Marketing LP totaled approximately $39.6 million during the year ended December 31, 2020, which was included in Oil, natural gas, and NGL sales – related party in the accompanying consolidated statements of operations. Accounts receivable due from Plains Marketing, LP totaled approximately $4.9 million as of December 31, 2020 and are reflected in Accounts receivable – oil, natural gas, and NGLs – related party on the accompanying consolidated balance sheets. This related party accounts receivable is reflected in Accounts receivable – other in the successor period.

A member of SPR’s Board of Managers, SPR Finance’s Board of Managers and Sable Land’s Board of Managers had an investment in W.D. Von Gonten Laboratories, LLC. SPR entered into an agreement with W.D. Von Gonten &Co. and W.D. Von Gonten Laboratories, LLC to obtain professional petroleum engineering and geological evaluation consulting services. Under the agreement with W.D. Von Gonten & Co. and W.D. Von Gonten Laboratories, LLC, SPR incurred $0.7 million for the year ended December 31, 2020.

A member of SPR’s Board of Managers, SPR Finance’s Board of Managers and Sable Land’s Board of Managers was also a member of the Board of Directors of Medallion Midstream, LLC (“Medallion”). Medallion’s subsidiary, MGP Marketing LLC, was a service provider, arranging for the trucking of crude oil from our leases to truck unloading stations on Medallion’s pipeline system. We incurred $0.4 million for the year ended December 31, 2020, to MGP Marketing LLC for trucking services.

An independent manager of SPR Finance's Board of Managers was also a director of Now, Inc., which operated a subsidiary DNOW L.P. We used DNOW L.P. for supplying equipment, products, parts and supplies, and incurred expenses of $0.03 million for the year ended December 31, 2020.

Predecessor – Debt

As of December 31, 2020, three of the predecessor Company’s equity sponsors held $35.4 million and one of the members to the predecessor Company’s Board of Managers held $8.7 million in principal value of the 2024 Notes reflected in Liabilities subject to compromise and Debt, net as of December 31, 2020, on the accompanying consolidated balance sheets.

Note 11 – Equity

Members’ Equity

On the effective Date of the emergence, all our Predecessor common stock, were cancelled pursuant to the Plan and New Common Equity was issued. See Note 3 Chapter 11 Emergence for further information.

For the period from February 2, 2021 to December 31, 2021 and for the period from January 1, 2021 to February 1, 2021, there were no other significant transactions in equity besides the net income of $84.8 million and $693.8 million, respectively.

In the year ended December 31, 2020, the Company issued 5.0 million in newly issued common units to PRES NE in exchange for $0.4 million in cash during January 2020. As of December 31, 2020, PRES NE and PRES ICA owned 81.06% of our 23.7 billion common units outstanding.

Noncontrolling interest represents third-party ownership in the net assets of our consolidated subsidiary, SPR Finance, in the form of common unit warrants, classified as permanent equity in our consolidated balance sheets. The warrants are indexed to SPR Finance's own equity and meet all of the conditions for equity classification. Each warrant, when exercised, will entitle the holder to purchase one SPR Finance common unit at an exercise price equal to $0.0001. The warrants are exercisable for a period of five years from the October 2019 issuance date. In April 2020, holders of 216,310 warrants exercised their right to purchase common units, resulting in the issuance of 352,152,680 common units of SPR Finance and $0.04 million of cash contributed to SPR Finance. The impact of the 2020 exercises is that as of December 31, 2020, 1.47% of SPR Finance equity is owned by third-parties who were issued SPR Finance common units. There was no noncontrolling interest as of December 31, 2021.

Note 12 – Unit Based Compensation

The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation, which requires companies to recognize in the statements of operations all share-based payments granted to employees based on their fair value.

Management Units

On May 1, 2017, PRES NE issued a total of 1,000 profits interests in the form of management units ("Management Units") to our four executives as provided for in their employment agreements. The Management Units vest ratably in quarterly increments over a three-year period in exchange for continuous service to us or upon the occurrence of certain events, including the completion of an initial public offering, termination by employer without cause or by holder for good reason or change of control. In the event of death or disability, the holder would receive the portion of Management Units otherwise scheduled to vest in the next six months. Fair value is determined on the grant date and re-measured at the end of each reporting period until the service conditions are met. A unit-based compensation credit of $0.04 million was recognized for the year ended December 31, 2020. As of December 31, 2020, the Management Units were fully vested.

Management Warrants

On May 1, 2017, PRES ICA issued warrants to purchase approximately 18.9 million common units (the "Management Warrants") to our four executives as provided for in their employment agreements. The Management Warrants vested ratably in quarterly increments over a three-year period in exchange for continuous service to us or upon the occurrence of certain events, including the completion of an initial public offering, termination by employer without cause or by holder for good reason or change of control. In the event of death or disability, the holder would have received the portion of Management Warrants otherwise scheduled to vest in the next six months. The Management Warrants were exercisable at prices ranging from $0.28350 to $0.49350 from May 1, 2017 to May 1, 2022 at the election of the holder, subject to the vesting schedule. No unit-based compensation expense was recognized for the year ended December 31, 2020, because the value per unit was zero. As of December 31, 2020, the Management Warrants were fully vested.

Phantom Units

In February 2020, we granted 276.8 million Phantom Units at an average fair value of $0.08 per unit to employees of the Company and affiliates. We recognize unit-based compensation expense for these units based on the fair value of the awards on the grant date and subsequently remeasured each reporting period until the service conditions were met. The 2020 units vested 25% each year for four years after issuance. The awards would settle and convert to

restricted stock only at the time of an initial public offering or to a cash payment if an initial public offering does not occur within five years of the initial grant date for the 2018 units and within three years for the 2019 units. For the year ended December 31, 2020, we recognized a credit of $5.5 million. These amounts are reflected in general and administrative expense in the accompanying consolidated statements of operations. Due to the Company's deficit balance in equity, liquidity issues and bankruptcy proceedings, the value of the Phantom Units was deemed zero, which resulted in the $5.5 million credit in 2020.

Note 13 – Supplemental Cash Flow Information

The following table summarizes cash payments for interest as well as non-cash activities:


	Successor	Predecessor
(in thousands)	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 1, 2021	Year ended December 31, 2020
Paid interest	$ 8,904	$ 5,219	$ 24,326
Accrued capital expenditures	$ 1,025	$ ─	$ (5,065)

Note 14 – Revenue from Contracts with Customers

The following table disaggregates revenue as reported in our statements of operations by significant product type:


	Successor	Predecessor
(in thousands)	For the period from February 2, 2021 to December 31, 2021	For the period from January 1, 2021 to February 1, 2021	Year ended December 31, 2020
Oil sales	$ 215,498	$ 14,043	$ 176,776
Natural gas sales	127,285	5,933	29,932
NGL sales	136,909	8,770	66,382
Total revenues	$ 479,692	$ 28,746	$ 273,090

Note 15 – Income Taxes

Our operations are located in Texas and are subject to entity-level tax, the Texas franchise tax, at a statutory rate of up to 0.75% of income. The Predecessor holds an interest in three subsidiary C-Corporations. One of these corporations, SPRH Finance Corporation ("SPRH Finance Corp"), owns a minor interest in our subsidiary, SPR Finance. As such, these corporations are subject to federal income tax, however; these corporations have no material effect on the Company's determination of income tax expense or income taxes payable. The Successor does not hold interests in any C-Corporations and is treated as a partnership for federal income tax purposes with each member separately taxed on its respective share of the Company’s income (loss). For the period from February 2, 2021 to December 31, 2021 and the year ended December 31, 2020, we recorded a $1.3 million income tax expense and a $12.0 million income tax benefit, respectively. There was no income tax expense for the period from January 1, 2021 to February 1, 2021.

We had no material deferred income taxes as of December 31, 2021 and 2020. Deferred income tax assets related to the Predecessor were fully reserved with a valuation allowance as of December 31, 2020 as it was more likely than not that the related tax benefits will not be realized.

As of December 31, 2021 and 2020, the income tax positions related to the Texas franchise tax were assessed and it was determined there were no uncertain tax positions. For the period from February 2, 2021 to December 31, 2021, the period from January 1, 2021 to February 1, 2021, and the year ended December 31, 2020, our effective tax rate was less than 1%.

Note 16 – Commitments and Contingencies

Operating Leases and Other Contractual Obligations

Our operating leases relate primarily to obligations associated with our leased truck fleet. Future non-cancellable commitments related to our operating leases as of December 31, 2021 are as follows:


(in thousands)			Operating Leases
2022			$ 612
2023			536
2024			350
2025			6
2026			─
Thereafter			─
Total			$ 1,504

For the period from February 2, 2021 to December 31, 2021, the period from January 1, 2021 to February 1, 2021, and year ended December 31, 2020 the lease expense was $1.3 million, $0.2 million, and $2.4 million, respectively.

Other Commitments

We are periodically subject to lawsuits, investigations, and disputes including, matters relating to commercial transactions, environmental, and health and safety matters. A liability is recognized for any contingency that is probable of occurrence and reasonably estimable. The likelihood of adverse judgments or outcomes in these matters is periodically assessed, as well as potential ranges of possible losses (taking into consideration any insurance recoveries), based on an analysis of each matter with the assistance of legal counsel and other experts, as considered appropriate. There are no loss contingencies which require recognition or disclosure in the consolidated financial statements.

Note 17 – Subsequent Events

The Company has evaluated subsequent events through May 27, 2022, the date of which these consolidated financial statements were available for issuance.

On January 30, 2022, the Company entered into an agreement with Earthstone Energy Holdings, LLC and Earthstone Energy, Inc. (collectively, “Earthstone”) to sell the Company’s assets for an aggregate purchase price of approximately $860 million, consisting of $770 million in cash and approximately 6.8 million shares of Earthstone’s Class A common stock valued at $90 million based on a closing share price of $13.25 on January 28, 2021, subject to customary closing adjustments. The effective date of the transaction is January 1, 2022.

Shortly after January 30, 2022 and the signing of the Earthstone sales agreement, the Company’s Board of Directors approved a series of derivative hedging transactions to offset the Company’s currently outstanding contracts and effectively cap the total risk management liabilities amounts due from April 2022 to September 2024 at $112.9 million. The contracts are scheduled to settle monthly in fixed amounts through September 2024.

On April 14, 2022, the transaction with Earthstone was consummated. The cash consideration of $770 million was reduced by approximately $131 million to $639 million. The equity consideration was also reduced from approximately 6.8 million shares of Earthstone’s Class A common stock by 1.2 million shares to 5.7 million shares, both based on customary, preliminary purchase price adjustments.

During the three months ended March 31, 2022, the Company (the “Seller”) received a deposit of $50.0 million, (the “Deposit”) from Earthstone, (the “Buyer”) for the assets sold as part of the transaction described above. When the closing of the transaction occurred on April 14, 2022, the deposit was applied toward the purchase price, but the deposit remained in escrow with the escrow agent (“Bank of America”) in accordance with the terms of the purchase sale agreement (“PSA”) with Earthstone. Six months following the closing date, the Seller is entitled to receive up to 50% of the deposit subject to reduction for claims made by the Buyer in good faith. Twelve months

following the closing date, the Seller is entitled to receive the remainder of the deposit subject to reduction for claims made by the Buyer in good faith. The Company recorded the deposit within other assets with a corresponding entry to other liabilities in the condensed consolidated balance sheets.

On April 14, 2022, Earthstone deposited 510,638 shares of Class A Common Stock (the “Stock Holdback”) and $7.75 million of cash (the “Cash Holdback”) (collectively the “Closing Step-Up Holdback”) into the escrow account. Six months following the closing date, the Seller is entitled to receive up to 50% of the Deposit and Closing Step-Up Holdback, collectively (the “Holdback”) subject to reduction for claims made by the Buyer in good faith. Twelve months following the closing date, the Seller is entitled to receive the remainder of the Holdback subject to reduction for claims made by the Buyer in good faith.

In April 2022, the Company voluntarily terminated all of its open derivative contracts which resulted in a net cash settlement of $109.7 million paid to counterparties, of which $68.7 million was to a related party.

During the three months ended March 31, 2022, the Company paid $88.0 million of principal on the RBL Credit Facility. On April 14, 2022, the Company paid down the remaining principal balance of $62.8 million on the RBL Credit Facility, plus $0.3 million of accrued interest, and terminated the RBL Credit Facility.

Note 18 – Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

Costs Incurred Related to Oil and Gas Activities

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

The Company’s oil and natural gas activities for the period from February 2, 2021 to December 31, 2021 (successor), for the period from January 1, 2021 to February 1, 2021 (predecessor), and for the year ended December 31, 2020 (predecessor) were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows:


	Successor	Predecessor
(in thousands)	For the period From February 2, 2021 to December 31, 2021	For the period From January 1, 2021 to February 1, 2021	Year Ended December 31, 2020
Acquisition cost:
Proved	$ ─	$ 2	$ ─
Unproved	─	─	─
Exploration and extension on well costs	─	29	17,974
Development costs	101,424	3	7,012
Total additions	$ 101,424	$ 34	$ 24,986

Capitalized Costs

Capitalized costs, depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the United States of America as of December 31, 2021 (successor) and December 31, 2020 (predecessor), are summarized below:


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Oil and natural gas properties, successful efforts method:
Proved properties	$ 864,612	$ 5,149,714
Accumulated impairment to proved properties	-	(2,954,792)
Proved properties, net of accumulated impairments	864,612	2,194,922
Unproved properties	-	220,996
Accumulated impairment to unproved properties	-	(220,996)
Unproved properties, net of accumulated impairments	-	-
Total oil and gas properties, net of accumulated impairments	864,612	2,194,922
Accumulated depreciation, depletion, and amortization	(52,950)	(1,496,832)
Oil and natural gas properties, net	$ 811,662	$ 698,090

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimate shown herein for the year ended December 31, 2021 (successor) have been prepared by Ryder Scott Company L.P., an independent petroleum consulting firm. The proved reserves estimate for the year ended December 31, 2020 (predecessor) were calculated by adding back production (rolled back) and adjusting for proved undeveloped reserves to estimate the reserve quantities, as this method was deemed to provide better estimates based on information currently available. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic conditions and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

The reserve information in these consolidated financial statements represent only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulates of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which there were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2021 and December 31, 2020 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $66.56 per barrel and $39.54 per barrel, respectively. The natural gas prices as of December 31, 2021 and December 31, 2020 are based

on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $3.60 per MMBtu and $1.99 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas, and natural gas liquids reserves as of December 31, 2021 being valued using prices of $65.80 per barrel, $3.11 per MMBtu and $30.60 per barrel, respectively. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States of America.

A summary of the Company’s changes in quantities of proved oil, natural gas, and NGL reserves for the years ended December 31, 2021 and December 31, 2020 are as follows:


(in thousands)	Oil (MBbl)	Natural Gas (MMcf)	Natural Gas Liquids (MBbl)	MBOE
Balance – January 1, 2020 (Predecessor)	61,717	549,864	68,288	221,649
Revisions to previous estimates	(16,331)	(100,302)	(11,924)	(44,972)
Production	(4,683)	(41,766)	(5,703)	(17,347)
Balance – December 31, 2020 (Predecessor)	40,703	407,796	50,661	159,330
Revisions to previous estimates	18,792	120,499	15,016	53,891
Production	(3,400)	(36,100)	(4,527)	(13,944)
Balance – December 31, 2021 (Successor)	56,096	492,195	61,150	199,277
Proved developed reserves:
January 1, 2020	33,521	432,855	53,751	159,414
December 31, 2020	25,765	344,687	42,821	126,034
December 31, 2021	29,176	373,519	46,406	137,835
Proved undeveloped reserves
January 1, 2020	28,196	117,009	14,537	62,235
December 31, 2020	14,938	63,109	7,840	33,296
December 31, 2021	26,919	118,676	14,744	61,442

Notable changes in reserves for the year ended December 31, 2021 included the following:

•Revision to previous estimates. In 2021, the upward revision of prior reserves of 53.9 MMBoe consisted of favorable adjustments to PUDs as a result of improved drilling plans and economic outlook coupled with changes in performance and other economic factors, including increases in SEC pricing.

Notable changes in reserves for the year ended December 31, 2020 included the following:

•Revision to previous estimates. In 2020, the downward revision of prior reserves of 45.0 MMBoe consisted of unfavorable adjustments to PUDs as a result of reduced drilling plans and economic outlook coupled with changes in performance and other economic factors, including decreases in SEC pricing.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. Proved undeveloped (“PUD”) locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data.

Changes in PUD reserves for the years ended December 31, 2021 (successor) and December 31, 2020 (predecessor) are as follows:


(in MBoe)
Proved undeveloped reserves at January 1, 2020 (Predecessor)			$ 62,235
Revision to previous estimates			(28,939)
Proved undeveloped reserves at December 31, 2020 (Predecessor)			33,296
Revision to previous estimates			28,146
Proved undeveloped reserves at December 31, 2021 (Successor)			$ 61,442

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing FASB ASC Topic 931, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve production volumes estimated by the Company’s third-party petroleum consulting firm. It can be used for some comparisons but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believe that the following factors should be considered when reviewing the following information:

•Future costs and commodity prices will probably differ from those required to be used in these calculations;

•Due to future market conditions and government regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

•A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•Future net revenues may be subject to different rates of income taxation.

On December 31, 2021 and December 31, 2020, as specified by the SEC, prices for oil and natural gas reserves used in this calculated were the unweighted 12-month average of the first day of the month prices. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount rate.

The Standardized Measure on December 31, 2021 (successor) and December 31, 2020 (predecessor) is as follows:


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Future cash inflows	$ 7,092,259	$ 3,109,156
Future production costs	(2,538,595)	(1,611,428)
Future development costs	(658,724)	(336,206)
Future income tax expense	(37,234)	(16,323)
Future net cash flows	3,857,706	1,145,199
10% annual discount for estimated timing of cash flows	(2,027,670)	(543,532)
Standardized measure of discounted future net cash flows	$ 1,830,036	$ 601,667

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following table is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the two-year period ended December 31, 2021 (successor) and December 31, 2020 (predecessor):


	Successor	Predecessor
(in thousands)	December 31, 2021	December 31, 2020
Beginning of the year	$ 601,667	$ 1,495,231
Net changes in prices and production costs	1,238,219	(650,188)
Net changes in future development costs	162	─
Sales of oil and gas produced net of production costs	(458,451)	(185,161)
Revisions of previously quantity estimates	425,126	(198,811)
Previously estimated development costs incurred during the period	33,619	─
Changes in taxes, net	(9,108)	7,133
Accretion of discount	61,012	151,082
Changes in timing of estimated cash flows and other	(62,210)	(17,619)
End of year	$ 1,830,036	$ 601,667