Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers of Independence Energy LLC

Opinion on the Financial Statements

We have audited the accompanying combined and consolidated balance sheets of Independence Energy LLC and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related combined and consolidated statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Houston, Texas

July 23, 2021

We have served as the Company’s auditor since 2021.

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INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

	December 31, 2020			December 31, 2019
ASSETS
Current assets:
Cash and cash equivalents	$	36,861		$	19,894
Accounts receivable, net		111,821			103,300
Derivative assets – current		30,926			31,469
Drilling advances		38,892			4,770
Prepaid and other current assets		1,948			6,392
Total current assets		220,448			165,825
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved		4,910,059			4,420,557
Unproved		288,459			326,331
Oil and natural gas properties at cost, successful efforts method		5,198,518			4,746,888
Field and other property and equipment, at cost		138,371			108,172
Total property, plant and equipment		5,336,889			4,855,060
Less: accumulated depreciation, depletion, amortization and impairment		(1,694,742	)		(1,081,521	)
Property, plant and equipment, net		3,642,147			3,773,539
Derivative assets – noncurrent		22,352			35,192
Other assets		22,422			22,964
Total assets	$	3,907,369		$	3,997,520
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	80,688		$	129,370
Accounts payable – affiliates		9,019			5,850
Derivative liabilities – current		26,392			61,727
Other current liabilities		4,572			3,939
Total current liabilities		120,671			200,886
Long-term debt		751,075			972,100
Derivative liabilities – noncurrent		23,958			13,858
Asset retirement obligations		106,403			80,423
Other liabilities		12,102			18,187
Total liabilities		1,014,209			1,285,454
Commitments and contingencies (Note 10)
Equity:
Members’ equity – Class A units, 1,220,421 and no units outstanding as of December 31, 2020 and 2019, respectively		2,716,892			1,881,733
Noncontrolling interests		176,268			830,333
Total equity		2,893,160			2,712,066
Total liabilities and equity	$	3,907,369		$	3,997,520

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except unit and per unit amounts)

	Year Ended December 31,
	2020			2019			2018
Revenues:
Oil	$	491,780		$	785,750		$	839,867
Natural gas		149,317			173,386			173,769
Natural gas liquids		69,902			86,473			133,874
Midstream and other		43,222			41,631			51,650
Total revenues		754,221			1,087,240			1,199,160
Expenses:
Lease operating expense		202,180			255,106			246,224
Workover expense		6,385			9,789			7,972
Asset operating expense		39,023			40,364			36,171
Gathering, transportation and marketing		173,122			142,214			134,358
Production and other taxes		61,124			88,696			90,709
Depreciation, depletion and amortization		372,300			311,185			267,883
Impairment of oil and natural gas properties		247,215			—			—
Exploration expense		486			469			5,815
Midstream operating expense		9,472			9,968			15,918
General and administrative expense		16,542			2,357			14,365
(Gain) loss on sale of assets		—			(22	)		11,557
Total expenses		1,127,849			860,126			830,972
Income (loss) from operations		(373,628	)		227,114			368,188
Other income (expense):
Interest expense		(38,107	)		(53,577	)		(48,401	)
Other income (expense)		341			402			945
Gain (loss) on derivatives		195,284			(127,202	)		56,562
Total other income (expense)		157,518			(180,377	)		9,106
Income (loss) before taxes		(216,110	)		46,737			377,294
Income tax expense		(14	)		(28	)		(220	)
Net income (loss)		(216,124	)		46,709			377,074
Less: net (income) loss attributable to noncontrolling interests		97,475			(870	)		(98,168	)
Net income (loss) attributable to members	$	(118,649	)	$	45,839		$	278,906
Weighted-average Class A Units outstanding – basic and diluted		773,979			620,206			620,206
Net income (loss) per Class A Unit – basic and diluted	$	(153.30	)	$	73.91		$	449.70

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

	Class A Units		Members’ Equity		Noncontrolling Interest		Total
Balance at January 1, 2018		—	$	1,230,606	$	532,909	$	1,763,515
Net income		—		278,906		98,168		377,074
Contributions		—		623,984		273,659		897,643
Distributions		—		(172,765)		(57,621)		(230,386)
Balance at December 31, 2018		—		1,960,730		847,114		2,807,844
Net income		—		45,839		870		46,709
Contributions		—		—		250		250
Distributions		—		(124,836)		(17,901)		(142,737)
Balance at December 31, 2019		—		1,881,733		830,333		2,712,066
Net loss		—		(118,649)		(97,475)		(216,124)
Contributions				4,704		—		4,704
Distributions		—		(61,421)		(1,146)		(62,567)
Issuance of Class A Units in exchange for the Contributed Entities		620,206		—		—		—
Reclassification of noncontrolling interests		—		(101,926)		101,926		—
Issuance of Class A Units in exchange for the acquisition of Titan Energy		379,794		455,081		—		455,081
December 2020 Exchange (see Note 2)		220,421		657,370		(657,370)		—
Balance at December 31, 2020		1,220,421	$	2,716,892	$	176,268	$	2,893,160

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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INDEPENDENCE ENERGY LLC

COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2020			2019			2018
Cash flows from operating activities:
Net income (loss)	$	(216,124	)	$	46,709		$	377,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		372,300			311,185			267,883
Impairment of oil and natural gas properties		247,215			—			—
(Gain) loss on sale of oil and natural gas properties		—			(22	)		11,557
(Gain) loss on derivatives		(195,284	)		127,202			(56,562	)
Net realized gain (loss) on settlement of derivatives		186,495			(22,743	)		(125,107	)
Equity-based compensation expense		(797	)		(2,721	)		8,005
Write-offs of other long-term assets		—			3,804			317
Debt issuance cost amortization		4,941			4,730			3,451
Other		(29	)		105			(117	)
Changes in operating assets and liabilities:
Accounts receivable		14,652			24,104			(39,935	)
Prepaid and other current assets		17,769			(1,133	)		(494	)
Other assets		117			45			(116	)
Accounts payable and accrued liabilities		(15,138	)		(5,514	)		42,348
Accounts payable – affiliates		657			27			(17,274	)
Other liabilities		(5,746	)		(263	)		(107	)
Net cash provided by operating activities		411,028			485,515			470,923
Cash flows from investing activities:
Development of oil and natural gas properties		(126,164	)		(338,646	)		(207,154	)
Acquisitions of oil and natural gas properties		—			—			(1,461,876	)
Proceeds from the sale of oil and natural gas properties		9,362			15,798			52,968
Purchases of restricted investment securities – HTM		(9,071	)		(5,412	)		(11,061	)
Maturities of restricted investment securities – HTM		9,052			5,414			2,672
Due from related party		(7,353	)		(4,868	)		(1,085	)
Other investing		(766	)		(444	)		(2,928	)
Net cash used in investing activities		(124,940	)		(328,158	)		(1,628,464	)
Cash flows from financing activities:
Repayments of capital lease obligations		(215	)		(207	)		(35	)
Long-term debt borrowings		275,850			553,300			969,600
Long-term debt repayments		(496,875	)		(564,900	)		(513,900	)
Debt issuance costs		(3,333	)		(1,619	)		(8,747	)
Member contributions		5,186			—			623,984
Noncontrolling interest contributions		—			250			273,659
Member distributions		(61,422	)		(124,837	)		(172,765	)
Non-controlling interest distributions		(1,145	)		(17,901	)		(57,621	)
Due to related party		9,865			2,720			20,890
Other financing		—			2			(7,258	)
Net cash provided by (used in) financing activities		(272,089	)		(153,192	)		1,127,807
Net change in cash, cash equivalents and restricted cash		13,999			4,165			(29,734	)
Cash, cash equivalents and restricted cash, beginning of period		27,421			23,256			52,990
Cash, cash equivalents, and restricted cash, end of period	$	41,420		$	27,421		$	23,256

The accompanying notes to financial statements are an integral part of these combined and consolidated financial statements

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(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

References to “we,” “us”, “our” and the “Company” mean the results of Independence Energy LLC.

NOTE 1 – ORGANIZATION AND BASIS OF PRESENTATION

Organization

Independence Energy LLC is an independent energy company formed in June 2020 by investment funds and other entities affiliated with KKR & Co. Inc. (“KKR”), a global investment firm. We seek to generate attractive risk-adjusted returns and cash flow for our members through the exploration, development, production and acquisition of crude oil, natural gas and natural gas liquids (“NGLs”). We maintain a diverse portfolio of proven energy assets, including operated, non-operated, royalty and mineral interests and related midstream infrastructure in key proven basins across the United States, including the Eagle Ford, DJ, Permian and Barnett Basins and the Rockies.

We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of crude oil, natural gas and NGLs. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. All of our operations and assets are located in the United States, and substantially all of our revenues are attributable to United States customers.

Basis of Presentation

Our combined and consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.

In August 2020, through a series of transactions, we underwent a reorganization (the “Reorganization”) in connection with the Titan Acquisition (as defined in Note 3 – Acquisitions and Divestitures), carried out under the direction of our Managing Member whereby certain entities (the “Contributed Entities”) previously owned and under the common control of affiliates of KKR were contributed to us. The financial statements include the accounts of the Contributed Entities from the date of the Reorganization, which is the date the Company obtained a controlling financial interest in these entities, to December 31, 2020 on a consolidated basis. As required by GAAP, the contributions of the Contributed Entities in connection with the Reorganization were accounted for as a reorganization of entities under common control, in a manner similar to a pooling of interests, with all assets and liabilities transferred to us at their carrying amounts. Further, because the Reorganization resulted in a change in reporting entity, and in order to furnish comparative financial information prior to the Reorganization, the financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis.

Independence Energy LLC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including Independence Energy Finance LLC, its wholly owned subsidiary. Independence Energy LLC has no operations, cash flows, or material assets and liabilities other than its investment in Independence Energy Finance LLC.

The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs, and cash flows within the accompanying combined and consolidated balance sheets, statements of operations, and statements of cash flows.

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NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties and valuation of derivative instruments.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.

Restricted Cash

Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to pay for the future abandonment of certain wells in California. Restricted cash is included in other current assets and other assets on our balance sheets.

The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in the statements of cash flows:

	As of December 31,
	2020		2019		2018
	(in thousands)
Cash and cash equivalents	$	36,861	$	19,894	$	20,813
Restricted cash – current		—		3,932		—
Restricted cash – noncurrent		4,559		3,595		2,443
Total cash, cash equivalents and restricted cash	$	41,420	$	27,421	$	23,256

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

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As a result of adopting ASU 2016-13, we establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary. Our allowances for expected credit losses and bad debt were immaterial as of December 31, 2020 and 2019, respectively. We did not incur credit loss expense or bad debt expense related to our accounts receivable during the years ended December 31, 2020, 2019, and 2018. We do not have any off-balance sheet credit exposure related to our customers.

Restricted investment securities

We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within other assets on our combined and consolidated balance sheets.

We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income. At December 31, 2020 and 2019, we had restricted investment securities – HTM with a carrying value of $8.5 million and $8.4 million, respectively.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs (“G&G”) and costs of certain nonproducing leasehold costs are expensed once evaluated and determined to be a dry hole. We incurred exploration expense of $0.5 million, $0.5 million, and $5.8 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.

The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. See discussion of Asset Retirement Obligations below for additional discussion.

During the years ended December 31, 2020, 2019 and 2018, we recognized depletion expense of $364.7 million, $300.9 million and $258.3 million, respectively.

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Other Property, Plant, and Equipment

We have other property, plant, and equipment that consists principally of gathering and processing facilities, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Impairment

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. We perform this analysis on an investments pool basis. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.

In March 2020, crude oil demand experienced significant declines due to the coronavirus disease 2019 (COVID-19) global pandemic and resulting governmental led shut-downs in economic activity. During the second quarter of 2020, as it became apparent that the pandemic would continue indefinitely with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and incurred impairment expense of $247.2 million during the year ended December 31, 2020. We did not incur any impairment expense during the years ended December 31, 2019 and 2018.

Drilling Advances

We pay advances for certain drilling and completion costs on our non-operated properties, as required by our joint operating agreements. At December 31, 2020 and 2019, we had $38.9 million and $4.8 million, respectively, of outstanding advances, reflected net of any related accrued capital expenditures, on our combined and consolidated balance sheets.

Other long-term assets

We acquired certain long-term joint interest receivables that are settled through the underlying oil and natural gas interests of certain joint interest owners. The outstanding balance of these long-term receivables was $1.3 million as of December 31, 2020 and 2019. We recognized write-offs of acquired long-term joint interest receivables totaling $3.8 million within operating expense in the combined and consolidated statement of operations for the year ended December 31, 2019.

Members’ Equity and Noncontrolling interest

We have two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units are considered common units, and distributions are made pro rata in accordance with each Unit’s respective ownership percentage. As of December 31, 2020, all outstanding Class A Units were held by two entities (i) an affiliate of KKR and (ii) an unrelated third-party. No Class B Units were issued or outstanding during the year.

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We record noncontrolling interest associated with third party ownership interests in our combined and consolidated subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our combined and consolidated statements of operations.

In December 2020, certain owners of noncontrolling equity interests in certain of our consolidated subsidiaries elected to exchange 100% of their interests in those individual consolidated subsidiaries for 220,421 of our Class A units (“December 2020 Exchange”). Since we already consolidate the results of these subsidiaries, this transaction was accounted for as a reclassification of $657.4 million from noncontrolling interest to members’ equity with no gain or loss recognized on the exchange.

In August 2020, in connection with the Reorganization, certain interests in our consolidated subsidiaries owned by a third-party investor were not contributed to the Company. These interests were reclassified from members’ equity to noncontrolling interest as of the date of the Reorganization and all income and loss attributable to these interests is recorded as net income (loss) attributable to noncontrolling interests for the period from the date of the Reorganization through the year-ended December 31, 2020.

The following table discloses the effects of changes in the Company’s ownership interest in its subsidiaries on equity associated with the August and December events mentioned above:

	Year Ended December 31,
	2020			2019		2018
	(in thousands)
Net income (loss) attributable to members	$	(118,649	)	$	45,839	$	278,906
Transfers (to) from noncontrolling interest
Decrease in members’ equity related to the Reorganization		(101,926	)		—		—
Increase in members’ equity related to the December 2020 Exchange		657,370			—		—
Net transfers (to) from the noncontrolling interest		555,444			—		—
Changes from net income (loss) attributable to members and transfers (to) from noncontrolling interest	$	436,795		$	45,839	$	278,906

Debt Issuance Costs

We capitalize costs incurred in connection with obtaining financing associated with our revolving credit facilities and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees and are included in other assets in our combined and consolidated balance sheets.

Revenue Recognition

Oil, Gas and NGL Revenues

We hold operated and non-operated interests in producing assets that function as follows:

Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

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Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.

Royalty Interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating, or any other expense associated with drilling and producing an oil and gas well. Royalty interests may be burdened by some or all of the post-production costs related to gathering, processing, and marketing.

We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.

Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.

Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.

Performance Obligations

Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.

At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.

Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.

Incentive Compensation

Incentive compensation includes liability-classified share-based payments issued to employees and non-employees. Liability-classified awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur. Certain of our consolidated subsidiaries have also issued incentive awards that are accounted for similar to cash bonus plans, whereby compensation cost is measured based on the present value of probable expected benefits to be paid and recognized over the period services are provided. Incentive awards similar to cash bonus plans may also have market-based or time-based vesting conditions and are presented as accounts payable and accrued liabilities on our combined and consolidated balance sheets.

Incentive compensation cost is presented as general and administrative expense on our combined and consolidated statements of operations. See Note 11 – Incentive Compensation for additional discussion.

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Business Combinations

We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our combined and consolidated balance sheets as of December 31, 2020 and 2019. The results of operations of an acquired business are included in our combined and consolidated statements of operations from the date of the acquisition.

Credit and Concentration Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry, or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.

The below purchasers represented greater than 10% of our combined and consolidated revenues during the years ended December 31, 2020, 2019 and 2018:

	2020			2019			2018
SN EF Maverick, LLC		15.5	%		20.0	%		24.4	%
Eighty Eight Oil		11.7	%		*			*
Shell Trading US Company		10.4	%		*			*
Cokinos Energy Corporation		*			18.1	%		27.8	%
BP Products North America		*			13.1	%		14.5	%

* Purchaser did not account for greater than 10% of revenue for the year

We believe that the loss of any of our purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Risks and Uncertainties

Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. Oil, natural gas and NGL prices historically have been volatile, and we expect such volatility to continue in the future. Prices for oil, natural gas and NGL are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include the supply of oil, natural gas and NGL, the level of consumer demand, weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows, and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.

Oil, natural gas and NGL revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.

Risk Management

We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or options. We do not use derivative contracts for trading purposes and have not designated any derivative

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instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in gain (loss) on derivatives in our combined and consolidated statements of operations.

Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our combined and consolidated balance sheets.

See Note 6 – Fair Value Measurements.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See Note 10 – Commitments and Contingencies.

Income Taxes

We and our subsidiaries are organized as Delaware limited liability companies and Delaware limited partnerships and are treated as flow-through entities for U.S. federal income tax purposes. As a result, our net taxable income and any related tax credits are passed through to our members or partners, as applicable, and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, we are not subject to any U.S. federal income taxes. We are subject to certain state income taxes, such as the Texas Margin Tax, in certain jurisdictions in which we operate, and any provisions for such taxes are included in income tax expense on our combined and consolidated statements of operations.

Asset Retirement Obligations

An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in depreciation, depletion and amortization expense on our combined and consolidated statements of operations.

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Measuring the future ARO requires management to make estimates, assumptions, and judgments inherent in the present value calculation 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.

See Note 9– Asset Retirement Obligations.

Environmental Expenditures

In addition to ARO, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. As of December 31, 2020 and 2019, we did not have any probable environmental costs.

Supplemental Cash Flow Disclosures

The following are our supplemental cash flow disclosures for the years ended December 31, 2020, 2019 and 2018 (in thousands):

	Year Ended December 31,
	2020		2019		2018
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized	$	33,902	$	49,397	$	43,605
Income taxes paid		14		28		30
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities		12,267		28,305		51,521
Titan Energy acquisition, net of cash acquired – see Note 3		454,599		—		—
Capital lease obligations		—		—		581
December 2020 Exchange		657,370		—		—

Recent Accounting Standards

In August 2018, the FASB issued ASU 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. This standard was adopted on January 1, 2020 and is reflected in our disclosures.

In June 2018, the FASB issued ASU 2018-07, Compensation-Stock Compensation: Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include all share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 is effective for annual periods beginning after December 15, 2019 for all entities other than public business entities, and early adoption is permitted. The adoption of this standard on January 1, 2020 did not have a material impact on our financial statements or related disclosures.

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In June 2016, the FASB issued ASU 2016-13, Financial Instruments, Credit Losses, which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. Accounts receivable from sales of oil and natural gas and joint interest receivables are the primary financial assets that are within the scope of the new guidance. A loss-rate method is applied to these receivables to estimate credit losses. The adoption of this standard on January 1, 2020 did not have a material impact on our financial statements or related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases, which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheets. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” In November 2019 and June 2020, the FASB issued ASU No. 2019-10 and ASU No. 2020-05, respectively, that grant entities in the “all other” category a deferral of the effective date for its leases standard. As a result, this guidance is effective for our 2022 annual financial statements; however, early adoption is permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach. As an emerging growth company, we plan to adopt ASU 2016-02 effective January 1, 2022. We are substantially complete with the assessment of our existing accounting policies and documentation, and enhancement of our internal controls. Adoption of the standard will result in the recognition of additional lease assets and liabilities on our combined and consolidated balance sheet as well as additional disclosures. The adoption is not expected to have a material impact to our combined and consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers, which requires an entity to recognize revenue in a manner that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, the amendment provides five steps that an entity should apply when recognizing revenue. The amendment also specifies the accounting of some costs to obtain or fulfill a contract with a customer and expands the disclosure requirements around contracts with customers. An entity can either adopt this amendment retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, which delays the effective date by one year, making the new standard effective for annual reporting periods beginning after December 15, 2018. In March 2016, ASU 2014-09 was amended by the provisions of ASU 2016-08, which clarifies principal versus agent considerations. In April 2016, ASU 2014-09 was amended by the provisions of ASU 2016-10, which clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. We adopted ASU 2014-09 utilizing a modified retrospective approach effective January 1, 2019, and there was no material impact on our consolidated financial statements and related disclosures.

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NOTE 3 – ACQUISITIONS AND DIVESTITURES

During the three years ended December 31, 2020, we completed the following acquisitions, each of which was accounted for using the acquisition method under GAAP, which requires the acquired assets and liabilities be recorded at fair value as of the acquisition date:

Titan Energy Acquisition

In August 2020, through a series of transactions, we consummated the acquisition of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence Energy LLC to an entity substantially owned by Liberty Holdco. Subsequent to the acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ, Eagle Ford, and Arkoma Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. The fair value of net assets acquired equaled the fair value of the consideration transferred of $455.1 million, and we recognized transaction related expenses of $8.7 million for the year ended December 31, 2020. We expect to complete the purchase price allocation during the second quarter of 2021.

Barnett Gas Acquisition

In May 2018, we acquired certain producing natural gas properties located in North Texas, certain related derivatives, other property and equipment and working capital items from Devon Energy Production Company, L.P. for $480.2 million.

Frio Atascosa Eagle Ford Oil Acquisition

In February 2018, we acquired certain producing and non-producing oil and gas properties located in the Eagle Ford area of South Texas (the “Frio Atascosa Eagle Ford Oil acquisition”) for total cash consideration of $728.2 million. From June 2018 through September 2018, we completed a series of unrelated bolt-on acquisitions adjacent to these properties for aggregate consideration of approximately $253.5 million. We incurred approximately $1.9 million of acquisition costs related to these acquisitions.

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The following table summarizes, for each of the above acquisitions, the consideration transferred and the estimated fair value of identified assets acquired and liabilities assumed at the date of each respective acquisition:

	2020			2018
	Titan Energy			Barnett Gas			Frio Atascosa Eagle Ford Oil
	(in thousands)
Consideration transferred:
Cash	$	—		$	480,165		$	981,683
Membership interest		455,081			—			—
Total	$	455,081		$	480,165		$	981,683
Assets acquired and liabilities assumed:
Cash	$	482		$	—		$	—
Accounts receivable – oil and gas		21,788			952			—
Derivative assets – current		12,000			2,906			—
Prepaid and other current assets		49,079			—			—
Oil and natural gas properties:
Proved properties		375,014			498,098			933,729
Unproved properties		—			—			55,884
Other property, plant, and equipment		30,232			5,846			—
Equipment inventory		—			—			1,092
Derivative assets – noncurrent		114			5,624			—
Accounts payable and other liabilities		(6,185	)		(3,892	)		(1,832	)
Derivative liabilities – current		(4,550	)		(9,946	)		—
Derivative liabilities – noncurrent		(1,484	)		(2,474	)		—
Asset retirement obligations		(21,409	)		(16,949	)		(7,190	)
Fair value of net assets acquired	$	455,081		$	480,165		$	981,683

From the date of the Titan acquisition through December 31, 2020, revenues and net income associated with the operations acquired through the acquisition were $88.2 million and $16.7 million, respectively.

The following table summarizes the unaudited pro forma financial information of the Company for the year ended December 31, 2020 and 2019 as if the acquisition occurred on January 1, 2019:

	Year Ended December 31,
	2020			2019
	(in thousands)
Revenues	$	857,920		$	1,409,789
Net income (loss)	$	(519,524	)	$	49,359

The unaudited pro forma information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed on January 1, 2019, nor is it necessarily indicative of future operating results of the combined entity.

Midland and Ector County Divestiture

In March 2020, we received the remaining $3.9 million from the deep rights sale, described further below, and recognized the reduction to our oil and gas properties for the full sale of $7.9 million.

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In December 2019, we entered into a Term Assignment of Oil and Gas Lease conveying all of our interest in the Midland and Ector county leases between the top of the Mississippian formation down to the base of the Woodford formation, “deep rights”, for total bonus consideration of $7.9 million and a primary term of four years from the effective date, January 1, 2020. We received $4.0 million in December 2019 when the agreement was signed and the remainder was received in March 2020. As of December 31, 2019, the $4.0 million payment was included in accounts receivable – affiliates and deferred in accounts payable and accrued liabilities.

Eagle Ford Divestiture

In September 2019, we entered into a purchase, sale and exchange agreement with an unaffiliated third party, which encompassed the sale of certain producing properties and exchange of oil and gas leases in the Eagle Ford area of South Texas in exchange for cash consideration of $15.2 million and additional post-closing settlement consideration of $1.8 million, $1.2 million of which was received in 2020.

Mississippi Asset Divestiture

In December 2018, we sold all of our interests in the Mississippi assets we acquired in 2014 for which we received $15.0 million of proceeds and recognized $33.1 million of loss on sale of oil and natural gas properties in our combined and consolidated statements of operations.

Eagle Ford Non-operated Divestiture

In May 2018, we sold our interests in certain oil and natural gas properties for a total of $38.0 million cash and recognized $21.5 million of gain on sale of oil and natural gas properties in our combined and consolidated statements of operations.

NOTE 4 – PROPERTY, PLANT, AND EQUIPMENT

The following table summarizes our oil and natural gas properties as of December 31, 2020 and 2019:

	As of December 31,
	2020			2019
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	4,910,059		$	4,420,557
Unproved oil and natural gas properties		288,459			326,331
Oil and natural gas properties, at cost		5,198,518			4,746,888
Less accumulated depreciation, depletion, amortization and impairment		(1,633,664	)		(1,058,551	)
Oil and natural gas properties, net	$	3,564,854		$	3,688,337

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Other Property

The following table summarizes other property, plant and equipment as of December 31, 2020 and 2019:

	Estimated useful life		As of December 31,
			2020			2019
	(years)		(in thousands)
Gathering and pipeline system		30	$	108,777		$	78,545
Vehicles		3-5		7,273			7,093
Computers, furniture, and equipment		3-10		6,812			6,498
Buildings and improvements		5-30		6,797			6,805
Land				5,700			5,700
Field Inventory				3,012			3,531
Total field and other property and equipment, at cost				138,371			108,172
Less: accumulated depreciation, amortization and impairment				(61,078	)		(22,970	)
Total field and other property and equipment, at cost			$	77,293		$	85,202

Capitalized exploratory well costs

Capitalized exploratory well costs are included in unproved oil and natural gas properties. The following table reflects the net changes in capitalized exploratory well costs for the years ended December 31, 2020 and 2019:

	Year Ended December 31,
	2020		2019
	(in thousands)
Balance at beginning of period	$	—	$	297
Additions pending the determination of proved reserves		—		710
Reclassifications to proved properties		—		(1,007	)
Costs charged to expense		—		—
Balance at end of period	$	—	$	—

As of December 31, 2020, we did not have any capitalized exploratory well costs.

NOTE 5 – DERIVATIVES

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our revolving credit facilities that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.

As of December 31, 2020, our commodity derivative instruments consisted of fixed price swaps which are described below:

Fixed Price Swaps: Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.

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The following table details our net volume positions by commodity as of December 31, 2020:

Production Period	Volumes		Weighted Average Fixed Price			Fair Value
						(in thousands)
Crude oil swaps (Bbls):
WTI
2021		9,769,778	$	50.65		$	23,246
2022		7,368,902		47.19			4,082
2023		6,062,936		43.88			(10,628	)
Brent
2021		505,192		53.67			1,230
2022		481,800		56.57			3,146
2023		417,925		53.24			1,522
Natural gas swaps (MMBtu):
2021		69,539,483		2.75			7,528
2022		58,167,404		2.70			6,366
2023		46,912,477		2.48			761
NGL swaps (Bbls):
2021		3,717,002		16.61			(17,084	)
2022		1,516,120		16.12			(4,205	)
Crude oil basis swaps (Bbls):
2021		6,253,643		0.48			800
2022		3,534,661		0.74			(1,379	)
Natural gas basis swaps (MMBtu):
2021		26,606,125		(0.20	)		(2,720	)
2022		24,943,200		(0.17	)		(1,236	)
CMA Roll Hedges:
2021		4,434,097		(0.24	)		(1,495	)
Total						$	9,934

We have variable rate debt outstanding, which is subject to interest rate risk based on volatility in underlying interest rates. As of December 31, 2020, the fair value of our pay-fixed, receive-variable interest rate swaps was an unrealized loss of $7.0 million. Swap terms are as follows:

	Notional Amount		Floating Rate %		Weighted Average Interest Rate %
	(in thousands)
2021	$	535,000		1 Month LIBOR		2.94	%

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We use derivative commodity instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2020 and 2019:

	Gross Fair Value			Effect of Counterparty Netting			Net Carrying Value
	(in thousands)
December 31, 2020
Assets:
Derivative assets – current	$	52,833		$	(21,907	)	$	30,926
Derivative assets – noncurrent		34,257			(11,905	)		22,352
Total assets	$	87,090		$	(33,812	)	$	53,278
Liabilities:
Derivative liabilities – current	$	(48,299	)	$	21,907		$	(26,392	)
Derivative liabilities – noncurrent		(35,863	)		11,905			(23,958	)
Total liabilities	$	(84,162	)	$	33,812		$	(50,350	)

	Gross Fair Value			Effect of Counterparty Netting			Net Carrying Value
	(in thousands)
December 31, 2019
Assets:
Derivative assets – current	$	37,950		$	(6,481	)	$	31,469
Derivative assets – noncurrent		38,951			(3,759	)		35,192
Total assets	$	76,901		$	(10,240	)	$	66,661
Liabilities:
Derivative liabilities – current	$	(68,208	)	$	6,481		$	(61,727	)
Derivative liabilities – noncurrent		(17,617	)		3,759			(13,858	)
Total liabilities	$	(85,825	)	$	10,240		$	(75,585	)

The amount of gain (loss) recognized in gain (loss) on derivatives in our combined and consolidated statements of operations was as follows for the years ended December 31, 2020, 2019 and 2018:

	Years ended December 31,
	2020			2019			2018
	(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions	$	149,713		$	(44,265	)	$	(102,989	)
Realized gain (loss) on natural gas positions		32,638			4,245			(10,801	)
Realized gain (loss) on NGL positions		14,458			13,033			(22,048	)
Realized gain (loss) on interest hedges		(12,435	)		(2,189	)		(280	)
Total realized gain (loss)		184,374			(29,176	)		(136,118	)
Unrealized gain (loss) on commodity hedges		8,836			(94,766	)		195,279
Unrealized gain (loss) on interest hedges		2,074			(3,260	)		(2,599	)
Total unrealized gain (loss)		10,910			(98,026	)		192,680
Total gain (loss) on derivatives	$	195,284		$	(127,202	)	$	56,562

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NOTE 6 – FAIR VALUE MEASUREMENTS

GAAP defines fair value as 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 (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts, or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:

Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities within the fair value hierarchy levels.

Recurring Fair Value Measurements

The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019, by level within the fair value hierarchy:

	Fair Value Measurement Using
	Level 1		Level 2			Level 3		Total
	(in thousands)
December 31, 2020
Financial assets:
Derivative assets	$	—	$	87,090		$	—	$	87,090
Financial liabilities:
Derivative liabilities	$	—	$	(84,162	)	$	—	$	(84,162	)
December 31, 2019
Financial assets:
Derivative assets	$	—	$	76,901		$	—	$	76,901
Financial liabilities:
Derivative liabilities	$	—	$	(85,825	)	$	—	$	(85,825	)

See Note 5– Derivatives.

Non-Recurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 2 and are classified within Level 3.

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As stated in Note 2, in 2020, oil and natural gas properties were written down to their fair value resulting in an impairment expense of $247.2 million. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates, and other relevant data.

Our other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through acquisitions of oil and natural gas properties. The fair value of these assets and liabilities is calculated using a discounted-cash flow approach using Level 3 inputs and is not remeasured in periods after initial recognition. See Note 3 – Acquisitions and Divestitures and Note 9– Asset Retirement Obligations.

Other Fair Value Measurements

The carrying value of cash, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our revolving credit facilities also approximate fair value since the associated variable rates of interest are market based.

NOTE 7– ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities consisted of the following as of December 31, 2020 and 2019:

	As of December 31,
	2020		2019
	(in thousands)
Accounts payable and accrued liabilities:
Accounts payable	$	15,019	$	45,009
Accrued lease operating expense		20,126		27,172
Accrued asset operating expense		3,591		1,489
Accrued capital expenditure		11,793		28,305
Accrued general and administrative		9,549		1,895
Accrued transportation expense		8,399		13,759
Accrued deficiency fees		5,050		—
Other		7,161		11,741
Total accounts payable and accrued liabilities	$	80,688	$	129,370

NOTE 8 – DEBT

Overview

Certain of our subsidiaries have entered into revolving credit facilities with syndicates of lenders that expire between 2022 and 2024 (the “revolving credit facilities”). Our borrowings under these facilities are secured by a first priority lien on substantially all of the assets held by each subsidiary. Borrowings under each facility are generally used for the development and acquisition of oil and natural gas properties, working capital, and general corporate purposes, and such borrowings are limited in use by the subsidiary whose assets collateralize the debt. The amounts we may borrow under each of our revolving credit facilities is limited by a borrowing base, which is based on the oil and natural gas properties, proved reserves, total indebtedness, and other factors and is consistent with customary lending criteria. Borrowing bases are typically re-determined semi-annually, with provisions for additional redeterminations occurring after material acquisitions or dispositions, or more frequently at the request of our lenders.

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Interest

Interest on borrowings is calculated using the London Interbank Offering Rate (“LIBOR”), plus an applicable margin. The applicable margin ranges from 2.00% to 4.00% for LIBOR loans, depending on the percentage of the total borrowing base utilization level. In addition to interest, we pay various fees, including a commitment fee per annum on the unutilized commitment, which is included within interest expense on our combined and consolidated statements of operations. The range of weighted average interest rate on loan amounts outstanding as of December 31, 2020 was 2.85% to 3.89%.

Covenants

Our revolving credit facilities contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. Our facilities also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs under our credit facilities and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies. There is no cross collateralization between our revolving credit facilities.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with LIBOR borrowings. At December 31, 2020 and 2019, we had letters of credit outstanding of $17.8 million and $18.6 million, respectively, which reduce the amount available to borrow under each of our revolving credit facilities. We had $751.1 million and $972.1 million in long-term debt outstanding as of December 31, 2020 and 2019, respectively.

The following table summarizes our revolving credit facilities as of December 31, 2020:

	As of December 31, 2020
	Debt Outstanding		Letters of Credit Issued		Borrowing Base		Maturity
	(in thousands)
Revolving Credit Facilities:
Independence Upstream Holdings LLC	$	32,500	$	—	$	100,000		6/7/2022
Independence Minerals Holdings LLC		15,000		—		37,000		10/25/2024
KNR Resource Investors LP		5,565		250		12,000		6/7/2022
Renee Acquisition LLC		101,310		5,667		145,000		1/31/2023
Newark Acquisition I LP		135,400		6,280		190,000		5/31/2023
Bridge Energy Holdings LLC		35,800		5,574		50,000		7/21/2022
Venado EF LP		156,500		—		160,000		3/10/2022
VOG Palo Verde LP		269,000		—		320,000		2/28/2023
Total long-term debt	$	751,075

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The following table summarizes the five year maturities of our revolving credit facilities:

	As of December 31, 2020
	(in thousands)
2021	$	—
2022		230,365
2023		505,710
2024		15,000
2025		—
	$	751,075

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2020, 2019 and 2018:

	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Balance at beginning of period	$	83,141		$	78,348		$	60,419
Additions		21,860			1,034			25,651
Retirements		(881	)		(1,008	)		(629	)
Accretion expense		5,694			4,767			4,619
Change in estimates		(198	)		—			—
Sale		—			—			(11,712	)
Balance at end of period		109,616			83,141			78,348
Less: current portion		(3,213	)		(2,718	)		(2,525	)
Balance at end of period, noncurrent portion	$	106,403		$	80,423		$	75,823

NOTE 10 – COMMITMENTS AND CONTINGENCIES

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no liability or loss associated with environmental remediation was recognized as of December 31, 2020 except for the following:

We were engaged with the Environmental Protection Agency (EPA) for alleged violations of the Clean Water Act between 2016 and 2018. We have settled these allegations with the EPA and have recorded $1.4 million as a liability and expense at December 31, 2020.

Oil Gathering Agreement

In connection with the execution of an oil gathering agreement with a midstream service provider, we received ownership in a Series D class of equity in the midstream service provider. The Series D units do not give us

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voting or other control rights, but do provide us with an incentive distribution right if other unit classes receive distributions equal to contributed capital plus targeted rates of return. We account for the Series D units through the fair value option available under ASC 825, Financial Instruments. As of December 31, 2020 and 2019, we have concluded the fair value of our investment is not material, based on the nature of the Series D units and overall risk inherent in receiving future cash flows given the stage of development of the entity and required return hurdles.

Carbon Dioxide Purchase Agreement

We assumed one take-or-pay carbon dioxide purchase agreement as part of a prior acquisition. The agreement includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 175 MMcf/per day through May 2021 and 140 MMcf/per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance with the agreement, if we do not meet our minimum volume commitments for a year (or years), we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of December 31, 2020 and 2019, we have met required minimum volumes.

Oil and Natural Gas Transportation and Gathering Agreements

We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $14.5 million, $1.9 million, and $1.2 million of transportation expense in our combined and consolidated statements of operations related to minimum volume deficiencies for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2020:

	As of December 31, 2020
	(in thousands)
2021	$	93,901
2022		89,568
2023		66,883
2024		54,183
2025		51,032
Thereafter		90,972
Total minimum future commitments	$	446,539

NOTE 11 – INCENTIVE COMPENSATION

Overview

Certain of our subsidiaries have entered into award agreements to grant profits interests and other incentive awards to employees and non-employees. These liability-classified awards may contain certain service-, performance-, and market-based vesting conditions, which are further discussed below.

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Liability-classified share-based payments

Certain of our subsidiaries issue profits interests that are classified as equity-based liability awards. These awards contain different vesting conditions ranging from market-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from three to four years. Each of these profits interests are liability-classified due to their repurchase features. Compensation cost for these awards is presented within general and administrative expense with a corresponding credit to other long-term liabilities. The fair value of these awards is remeasured as of the end of each reporting period until settlement.

Incentive compensation cost for liability-classified share-based payments was ($0.8) million, ($2.5) million, and $6.6 million for the years ended December 31, 2020, 2019 and 2018, respectively. Unrecognized compensation cost related to non-vested awards was $1.6 million, $5.0 million, and $10.7 million for the years ended December 31, 2020, 2019 and 2018, respectively, and is expected to be recognized over a weighted-average period of two years. There were no cash settlements of liability-classified share-based payments during the year ended December 31, 2020.

Our time-based awards were measured at fair value using a Monte Carlo simulation as of December 31, 2020. We estimated the expected term of each award considering various exit scenarios. Expected volatility was based on the average of historical and implied volatility of a set of comparable companies, adjusted for size and leverage. The risk-free rate used was based on the yields of U.S. Treasury instruments with comparable terms.

The fair value of the units vested during the year using the fair value measurement as of December 31, 2020 was $7.7 million. As of December 31, 2020, the accounting impact of the market-based awards was determined to be immaterial to the financial statements.

Incentive awards other than share based payments

Certain of our subsidiaries have also issued incentive awards that require continuous service in order to receive distributions, but do not represent an equity interest. As these incentive awards are similar to a cash bonus plan, compensation cost is measured based on the present value of expected benefits that are probable of being paid and recognized over the period services are provided. Compensation cost is remeasured at each reporting period based on expected future benefits and is attributed over the performance period on a straight-line basis. We did not recognize any compensation cost for this type of incentive award for the year ended December 31, 2020.

NOTE 12 – RELATED PARTY TRANSACTIONS

KKR

Pursuant to our management agreement with the Manager (the “Management Agreement”), the Manager has agreed to provide us with management services and other assistance, including with respect to strategic planning, identifying acquisitions, screening and referring potential investments, recommending strategies for exit from investments, executing our authorized investments and providing such other assistance as we may require, including, without limitation, preparing valuations and reports necessary or appropriate for our compliance with our Amended & Restated Limited Liability Company Agreement, dated August 18, 2020 (the “LLC Agreement”). As consideration for its services, KKR has the right to a quarterly management fee to the extent future capital is raised from third parties, to be calculated in accordance with the terms of our LLC Agreement. Our Management Agreement has a perpetual term unless terminated by the mutual consent of us and the Manager or by the removal of the Manager as the Managing Member under our LLC Agreement.

FDL

Certain of our consolidated subsidiaries have entered into an Oil and Natural Gas Property Operating and Services Agreement (the “Agreement”) with FDL. FDL’s management owns less than 0.15% of our Class A

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Units and holds noncontrolling interests in certain of our consolidated subsidiaries. Pursuant to the Agreement, FDL was engaged to manage the day-to-day operations of the business activities of our consolidated subsidiaries, including allocating to us and other interest holders the production and sale of oil, natural gas and natural gas liquids, collection and disbursement of revenues, operating expenses and general and administrative 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. As part of the engagement, FDL will then allocate the revenues, operating expenses, general and administrative expenses and cash collected to us and others as appropriate. We settle balances due to or due from FDL on a monthly basis.

As of December 31, 2020 and 2019, we had a net related party payable due to FDL totaling $7.5 million and $5.0 million, respectively, included within accounts payable – affiliates on our combined and consolidated balance sheets. During the years ended December 31, 2020, 2019 and 2018, we recorded $15.1 million, $18.9 million, and $15.2 million, respectively, as asset operating expenses for direct expenses processed by FDL.

RPM

A KKR entity has entered into a Master Management Services Agreement (the “MSA”) with a subsidiary of RPM Energy Management Partnership L.P. (“RPM”) to act as the manager of certain mineral and non-operated assets controlled by the Contributed Entities. Pursuant to the MSA and under management of KKR affiliates, RPM manages the day-to-day operations of the business activities of certain of our oil and natural gas properties. We reimburse RPM for all reasonable out-of-pocket expenses incurred for fulfilling its obligations under the MSA (“Allocable Overhead Costs”). The Allocable Overhead Costs are charged to us on an actual basis without mark-up or subsidy. As such, the Allocable Overhead Costs approximate reasonable market rates and are representative of the expenses that we would have incurred. We settle balances due to or due from RPM on a monthly basis.

As of December 31, 2020 and 2019 we had a payable due to RPM of $1.7 million and $0.5 million, respectively, included within other current liabilities on our combined and consolidated balance sheets.

NOTE 13 – EARNINGS PER UNIT

We have two classes of equity in the form of Class A Units and Class B Units. Both Class A Units and Class B Units are considered common units, and distributions are made pro rata in accordance with each Unit’s respective ownership percentage. As such, we apply the two-class method for purposes of calculating earnings per unit (“EPU”). Net income (loss) attributable to members is allocated to Class A Units and Class B Units in proportion to the pro rata ownership of each class after giving effect to distributions declared during the period, if any. There were no Class B Units issued or outstanding during the periods presented.

As described in Note 1 – Organization and Basis of Presentation, our financial statements have been retrospectively recast to reflect the historical accounts of the Contributed Entities on a combined basis due to the Reorganization. The denominator for our computation of net income (loss) per unit for periods prior to the Reorganization is calculated based on the number of Class A Units received by our parent as a result of the Reorganization.

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The following table sets for the computation of basic and diluted net income (loss) per unit:

	Year Ended December 31,
	2020			2019			2018
	(in thousands, except unit and per unit amounts)
Numerator:
Net income (loss)	$	(216,124	)	$	46,709		$	377,074
Less: net (income) loss attributable to noncontrolling interests		97,475			(870	)		(98,168	)
Net income (loss) attributable to members	$	(118,649	)	$	45,839		$	278,906
Denominator:
Weighted-average Class A Units outstanding – basic and diluted		773,979			620,206			620,206
Net income (loss) per unit:
Class A Units – basic and diluted	$	(153.30	)	$	73.91		$	449.70

NOTE 14 – SUBSEQUENT EVENTS

Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to December 31, 2020, other than those items disclosed below, that would require additional adjustments to our disclosure in our financial statements.

Acquisition of DJ Minerals Asset

On March 5, 2021, we acquired a portfolio of oil & gas mineral assets from an unrelated third-party operator for a total value of $63.9 million. The purchase was funded using cash on hand and borrowings under our Independence Minerals Holdings LLC credit facility.

April 2021 Exchange

On April 1, 2021, certain co-investors exchanged 100% of their interests in our Barnett natural gas assets for 9,508 Class A Units, representing 0.77% of our consolidated ownership. Since we already consolidate the results of these assets, this transaction will be accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the exchange.

$500.0 million Senior Notes Issuance

On May 6, 2021, Independence Energy Finance, LLC, our wholly owned subsidiary, issued $500.0 million aggregate principal amount of 7.250% Senior Notes due 2026 (the “notes”). The notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year, and mature on May 1, 2026.

The notes will be our senior unsecured obligations and the notes and the guarantees will rank equally in right of payment with the borrowings under our New Credit Agreement (as defined later within this note) and all of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The notes will be guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our New Credit Agreement and certain other capital markets indebtedness. The notes and the guarantees will be effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our New Credit Agreement) to the extent of the value of the collateral securing such indebtedness, and

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structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the notes.

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

If we sell certain of our assets or experience certain kinds of changes of control accompanied by a ratings decline, holders of the notes may require us to repurchase their notes. The notes will not be listed on any securities exchange, and currently there is no public market for the notes.

New Credit Agreement

In connection with the notes issuance, we entered into a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “New Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. The initial committed amount and borrowing base under the New Credit Agreement are $500.0 million and $850.0 million, respectively. The New Credit Agreement matures on May 6, 2025. Upon closing, we borrowed $190.0 million under the New Credit Agreement.

Borrowings under the New Credit Agreement bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted LIBOR), plus an applicable margin or LIBOR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year.

The borrowing base is subject to semi-annual scheduled redeterminations on November 1, 2021 and thereafter on or about April 1st and October 1st of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition or acquisitions of oil and gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (i) the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off (a) of swap agreements the administrative agent relied on in determining the borrowing base or (b) of swap agreements if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

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

The New Credit Agreement contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of

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each fiscal quarter. The New Credit Agreement also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies.

Noncontrolling Interest Carve-out

In connection with the above refinancing transactions, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by our consolidated subsidiaries. Additionally, the third-party investor contributed cash of approximately $35.4 million to repay their proportional share of the underlying debt outstanding under our prior revolving credit facilities and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

Repayment of Prior Revolving Credit Facilities

The combined proceeds from the notes issuance, New Credit Agreement and Noncontrolling Interest Carve-Out were used to fully repay all amounts outstanding under our prior revolving credit facilities, which were then terminated upon the repayment of the remaining principal and accrued interest.

Arkoma Basin Divestiture

On May 18, 2021 we executed a purchase and sale agreement with an unaffiliated third-party which encompassed the sale of certain producing properties and oil and gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million, and recognized a $9.4 million of gain on sale of assets in our combined and consolidated statement of operations.

Distributions

In March 2021, we paid a distribution of $9.4 million for the three months ended December 31, 2020 to holders of our Class A Units.

In June 2021, we paid a distribution of $13.5 million for the three months ended March 31, 2021 to holders of our Class A Units.

Transaction Agreement

On June 7, 2021, we entered into a transaction agreement with Contango Oil & Gas Company (“Contango”) and certain other parties thereto, providing for the combination of Contango’s business with our business under a new publicly-traded holding company (“New PubCo”). The New PubCo will be structured as an “Up-C” with all of the assets and operations of each of us and Contango indirectly held by an operating subsidiary of New PubCo (such operating subsidiary “OpCo”). Contango shareholders will own New PubCo Class A Common Stock, which has both voting and economic rights with respect to New PubCo. Our equityholders will own economic, non-voting limited liability company interests in OpCo (“OpCo Units”) and corresponding New PubCo Class B Common Stock, which has voting (but no economic) rights with respect to New PubCo. New PubCo will be a holding company, the sole material assets of which will consist of OpCo Units. New PubCo will be the sole managing member of OpCo, will be responsible for all operational, management and administrative decisions relating to OpCo’s business and will consolidate the financial results of OpCo and its subsidiaries, including the

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subsidiaries of Independence and Contango. The transaction will be consummated through a series of steps and closing is conditioned upon approval and adoption of the transaction agreement by Contango’s stockholders, expiration of the waiting period under the Hart-Scott-Rodino Act and other customary conditions.

Commodity Derivative Settlement

In June 2021, we settled certain of our outstanding derivative oil commodity contracts for $198.7 million, using borrowings of $160.0 million from our New Credit Agreement described below and cash on hand. Subsequent to the settlement, we entered into new commodity derivative contracts at prevailing market prices.

Derivative Contracts

The following table details our net volume positions by commodity as of June 30, 2021:

Production Period	Volumes		Weighted Average Fixed Price
Crude oil swaps (Bbls):
WTI
2021		4,701,323	$	51.79
2022		7,568,649		61.90
2023		6,130,506		58.71
2024		1,092,000		53.68
Brent
2021		252,973		53.68
2022		500,050		56.36
2023		527,425		52.52
Natural gas swaps (MMBtu):
2021		34,118,935		2.76
2022		58,959,088		2.70
2023		47,512,319		2.48
NGL swaps (Bbls):
2021		1,980,333		17.83
2022		2,242,125		17.02
Crude oil basis swaps (Bbls):
2021		3,147,390		0.49
2022		5,457,176		(0.15	)
Natural gas basis swaps (MMBtu):
2021		14,682,110		(0.20	)
2022		26,061,463		(0.17	)
CMA Roll Hedges:
2021		2,165,868		(0.24	)

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NOTE 15 – SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

Geographic Area of Operation

All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas, Wyoming and Colorado. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a combined and consolidated basis.

Oil and Natural Gas Reserve Information

Subsequent to the issuance of the Company’s 2020 financial statements, we determined that certain of our reserve estimates contained reserves associated with uneconomic wells and did not include overhead or plugging and abandonment costs. As a result, we revised our December 31, 2020 and 2019 reserve balances. We believe the change is immaterial to the reserve totals as it represents a 4,070 MBoe (1%) and 7,665 MBoe (2%) decrease from the originally reported total MBoe December 31, 2020 and 2019 reserve balances. The following table presents our net proved reserves, on a revised basis, for the years ended December 31, 2020, 2019 and for the year ended December 31, 2018 and the changes in net proved oil, natural gas and NGL reserves during such years:

	Year Ended December 31, 2020
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		211,533			1,161,239			61,126			466,199
Revisions of previous estimates (1)		(57,708	)		(478,153	)		(20,279	)		(157,680	)
Extensions, discoveries, and other additions		4,088			21,479			603			8,271
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		22,409			196,840			18,952			74,168
Production		(13,132	)		(78,541	)		(5,078	)		(31,300	)
Net proved reserves at end of period		167,190			822,864			55,324			359,658
	Year Ended December 31, 2019
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		202,805			1,189,962			75,780			476,913
Revisions of previous estimates		10,477			20,552			(11,321	)		2,581
Extensions, discoveries, and other additions		12,003			24,472			1,855			17,936
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		—			—			—			—
Production		(13,752	)		(73,747	)		(5,188	)		(31,231	)
Net proved reserves at end of period		211,533			1,161,239			61,126			466,199
	Year Ended December 31, 2018
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Net proved reserves at beginning of period		129,887			286,619			43,747			221,405
Revisions of previous estimates (2)		(15,332	)		(44,977	)		(8,902	)		(31,730	)
Extensions, discoveries, and other additions		3,288			5,561			512			4,727
Sales of reserves in place		(1,401	)		(39,913	)		(242	)		(8,296	)
Purchases of reserves in place		99,573			1,041,027			45,551			318,628
Production		(13,210	)		(58,355	)		(4,886	)		(27,821	)
Net proved reserves at end of period		202,805			1,189,962			75,780			476,913

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(1) Revisions of previous estimates include 92.0 MBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.

(2) Revisions of previous estimates primarily related to the impact of certain of our operators’ bankruptcies on our oil and gas properties, and the removal of certain PUD locations related to those operators.

The following table sets forth our net proved oil, natural gas and NGL reserves, on a revised basis, as of the years ended December 31, 2020 and 2019, and as of the years ended December 31, 2018 and 2017:

Proved Developed Reserves	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
December 31, 2020		92,024		748,496		44,307		261,079
December 31, 2019		103,728		870,491		48,997		297,808
December 31, 2018		113,917		933,774		60,275		329,820
December 31, 2017		79,618		196,258		26,919		139,248
Proved Undeveloped Reserves	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
December 31, 2020		75,166		74,368		11,017		98,579
December 31, 2019		107,805		290,748		12,129		168,391
December 31, 2018		88,888		256,188		15,505		147,093
December 31, 2017		50,269		90,361		16,828		82,157

During the year ended December 31, 2020, we added 8,271 MBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin and in various mineral interests. Approximately 57% of the reserve additions for the year ended December 31, 2020 were crude oil and NGLs. Purchases in place of 74,168 MBoe were primarily related to the Permian and DJ Basins.

During the year ended December 31, 2019, we added 17,936 MBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian and Eagle Ford Basins. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.

During the year ended December 31, 2018, we added 318,628 MBoe of reserves through acquisitions in the Eagle Ford Shale and Barnett Shale. Approximately 54% of the acquired reserves for the year ended December 31, 2018 were natural gas, while 31% were crude oil.

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our crude oil and natural gas producing activities as of December 31, 2020 and 2019:

	As of December 31,
	2020			2019
	(in thousands)
Proved oil and natural gas properties (successful efforts method)	$	4,910,059		$	4,420,557
Unproved oil and natural gas properties		288,459			326,331
Oil and natural gas properties, at cost		5,198,518			4,746,888
Less accumulated depreciation, depletion and amortization		(1,666,620	)		(1,058,551	)
Net capitalized costs	$	3,531,898		$	3,688,337

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table summarizes costs incurred related to our oil and gas activities years ended December 31, 2020, 2019 and 2018:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Acquisition costs:
Proved	$	355,010	$	795	$	1,426,838
Unproved		680		7,264		59,212
Exploration costs		—		710		397
Development		83,013		318,157		208,655
Total costs incurred	$	438,703	$	326,926	$	1,695,102

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

The following information has been developed utilizing procedures prescribed by ASC 932 – Extractive Industries – Oil and Gas and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for commodity prices for the year ended December 31, 2017. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.

The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Subsequent to the issuance of the Company’s 2020 financial statements, we determined that certain of our reserve estimates contained reserves associated with uneconomic wells and did not include overhead or plugging and abandonment costs. As a result, we revised our December 31, 2020 and 2019 discounted future net cash flows. We believe the change is immaterial to the discounted future net cash flows totals as it represents a $3.4 million (less than 1%) decrease and a $1.6 million (less than 1%) increase from the originally reported December 31, 2020 and 2019 discounted future net cash flows totals. The following tables show the reserves on a revised basis.

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The following table sets forth the standardized measure of discounted future net cash flows from projected production of our oil and gas reserves, on a revised basis, for the years ended December 31, 2020, 2019 and for the year ended December 31, 2018:

	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Future cash inflows	$	8,232,932		$	15,745,942		$	18,281,840
Future production costs		(4,280,563	)		(6,766,410	)		(7,747,910	)
Future development costs(1)		(1,353,957	)		(2,323,420	)		(2,099,593	)
Future income taxes		(30,155	)		(63,136	)		(73,387	)
Future net cash flows		2,568,257			6,592,976			8,360,950
Annual discount of 10% for estimated timing		(1,240,397	)		(3,482,128	)		(4,153,603	)
Standardized measure of discounted future net cash flows	$	1,327,860		$	3,110,848		$	4,207,347

(1) Future development costs include future abandonment and salvage costs.

Changes in standardized measure of discounted future net cash flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2020, 2019 and 2018:

	Year Ended December 31,
	2020			2019			2018
	(in thousands)
Balance at beginning of period	$	3,110,848		$	4,207,347		$	1,394,865
Net change in prices and production costs		(1,184,939	)		(821,874	)		747,150
Net change in future development costs		160,465			(59,359	)		(1,568	)
Sales and transfers of oil and natural gas produced, net of production expenses		(290,053	)		(568,665	)		(720,524	)
Extensions, discoveries, additions and improved recovery, net of related costs		31,688			182,697			61,131
Purchases of reserves in place		176,480			—			2,583,348
Sales of reserves in place		—			—			(42,045	)
Revisions of previous quantity estimates		(887,395	)		(226,561	)		191,689
Previously estimated development costs incurred		32,873			15,676			27,420
Net change in taxes		19,350			(19	)		(22,825	)
Accretion of discount		283,954			424,278			138,904
Changes in timing and other		(125,411	)		(42,672	)		(150,198	)
Balance at end of period	$	1,327,860		$	3,110,848		$	4,207,347

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