GEP HAYNESVILLE, LLC AND SUBSIDIARIES

Consolidated Financial Statements

As of December 31, 2020 and 2019

and for the Years Ended December 31, 2020 and 2019

(With Independent Auditors’ Report)

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Financial Statements and Supplementary Data:
Independent Auditors’ Report	1-2
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statements of Changes in Equity	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7-26
Supplemental Information on Natural Gas Exploration and Production Activities (Unaudited)	27-32

Deloitte & Touche LLP

1111 Bagby Street

Suite 4500

Houston, TX 77002-2591

USA

Tel: +1 713 982 2000

Fax: +1 713 982 2001

www.deloitte.com

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of

GEP Haynesville, LLC

We have audited the accompanying consolidated financial statements of GEP Haynesville, LLC and its subsidiaries (the “Company”), which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

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

Auditors’ Responsibility

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

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

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GEP Haynesville, LLC and its subsidiaries as of December 31, 2020 and 2019, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

1

Emphasis of Matter

As discussed in Note 15 to the consolidated financial statements, a related party provides certain management and general and administrative support services to the Company and as such, the accompanying consolidated financial statements include expenses that have been incurred by a related party on behalf of the Company. These amounts incurred by the related party are then allocated and billed to the Company and are classified as general and administrative expenses in the statement of operations. These expenses may not fully reflect the expenses that would have been incurred by the Company had such services been provided by an unaffiliated company during the period presented. Our opinion is not modified with respect to this matter.

March 19, 2021

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

As of December 31, 2020 and 2019

(Amounts in thousands)

	2020				2019
Assets
Current assets:
Cash and cash equivalents	$	12,411			$	24,463
Accounts receivable – natural gas			57,808				44,607
Accounts receivable – other			37,861				63,791
Derivative assets			10,006				42,728
Other current assets			3,797				4,864
Total current assets			121,883				180,453
Natural gas properties, successful efforts method:
Proved properties			2,146,164				1,857,539
Unproved properties			365,090				434,870
Less accumulated depreciation, depletion, and amortization			(965,230	)			(664,680	)
Natural gas properties, net			1,546,024				1,627,729
Other property and equipment, net			3,321				3,613
Debt issuance costs, net			812				1,522
Derivative assets	—						2,800
Other long-term assets			220				3,120
Total assets	$	1,672,260			$	1,819,237
Liabilities and Equity
Current liabilities:
Accounts payable and accrued liabilities	$	25,212			$	26,589
Accounts payable – related party			5,595				5,732
Revenue payable			42,080				34,342
Accrued exploration and development costs			32,279				44,870
Gas gathering liabilities	—						18,544
Total current liabilities			105,166				130,077
Long-term liabilities:
Long-term debt			226,000				255,000
Asset retirement obligations			29,696				29,005
Derivative liabilities			1,309				578
Other long-term liabilities			570				972
Total liabilities			362,741				415,632
Commitments and contingencies (Note 13)
Mezzanine equity:
Series B Preferred Units			1,057,947				952,055
Members’ equity:
Class A Common Units			158,107				302,123
Class B Common Units			93,465				149,427
Total members’ equity			251,572				451,550
Total liabilities and equity	$	1,672,260			$	1,819,237

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

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2020 and 2019

(Amounts in thousands)

	2020				2019
Natural gas revenues	$	369,604			$	423,647
Operating expenses
Lease operating			51,841				46,617
Gathering and transportation			94,726				100,336
Production and ad valorem taxes			14,599				14,764
Exploration			193				948
Leasehold impairment	—						10,191
Depreciation, depletion, and amortization			301,227				242,868
Accretion of gas gathering liabilities and asset retirement obligations			1,577				3,534
Gain on sale of assets			(30	)			(3,099	)
General and administrative (includes related party management fees of $16,086 and $16,220, respectively, and overhead recoveries of ($14,655) and ($14,489), respectively)			6,522				10,147
Total operating expenses			470,655				426,306
Operating loss			(101,051	)			(2,659	)
Other income (expense)
Gain on derivatives, net			24,625				75,433
Interest expense			(1,084	)			(1,734	)
Other			(1,666	)			(237	)
Total other income (expense)			21,875				73,462
Net (loss) income			(79,176	)			70,803
Preferred distributions			(120,802	)			(113,083	)
Net loss attributable to members’ equity	$		(199,978	)	$		(42,280	)

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

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2020 and 2019

(Amounts in thousands)

	Mezzanine Equity Series B Preferred Units				Class A Common Units				Class B Common Units				Total Members’ Equity
Balance at December 31, 2018	$	888,972			$	264,047			$	112,396			$	376,443
Contributions			—				66,667				—				66,667
Preferred distributions – accrued			113,083				(83,103	)			(29,980	)			(113,083	)
Conversion of Preferred Units			(50,000	)			—				50,000				50,000
Equity-based compensation			—				544				176				720
Net income			—				53,968				16,835				70,803
Balance at December 31, 2019			952,055				302,123				149,427				451,550
Preferred distributions – accrued			120,802				(86,996	)			(33,806	)			(120,802	)
Preferred distributions – cash			(14,910	)	—				—						—
Net loss	—						(57,020	)			(22,156	)			(79,176	)
Balance at December 31, 2020	$	1,057,947			$	158,107			$	93,465			$	251,572

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

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2020 and 2019

(Amounts in thousands)

	2020				2019
Cash flows from operating activities:
Net (loss) income	$		(79,176	)	$	70,803
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, and amortization			301,227				242,868
Exploration expense			16				83
Leasehold impairment	—						10,191
Accretion of gas gathering liabilities and asset retirement obligations			1,577				3,534
Equity-based compensation	—						720
Shortfall payments on gas gathering liability			(6,723	)			(30,208	)
Volumetric adjustment to gas gathering liability			(12,390	)			(76	)
Loss (gain) on sale of assets			2				(2,918	)
Unrealized loss (gain) on derivatives, net			36,253				(44,400	)
Amortization of debt issuance costs			917				1,180
Other gain			(236	)			(102	)
Changes in operating assets and liabilities:
Accounts receivable – natural gas			(13,201	)			36,786
Accounts receivable – other			28,830				(42,683	)
Other current assets			1,067				577
Accounts payable and accrued liabilities			(3,324	)			(365	)
Accounts payable – related party			(137	)			(1,156	)
Revenue payable			7,670				(10,456	)
Net cash provided by operating activities			262,372				234,378
Cash flows from investing activities:
Divestiture of natural gas properties	—						6,747
Exchange of natural gas properties			(1,953	)			—
Additions to natural gas properties			(227,966	)			(347,288	)
Additions to other property and equipment			(388	)			(1,305	)
Net cash used in investing activities			(230,307	)			(341,846	)
Cash flows from financing activities:
Proceeds from revolving credit facility			32,000				65,000
Repayments on revolving credit facility			(61,000	)			(40,000	)
Debt issuance costs			(207	)			(223	)
Distributions – Series B Preferred Units			(14,910	)			—
Contributions – Class A Common Units	—						66,667
Net cash (used in) provided by financing activities			(44,117	)			91,444
Net decrease in cash			(12,052	)			(16,024	)
Cash and cash equivalents at beginning of period			24,463				40,487
Cash and cash equivalents at end of period	$	12,411			$	24,463

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

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(1)    Organization and Nature of Operations

GEP Haynesville, LLC, a Delaware limited liability company, together with its wholly owned subsidiaries (collectively, the “Company”) is engaged in the acquisition, exploration, development and production of natural gas assets in the onshore United States. The Company’s natural gas assets are located in North Louisiana targeting the Haynesville and Middle Bossier shale formations. The Company was formed on August 13, 2015 and is headquartered in The Woodlands, Texas.

The Company’s principal equity owners are GeoSouthern Haynesville, LP (“Haynesville LP”) and entities affiliated with Blackstone Credit, (formerly GSO Capital Partners, LP) GSO GEPH Holdings LP (“GSO GEPH”) and GSO Energy Partners-B LP (“GSO EPB” and, together with GSO GEPH, “BXC”). On August 24, 2015, Haynesville LP and BXC executed the Company’s organization documents which govern its ownership, management, and operations.

On November 12, 2015, the Company completed the acquisition of certain natural gas properties in North Louisiana from Ovintiv USA Inc. (as successor in interest to Encana Oil & Gas (USA) Inc.) (“Ovintiv”) and Pavillion Land Development, LLC (the “Ovintiv Acquisition”) for cash consideration of $811.8 million. On June 12, 2017, the Company acquired additional natural gas properties in North Louisiana from Sabine Oil & Gas Corporation (the “Sabine Acquisition”) for cash consideration of $45.1 million. The Ovintiv Acquisition and Sabine Acquisition were financed with cash contributions from Haynesville LP and BXC. On January 31, 2018, the Company exchanged certain natural gas properties with Vine Oil and Gas LP (the “Vine Asset Exchange”). On July 1, 2020, the Company completed an asset exchange with Comstock Oil and Gas-Louisiana, LLC (“Comstock” and the “Comstock Asset Exchange”). See Note 5 – Comstock Asset Exchange for additional information.

(2)    Summary of Significant Accounting Policies

(a)Basis of Presentation

The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany transactions and balances have been eliminated upon consolidation. In the notes to consolidated financial statements, all dollar amounts in tabulations are in thousands of dollars unless otherwise indicated.

(b)Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions which affect the reported amount of assets and liabilities, the 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. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from those estimates.

Significant estimates made in preparing the consolidated financial statements include, among other things, the estimated quantities of proved natural gas reserves and associated cash flows used to calculate depletion and impairment of proved natural gas properties; the evaluation of unproved properties for impairment; the estimated present value of future net cash flows used in the valuation of purchase price allocation; accruals related to natural gas sales volumes and revenue, capital expenditures, and lease operating expenses; the fair value of derivative instruments; equity-based compensation; commitments and contingencies; and the timing and amount of future plugging and abandonment costs used in calculating asset retirement obligations. Changes in the assumptions utilized could have a significant impact on reported results in future periods.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(c)Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with an original or remaining maturity of three months or less to be cash equivalents. The Company maintains cash balances in deposit and money market accounts with major financial institutions, which at times exceed federally insured limits.

(d)Accounts Receivable

The Company’s accounts receivable consists primarily of receivables from natural gas purchasers, receivables from joint interest owners on properties the Company operates, and revenues receivable from operators for the sale of hydrocarbons on properties the Company does not take its share of production in-kind. The Company reviews its accounts receivable periodically, and if necessary, reduces the carrying amount by a valuation allowance that reflects management’s best estimate of all potentially uncollectible amounts. The Company made no allowances for uncollectible accounts as of December 31, 2020 and 2019. See Note 14 – Well Control Incident for additional information.

(e)Natural Gas Properties

The Company accounts for its natural gas exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete successful exploratory wells and development wells are capitalized. Property and leasehold acquisition costs are also capitalized. Exploration costs, including certain seismic expenditures, geological and geophysical costs, and delay rentals for natural gas leases are charged to exploration expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the Company determines that the well does not contain proved reserves. All exploratory wells are evaluated for economic viability within one year of well completion. There were no exploratory wells in progress for the years ended December 31, 2020 and 2019.

The Company reviews its proved natural gas properties for impairment when events and circumstances indicate a significant decline in the recoverability of the carrying value of such properties or at least annually. The Company estimates the expected undiscounted future cash flows of its proved natural gas properties and compares such undiscounted future cash flows to the carrying value of its proved natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will recognize an impairment loss for the amount by which the property’s carrying value exceeds its estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, inflation and discount rates commensurate with the risk associated with realizing the projected cash flows. There were no impairments of proved natural gas properties for the years ended December 31, 2020 and 2019.

Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Unproved properties and the related costs are transferred to proved properties when reserves are discovered or otherwise attributed to the property. Unproved properties are assessed for impairment on a prospective basis at least annually. Indicators of potential impairment include changes due to economic factors and potential shifts in business strategy. The likelihood of an impairment of unproved properties increases as the expiration of a lease term approaches and drilling activity has not commenced. If the Company does not intend to develop the property prior to expiration of the lease or does not have the intent and ability to extend, renew, trade or sell the lease prior to expiration, impairment expense is recorded. Abandonment expense for lease expirations where the lease was not previously impaired is recorded as the lease expires. There were no unproved property impairments for the year ended December 31, 2020. The Company recorded $10.2 million for unproved property impairments and lease expirations for the year ended December 31, 2019.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in process to bring the projects to their intended use.

Depreciation, Depletion, and Amortization: Costs of drilling, completing, and equipping successful exploratory wells, development wells, costs to construct or acquire facilities and associated asset retirement costs are depleted on a unit-of-production basis over the remaining life of total estimated proved developed reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted on a unit-of-production basis over the remaining life of total estimated proved reserves. See Note 4– Natural Gas Properties for additional information.

(f)Other Property and Equipment

Other property and equipment is carried at cost and consists of land, buildings, field equipment, leased vehicles, and computer equipment. Depreciation is computed on a straight-line basis over a three to thirty-nine year period based on the estimated economic life of the respective asset class. Depreciation expense was $0.7 million for each of the years ended December 31, 2020 and 2019. Costs for maintenance and repairs are expensed in the period incurred.

(g)Debt Issuance Costs

Debt issuance costs consist of costs incurred in connection with obtaining debt financing that are capitalized and amortized to interest expense using the effective interest method over the term of the applicable debt instrument. Amortization expense was $0.9 million and $1.2 million for the years ended December 31, 2020 and 2019, respectively. The Company presents debt issuance costs, net of amortization within long-term assets on the consolidated balance sheets. See Note 10 – Long-Term Debt for additional information.

(h)Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the plugging, abandonment, and site restoration of its natural gas properties. A liability for the fair value of an asset retirement obligation (“ARO”) and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired.

The fair value of the liability recognized is based on the present value of the estimated future cash outflows associated with plugging and abandonment obligations. Estimating the ARO requires management to make estimates, assumptions, and judgments regarding such factors as plugging and abandonment costs, timing of settlements, the credit-adjusted risk-free rate, and inflation rates. The Company depletes the amount added to proved natural gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective natural gas properties. When the ARO is settled or the asset is sold, the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded within other income (expense) on the consolidated statements of operations. The Company reassesses the ARO annually to determine whether a change in the estimate is necessary. Any revisions result in prospective changes to accretion expense. See Note 6 – Asset Retirement Obligations for additional information.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(i)Income Taxes

Since the Company is a limited liability company and files as a partnership for federal income tax purposes, the income or loss of the Company for federal and state income taxes is generally allocated to the members to report their share of taxable income or loss on their separate income tax returns. Accordingly, no recognition has been given to federal or state income taxes in the consolidated financial statements. For tax years beginning on or after January 1, 2018, the Company is subject to partnership audit rules enacted as part of the Bipartisan Budget Act of 2015 (the “Centralized Partnership Audit Regime”). Under the Centralized Partnership Audit Regime, any IRS audit of the Company would be conducted at the Company level, and if the IRS determines an adjustment, the default rule is that the Company would pay an “imputed underpayment” including interest and penalties, if applicable. The Company may instead elect to make a “push-out” election, in which case the partners for the year that is under audit would be required to take into account the adjustments on their own personal or business income tax returns. If the Company does not elect to make a “push-out” election, the Company’s operating agreement requires current members to indemnify the Company for their specific share of the imputed underpayment.

If the Company receives an imputed underpayment, a determination will be made based on the relevant facts and circumstances that exist at that time to allocate such imputed underpayment to each partner based on their specific share of such imputed underpayment. Any payments that the Company ultimately makes on behalf of its current members will be reflected as a distribution, rather than tax expense, at the time that such distribution is declared.

(j)Revenue Recognition

Product Revenue: The Company’s revenues are derived from the sale of natural gas. Sales of natural gas are recognized at the point in time when the Company satisfies a performance obligation by transferring control of a product to a customer at a designated delivery point. Payment is generally received one to three months after the sale has occurred. The amount of natural gas sales to which the Company is entitled is based on its revenue interests in the properties. The Company had no material imbalances as of December 31, 2020 and 2019. The Company reports revenues disaggregated by product on its consolidated statements of operations. The accounts receivable – natural gas balance as of December 31, 2020 and 2019 was $57.8 million and $44.6 million, respectively.

Pursuant to the Company’s natural gas sales contracts with its purchasers, the Company delivers natural gas to the purchasers at agreed upon delivery points. The Company utilizes third parties to gather, compress, treat, and transport natural gas from the wellhead to the delivery points specified in the sales contracts. These costs are recorded as gathering and transportation expenses. The Company’s sales contracts typically include consideration that is based on prices tied to local indices for volumes delivered at the delivery points. The Company transfers control of the product at the delivery points and recognizes revenue based on the contract price.

Transaction Price Allocated to Remaining Performance Obligations: The Company has utilized the practical expedient allowed in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, for contracts that are short-term in nature. This exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future natural gas volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances: Under the Company’s sales contracts, once performance obligations have been satisfied, payment is unconditional. The Company does not receive payment prior to performance under its natural gas sales contracts. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.

(k)Concentration of Credit Risks

Major Customers: The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and natural gas industry. During the years ended December 31, 2020 and 2019, Ovintiv Marketing Inc. (as successor in interest to Encana Marketing (USA) Inc.) purchased approximately 94% and 88% of the Company’s natural gas production volumes, respectively. The Company reviews its natural gas purchasers for creditworthiness and general financial condition and has not experienced any significant losses on its receivables.

Joint Interest Receivables: The Company operates a substantial portion of its natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on the properties it operates.

Derivative Instruments: The Company is exposed to credit risk on its derivative contracts related to potential non-performance by its counterparties. The Company has executed International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with its counterparties for the purpose of entering into derivative contracts. The terms of the ISDA Agreements provide the Company and its counterparties with netting rights such that payables may be offset against receivables with a counterparty under separate derivative contracts.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. As of December 31, 2020, the Company’s derivative counterparties included nine financial institutions, eight of which are secured lenders in the Revolving Credit Facility. As of December 31, 2020 and 2019, the Company did not have any past-due receivables from or payables to any of its derivative counterparties.

Financial Instruments: The Company’s cash balances, at times, exceed federally insured limits. Deposits in the United States of America are guaranteed by the Federal Deposit Insurance Corporation. The Company monitors the financial condition of the financial institutions in which it maintains deposit balances and has not experienced any losses associated with its accounts.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(l)401(k) Plan

The Company sponsors a 401(k) tax deferred savings plan for its employees. Prior to May 1, 2020 the Company matched employee contributions dollar-for-dollar on the first 10% of an employee’s pre-tax earnings, subject to individual IRS limitations, in cash. The first 0-6% is Safe Harbor with immediate vesting and the additional 7-10% is discretionary with three year cliff vesting. All employees of the Company are eligible to participate, and participation in the plan is voluntary. The Company provided matching contributions of $0.1 million and $0.3 million for the years ended December 31, 2020 and 2019, respectively.

(m)Derivative Instruments and Hedging Activities

The Company enters into derivative contracts, primarily swaps, collars, call, and put options, to manage its exposure to commodity price fluctuations on a portion of its anticipated future natural gas production. All of the Company’s derivatives are used for risk management and are not held for speculative trading purposes.

The Company follows ASC Topic 815, Derivatives and Hedging (“ASC 815”). The Company’s derivative instruments are recorded on the consolidated balance sheets as either current or long-term assets or liabilities measured at their fair value. The Company’s derivatives are reflected on the consolidated balance sheets on a net basis by counterparty when they are governed by ISDA Agreements. The Company has elected not to designate any of its derivative positions for hedge accounting. Accordingly, the Company records the net change in the fair value of these positions, as well as payments and receipts on settled contracts, in gain (loss) on derivatives, net within other income (expense) on the consolidated statements of operations. Gain (loss) on derivatives, net are included in cash flows from operating activities on the consolidated statements of cash flows.

(n)Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurement, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•Level 1: Unadjusted quoted market prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

•Level 2: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

•Level 3: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

Valuation techniques that maximize the use of observable inputs are favored. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair value information is included in the notes to the consolidated financial statements when it is required by applicable guidance. See Notes 5 – Comstock Asset Exchange, 8 – Derivative Instruments and HedgingActivities, 9 – Fair Value Measurements, and 12 – Equity-Based Compensation for additional information.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(o)COVID-19

On March 11, 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. The Company continues to closely monitor the impact of the COVID-19 pandemic on all aspects of its business, including how it may impact the Company’s customers, employees, vendors and contractors. While the Company did not incur significant disruptions to its operations during the year ended December 31, 2020 as a result of the COVID-19 pandemic, the Company is unable to predict the ultimate impact of COVID-19 on its financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties. These uncertainties include the severity of the virus, the duration of the outbreak, the pace of vaccine development and immunization programs, governmental or other actions taken to combat the virus (which could include limitations on the Company’s operations or the operations of the Company’s customers and vendors), and the effect that the COVID-19 pandemic has on the demand for oil and natural gas. The impacts of a potential worsening of global economic conditions and the continued volatility in the commodity and financial markets present material uncertainty and risk with respect to the Company’s performance and financial results. The Company has noted this impact in its assessment of the decline in natural gas prices below.

Sustained or additional weakness in natural gas prices could affect the Company’s business in numerous ways, including a negative impact on the Company’s revenues, earnings and cash flows, a decrease in proved reserves, impairments of the Company’s natural gas properties, and reductions in the borrowing base under the Revolving Credit Facility.

(p)Commitments and Contingencies

The Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. The Company is subject to various legal proceedings and claims which arise in the ordinary course of business. Management believes that the final disposition of such matters will not have a material adverse effect on the Company’s financial position, results of operations, or cash flows.

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. See Note 13 – Commitments and Contingencies and Note 14 – Well Control Incident for additional information.

(q)Environmental Remediation

The Company may become subject to certain environmental liabilities related to the remediation of well sites and associated facilities. In connection with the Company’s acquisition of existing or previously drilled wells, the Company may not be aware of the environmental safeguards that were taken at the time such wells were drilled or operated. Liabilities are accrued when environmental assessments and/or remediation is probable and the costs can be reasonably estimated. For the years ended December 31, 2020 and 2019, the Company had not accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows.

13

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(r)Recent Issues and Applicable Accounting Pronouncements

Not Yet Adopted

In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) establishing a right-of-use model that requires a lessee to record a right-of-use asset and a lease liability on the balance sheet for most leases. Leases will be classified as either financing or operating, with classification affecting the pattern of expense recognition in the statement of financial position. This guidance is effective for fiscal years beginning after December 15, 2021, and interim periods within fiscal years beginning after December 15, 2022 with earlier application permitted. Management does not expect the adoption of this standard to have a material impact on its consolidated financial statements and related disclosures.

(s)Subsequent Events

The Company follows the FASB ASC Topic 855, Subsequent Events. The standard defines subsequent events as either recognized or unrecognized subsequent events. The Company has evaluated subsequent events through the issuance date of March 19, 2021. See Note 16 – Subsequent Events for additional information.

(3)    Supplemental Cash Flow Information

The following table presents supplemental non-cash information for the years ended December 31, 2020 and 2019:

	2020				2019
Cash flows from investing activities:
Exchange of natural gas properties
Exchange of revenue payable, net	$	68			$	—
Exchange of asset retirement obligations, net			(101	)	—
Additions to natural gas properties
Accounts payable and accrued liabilities			4,573			3,026
Accrued exploration and development costs			32,279			44,870
Asset retirement obligations			231			164
Cash flows from financing activities:
Preferred distributions – accrued			105,892			113,083

The Company made cash payments of $14.0 million and $11.8 million for interest, including amounts capitalized, for the years ended December 31, 2020 and 2019, respectively. The Company did not make any cash payments for income taxes for the years ended December 31, 2020 and 2019.

14

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(4)    Natural Gas Properties

The following table presents natural gas properties for the years ended December 31, 2020 and 2019:

	2020				2019
Proved properties	$	2,146,164			$	1,857,539
Unproved properties			365,090				434,870
Total capitalized costs			2,511,254				2,292,409
Less accumulated depreciation, depletion, and amortization			(965,230	)			(664,680	)
Natural gas properties, net	$	1,546,024			$	1,627,729

The Company capitalized interest expense totaling $12.6 million and $11.9 million in the years ended December 31, 2020 and 2019, respectively.

Depreciation, depletion, and amortization expense for the Company’s natural gas properties was $300.5 million and $242.2 million for the years ended December 31, 2020 and 2019, respectively.

(5)    Comstock Asset Exchange

In 2020, the Company completed an exchange of natural gas properties located in North Louisiana. The transaction was accounted for using the acquisition method of accounting as required by FASB ASC Topic 805, Business Combinations, which requires, among other things, that assets acquired and liabilities assumed be recorded at fair value on the date of exchange. Significant inputs to the valuation of assets acquired and liabilities assumed requiring assumptions, judgements, and estimates include quantities of natural gas reserves, future commodity prices, and estimated future cash flows.

On July 1, 2020, the Company completed an asset exchange with Comstock covering properties located in Red River and DeSoto Parishes in Northwest Louisiana. The Company conveyed primarily unproved properties to Comstock and received primarily proved properties in return. The transaction was structured as a non-monetary exchange of natural gas properties. The Company made a $2.0 million post-closing adjustment payment for the settlement of revenues and expenses attributable to the exchange properties from the effective date through the closing. The Company did not recognize a gain or loss on the exchange.

The fair value of, and the allocation to, the assets acquired and liabilities assumed is shown in the following table:

Assets:
Proved properties	$	26,449
Unproved properties			541
Total assets acquired			26,990
Liabilities:
Asset retirement obligations			339
Revenue payable			62
Total liabilities assumed			401
Net assets acquired	$	26,589

The results of operations from the Comstock Asset Exchange have been included in the Company’s consolidated statements of operations since the closing date. Transaction costs for legal, engineering, and other due diligence costs are reflected as general and administrative expenses in the Company’s consolidated statements of operations. The Company incurred transaction costs of approximately $90.5 thousand for the year ended December 31, 2020.

15

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(6)Asset Retirement Obligations

The following table presents the activity for the Company’s AROs for the years ended December 31, 2020 and 2019:

	2020				2019
Asset retirement obligations, beginning of period	$	29,093			$	27,976
Exchange of obligations, net			(101	)			—
Additional obligations incurred			441				164
Obligations settled			(235	)			(102	)
Revisions			(210	)			—
Accretion expense			1,008				1,055
Asset retirement obligations, end of period			29,996				29,093
Current portion (included in accounts payable and accrued liabilities)			(300	)			(88	)
Asset retirement obligations, long-term	$	29,696			$	29,005

(7)    Gas Gathering Liabilities

In connection with the Ovintiv Acquisition, the Company became party to three gathering contracts that require delivery of minimum volumes of natural gas at fixed rates for each contract period. These gathering contracts require settlement payments for any shortfalls in the gathered volumes. The Company recorded the estimated fair value of liabilities for the expected volume shortfalls over the remaining contract periods based on the expected annual production in its acquisition date reserve report. The Company recognizes accretion expense for the impact of increasing the discounted liability to its estimated settlement value. The Company accrues gas gathering liabilities for any shortfall between actual produced natural gas volumes and committed natural gas volumes. The difference, if any, between the estimated payments recognized at acquisition and actual current contract period payments required is recorded as a volumetric adjustment to gathering and transportation expense. During the year ended December 31, 2020, the Company recorded a volumetric adjustment to its gas gathering liability as a result of excess natural gas deliveries recognized at the end of the volume commitment term.

The following table presents the activity for the Company’s gas gathering liabilities for the years ended December 31, 2020 and 2019:

	2020				2019
Gas gathering liabilities, beginning of period	$	18,544			$	46,349
Accretion expense			569				2,479
Volumetric adjustment to gas gathering liability			(12,390	)			(76	)
Cash shortfall payments			(6,723	)			(30,208	)
Gas gathering liabilities, end of period	$		—		$	18,544

(8)    Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk. Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future natural gas production. The Company does not enter into derivative contracts for speculative trading purposes. The Company did not post collateral under any of its derivative contracts.

The Company considers the creditworthiness of its counterparties and assesses the impact on the fair value of its derivative instruments as a result of non-performance. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of

16

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

operations for the period in which the change occurs. The Company has not designated any of its derivative instruments as hedges for accounting purposes.

The Company's natural gas derivative positions at any point in time may consist of swaps, collars, call, and put options. Under a swap, the Company receives a fixed price for its natural gas production and pays a variable market price to the counterparty. Options are used to establish a floor price (put), a ceiling price (call) or a floor and a ceiling price (collar) for expected future production. Under a collar, the Company will pay the counterparty if the settlement price is above the ceiling price and the counterparty will pay the Company if the settlement price is below the floor price. Under a three-way collar, the Company will pay the counterparty if the settlement price is above the ceiling price, the counterparty will pay the Company the full floor price if the settlement price is between the floor purchase price and floor sold price, and the counterparty will pay the Company the difference between the floor purchase price and the floor sold price if the settlement price is below the floor sold price. From time to time, the Company may sell future call options, the premiums from which are used to obtain higher strike prices on swap and collar contracts.

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the consolidated balance sheet as of December 31, 2020:

As of December 31, 2020	Gross amount				Netting adjustment				Net amount presented in balance sheets
Assets
Current derivative assets	$	27,503			$		(17,497	)	$	10,006
Long-term derivative assets	—				—				—
Total derivative assets	$	27,503			$		(17,497	)	$	10,006
Liabilities
Current derivative liabilities	$		(17,497	)	$	17,497			$		—
Long-term derivative liabilities			(1,309	)	—						(1,309	)
Total derivative liabilities	$		(18,806	)	$	17,497			$		(1,309	)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the consolidated balance sheet as of December 31, 2019:

As of December 31, 2019	Gross amount				Netting adjustment				Net amount presented in balance sheets
Assets
Current derivative assets	$	45,370			$		(2,642	)	$	42,728
Long-term derivative assets			3,349				(549	)	2,800
Total derivative assets	$	48,719			$		(3,191	)	$	45,528
Liabilities
Current derivative liabilities	$		(2,642	)	$	2,642			$		—
Long-term derivative liabilities			(1,127	)			549				(578	)
Total derivative liabilities	$		(3,769	)	$	3,191			$		(578	)

17

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's consolidated statement of operations for the year ended December 31, 2020:

Derivatives not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Amount of gain or (loss) recognized in income on derivative contracts
Realized gain on commodity contracts	Other income (expense) – Gain (loss) on derivatives, net	$	60,878
Unrealized loss on commodity contracts	Other income (expense) – Gain (loss) on derivatives, net			(36,253	)
Total net gain on derivative contracts	Other income (expense) – Gain (loss) on derivatives, net	$	24,625

The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's consolidated statement of operations for the year ended December 31, 2019:

Derivatives not designated as hedging contracts under ASC 815	Location of gain or (loss) recognized in income on derivative contracts	Amount of gain or (loss) recognized in income on derivative contracts
Realized gain on commodity contracts	Other income (expense) – Gain (loss) on derivatives, net	$	31,033
Unrealized gain on commodity contracts	Other income (expense) – Gain (loss) on derivatives, net			44,400
Total net gain on derivative contracts	Other income (expense) – Gain (loss) on derivatives, net	$	75,433

18

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

At December 31, 2020, the Company had the following open natural gas derivative contracts:

Contract Description	Production Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
Swaps	January 2021 - March 2021		200,000	$	2.97
Swaps	April 2021 - December 2021		50,000	$	2.54
Natural Gas Three-way Collars:
Ceiling sold price (call)	January 2021 - March 2021		170,000	$	3.26
Floor purchase price (put)	January 2021 - March 2021		170,000	$	2.89
Floor sold price (put)	January 2021 - March 2021		170,000	$	2.13
Ceiling sold price (call)	April 2021 - December 2021		170,000	$	2.89
Floor purchase price (put)	April 2021 - December 2021		170,000	$	2.64
Floor sold price (put)	April 2021 - December 2021		170,000	$	2.13
Natural Gas Call Options:
Calls sold	2021		20,000	$	3.15
Calls sold	2022		20,000	$	3.15

See Note 9 –Fair Value Measurements for additional information.

(9)    Fair Value Measurements

Recurring Fair Value Measurements

The following tables set forth by level within the fair value hierarchy the Company's financial assets and liabilities that were accounted for at fair value as of December 31, 2020 and 2019.

	December 31, 2020
	Level 1		Level 2				Level 3		Total
Assets
Natural gas derivative contracts	$	—	$	10,006			$	—	$	10,006
Liabilities
Natural gas derivative contracts	$	—	$		(1,309	)	$	—	$		(1,309	)

	December 31, 2019
	Level 1		Level 2				Level 3		Total
Assets
Natural gas derivative contracts	$	—	$	45,528			$	—	$	45,528
Liabilities
Natural gas derivative contracts	$	—	$		(578	)	$	—	$		(578	)

Derivative contracts listed above as Level 2 include swaps, collars, call, and put options that are carried at fair value. The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas forward curves and implied volatility factors related to changes in the forward curves. The determination of the fair values presented above also incorporates a credit

19

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

adjustment for non-performance risk of the Company and its counterparties. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative transactions while non-performance risk of the Company is evaluated using the credit spread on the Company’s Revolving Credit Facility.

As of December 31, 2020 and 2019, the Company's derivative contracts were with major financial institutions and commodity traders with investment grade credit ratings which are believed to have a minimal credit risk. See Note 8 – Derivative Instruments and Hedging Activities for additional information.

Nonrecurring Fair Value Measurements

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using the income and market valuation techniques based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired natural gas properties include estimates of: (i) reserve quantities; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. See Note 5 – Comstock Asset Exchange for additional information.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future abandonment costs associated with natural gas properties. Significant Level 3 inputs used in the calculation of ARO include plugging and abandonment costs and reserve lives. See Note 6 – Asset Retirement Obligations for additional information.

The Company reviews its proved natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows of its proved natural gas properties to their carrying value. Significant Level 3 inputs used in the calculation of future cash flows for the impairment analysis include estimates of reserve quantities, future commodity prices, future production estimates, estimated future capital expenditures, and risk adjusted discount rates.

Other Financial Instruments

The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the Company’s Revolving Credit Facility approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.

(10)    Long-Term Debt

On November 19, 2015, the Company entered into a senior secured revolving credit facility (as amended and restated, the “Revolving Credit Facility”) with JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto to finance the development of natural gas properties and provide working capital to the Company. The Revolving Credit Facility provides for a maximum credit facility of $500.0 million, a $15.0 million sublimit for swingline loans, and $40.0 million sublimit for letters of credit. The borrowing base in effect at December 31, 2020 and 2019 was $245.0 million and $290.0 million, respectively. As of December 31, 2020, the Company had borrowings of $226.0 million and letters of credit of $1.7 million outstanding under the Revolving Credit Facility. The Company had borrowings of $255.0 million and no letters of credit as of December 31, 2019. The Company incurred $0.2 million of debt issuance costs in connection with borrowing base redeterminations in the years ended December 31, 2020 and 2019.

20

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

The Revolving Credit Facility matures on August 10, 2022. The borrowing base is redetermined semi-annually in the spring and fall, with the lenders and the Company each having the right to two interim unscheduled redeterminations during any twelve-month period. The borrowing base takes into account the value of the Company's natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The borrowing base is subject to a reduction, in most cases, equal to the product of 0.25 multiplied by the stated principal amount (without regard to any initial issue discount) of any future notes or other long-term debt securities that the Company may issue. Funds advanced under the Revolving Credit Facility may be paid down and re-borrowed during the term of the facility. The obligations under the Revolving Credit Facility are secured by perfected real property mortgages on the natural gas reserves of the Company and its restricted subsidiaries.

Interest on borrowings is calculated using the ABR plus applicable margin or the LIBOR rate plus applicable margin. The ABR is defined as the rate per annum equal to the highest of (a) the federal funds rate in effect plus 0.50%, (b) the prime rate in effect, and (c) the LIBOR rate for a one-month interest period plus 1.00%. The applicable margin ranges from 2.00% to 3.00% for ABR loans and from 3.00% to 4.00% for LIBOR loans depending on the borrowing base utilization percentage. At December 31, 2020, the applicable margin was 3.00% for ABR loans and 4.00% for LIBOR loans. The weighted average interest rate on loan amounts outstanding during the years ended December 31, 2020 and 2019 was 5.19% and 5.10%, respectively. In addition to interest, the lenders receive a commitment fee on the unused commitments equal to an annual rate of 0.50%.

The Revolving Credit Facility requires the Company to maintain the following two financial covenants:

–A ratio of consolidated total debt to EBITDAX (as defined in the credit agreement) of no greater than 3.00 to 1.00 as of the last day of any fiscal quarter for the four fiscal quarters ending on such date; and

–a current ratio, which is the ratio of consolidated current assets (including availability under the Revolving Credit Facility) to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

At December 31, 2020, the Company was in compliance with the financial covenants described above and expects to be in compliance with the financial covenants in the Revolving Credit Facility for the next twelve months.

The Revolving Credit Facility also places restrictions on the Company and its restricted subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions, maximum cash balances, and other matters.

(11)    Equity

Series B Preferred Units

In 2015, the Company issued 650,000 Preferred Units and 27,778 Class B Common Units to GSO GEPH in exchange for cash contributions of $650.0 million to finance a portion of the Ovintiv Acquisition. In 2016, the Company issued an additional 21,700 Preferred Units and 929 Class B Common Units to GSO EPB for $21.7 million in cash contributions for general corporate purposes. In 2017, the Company issued 28,300 Preferred Units and 1,211 Class B Common Units to BXC for $28.3 million in cash contributions to finance a portion of the Sabine Acquisition. The proceeds from each issuance, net of equity issuance costs, were allocated to Preferred Units and Class B Common Units based on their respective fair values.

At November 9, 2018, the Base Preferred Return Amount in respect of the 700,000 issued and outstanding Preferred Units was calculated at $1,038.2 million. The Company issued 133,333.33 Class B Common Units in exchange for $100.0 million of the Base Preferred Return Amount. The remaining Base Preferred Return Amount of $938.2 million was converted into 938,158.88 Series B Preferred Units at a conversion price of $1,000 per unit.

On July 9, 2019, BXC converted $50.0 million of the Base Preferred Return Amount in respect of the Series B Preferred Units into 66,666.67 Class B Common Units. The number of Series B Preferred Units outstanding was reduced by 47,345.08 in connection with the transaction.

21

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

The Company has classified the Series B Preferred Units as mezzanine equity based upon the terms and conditions of the units, which include various contingent redemption features described below. Holders of the Series B Preferred Units are entitled to receive quarterly cash distributions in an amount equal to 6.0% per annum. The Company has the option to accrue distributions on the Series B Preferred Units during the first eight fiscal quarters following November 9, 2018 (“Toggle Period”). Any distributions not paid in cash will accrue at 6.0% per annum, compounded quarterly. The distribution rate will increase if, after the Toggle Period, quarterly distributions required to be paid in cash are not paid timely. The Company accrues distributions to recognize changes in the Base Preferred Return Amount on the Series B Preferred Units each reporting period as this is an unconditional obligation of the Company. The Company recognized $120.8 million of distributions attributable to the Series B Preferred Units in the year ended December 31, 2020, of which $14.9 million was paid in cash and $105.9 million was accrued. The Company recognized $113.1 million of accrued distributions attributable to the Series B Preferred Units in the year ended December 31, 2019.

The Series B Preferred Units have liquidation preference over the Common Units in the event of dissolution of the Company in an amount equal to the Base Preferred Return Amount. The Base Preferred Return Amount is defined as an amount of cash in respect of each Series B Preferred Unit equal to an amount such that the internal rate of return with respect to each Series B Preferred Unit is equal to 10.0% for the first twelve months following November 9, 2018 and 12.0% thereafter. The Company may, from time to time, redeem all or a portion of the Series B Preferred Units by paying BXC an amount of cash equal to the Base Preferred Return Amount with respect to each Series B Preferred Unit redeemed. At any time after November 9, 2026 or upon a Change of Control, BXC shall have the option to cause the Company to redeem all of the issued and outstanding Series B Preferred Units for an amount of cash equal to the Base Preferred Return Amount.

The Company had 890,813.80 Series B Preferred Units issued and outstanding as of December 31, 2020 and 2019.

Common Units

In 2015, the Company issued 250,000.00 Class A Common Units to Haynesville LP at a purchase price of $1,000 per unit for $250.0 million of cash consideration to finance a portion of the Ovintiv Acquisition. In 2016, the Company issued 50,000.00 Class A Common Units to Haynesville LP at a purchase price of $1,000 per unit for $50.0 million of cash consideration for general corporate purposes. In 2017, the Company issued 25,000.00 Class A Common Units to Haynesville LP at a purchase price of $1,000 per unit for $25.0 million of cash consideration to finance a portion of the Sabine Acquisition.

The Company issued Class B Common Units during the years ended December 31, 2015 to 2017 in connection with the issuance of Preferred Units as described above. Based on the Company’s operating agreement, the Class A and Class B Common Units have similar economic attributes. Thus, the Company estimated the fair value of the Class B Common Units issued in 2015 to 2017 in connection with the Preferred Units at $1,000 per unit.

In 2018, the Company entered into the Amended and Restated Securities Purchase Agreement. Pursuant to the terms of the agreement, the Company issued 177,777.78 Class A Common Units to Haynesville LP at a purchase price of $750 per unit for $133.3 million of cash. Additionally, the Company issued 133,333.33 Class B Common Units to BXC at a conversion price of $750 per unit in exchange for $100.0 million of the Base Preferred Return Amount on the Preferred Units. The Company used the proceeds from the common equity issuance to repay $130.0 million of outstanding borrowings on the Revolving Credit Facility and for transaction fees and expenses.

On July 9, 2019, the Company issued 88,888.89 Class A Common Units to Haynesville LP at a purchase price of $750 per unit for $66.7 million of cash. Additionally, the Company issued 66,666.67 Class B Common Units to BXC at a conversion price of $750 per unit in exchange for $50.0 million of the Base Preferred Return Amount in respect of the Series B Preferred Units. The Company utilized the proceeds from the common equity issuance to repay $40.0 million of outstanding borrowings on the Revolving Credit Facility and for general corporate purposes.

22

GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

Haynesville LP has the right to appoint four directors to the Board of Directors and BXC has the right to appoint two directors to the Board of Directors. BXC has specific approval rights with respect to, among other things, the Company’s incurrence of indebtedness, consummation of a Change of Control, asset acquisitions, asset dispositions, annual budgets, dissolution of the Company, amendments to the Company’s organization documents, affiliate contracts, issuance of equity securities, payment of distributions, and changes to nature of the Company’s business.

The Company had 591,666.67 Class A Common Units and 229,918.00 Class B Common Units issued and outstanding representing 72.02% and 27.98% of the Common Units of the Company as of December 31, 2020 and 2019, respectively.

(12)Equity-Based Compensation

On August 24, 2015, the Company established an Incentive Unit Award Plan (the “Plan”) to provide economic incentives to (i) certain persons providing services to the Company pursuant to the Management Services Agreement (the “MSA”) by and between GeoSouthern Energy Corporation (“GeoSouthern”) and the Company and (ii) other officers, non-employees and individual service providers of the Company. See Note 15 – Transactions with Affiliates and Related Parties for additional information. The total number of Incentive Units that may be granted under the Plan is 1,000 units. The Incentive Units are subject to service vesting conditions and vest only to the extent a person issued such Incentive Units (a “Participant”) continues to provide services to or remain employed by the Company through the applicable vesting periods. The Incentive Units are divided into two tranches including “Time Vesting Units” and “Exit Vesting Units” representing 60% and 40% of the granted units, respectively. The Time Vesting Units are subject to graded vesting over four years or are accelerated upon a Change of Control or sale of the Company (an “Exit Event”), and the Exit Vesting Units become vested in full upon the earlier of an Exit Event or November 12, 2022. In case of termination for any reason other than for cause, a Participant’s cliff vested units remain outstanding and eligible for distributions, subject to a repurchase option by the Company at a price equal to fair market value, while his or her unvested Incentive Units are forfeited for no consideration.

The Company granted 1,000 Incentive Units on June 1, 2017. The vesting schedule for the Time Vesting Units was adjusted such that 50% of the Time Vesting Units were vested at the grant date, and the remaining 50% of the Time Vesting Units are subject to graded vesting over two years in accordance with the Plan. The Time Vesting Units were fully vested as of May 1, 2019. There were no forfeitures of Incentive Units during the years ended December 31, 2020 and 2019.

The Incentive Units are deemed to be a substantive class of equity and are accounted for as share-based compensation in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. The Incentive Units granted to non-employees are accounted for in accordance with ASC 505-50, Equity Based Payment to Non-Employees, and were subject to remeasurement at fair value each reporting period. On January 1, 2018, the Company adopted ASU 2018-07 Compensation – Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting, which supersedes ASC 505-50. With the adoption of this standard, the Company will no longer have a remeasurement each reporting period.

The Company used the Black Scholes option pricing method to estimate the fair value of the Incentive Units. The risk-free rate was based on the U.S. Treasury yield curve in effect commensurate with the Incentive Units’ estimated time horizon. Expected volatilities are based on historical equity volatilities of comparable companies in the oil and natural gas industry.

The Company did not recognize equity-based compensation expense in the year ended December 31, 2020. The Company recognized $0.7 million related to the Incentive Units in the year ended December 31, 2019, which is presented within general and administrative expenses in the consolidated statements of operations.

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

(13)    Commitments and Contingencies

	Firm transportation (a)			Drilling rigs (b)			Vehicles and equipment (c)			Total
2021	$	11,863		$	4,679		$	777		$	17,319
2022			11,863			—			491			12,354
2023			11,863			—			179			12,042
2024			11,863			—			—			11,863
2025			11,274			—			—			11,274
Thereafter			9,437			—			—			9,437
Total	$	68,163		$	4,679		$	1,447		$	74,289

The values in the table above represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest, as applicable.

(a)Firm Transportation

In 2017, the Company entered into a firm transportation agreement with a downstream pipeline in order to facilitate the delivery of its natural gas production to market. This contract commits the Company to transport a minimum daily natural gas volume of 150,000 dekatherms per day for a period of time and then 300,000 dekatherms per day for another period of time at a negotiated rate or pay for any deficiencies at a specified reservation fee rate. In 2018, the Company entered into a firm transportation agreement with a downstream pipeline that commits the Company to transport a minimum daily natural gas volume of 200,000 dekatherms per day for a period of time. In 2019, the Company entered into a precedent agreement with a downstream pipeline pursuant to which the Company will enter into a firm transportation agreement to transport a minimum daily natural gas volume of 100,000 dekatherms per day for a period of time if certain terms and conditions are met.

(b)Drilling Rigs

The Company has contracted two drilling rigs for the drilling of four wells each.

(c)Vehicles and Equipment

The Company leases vehicles to support its field operations in North Louisiana. The Company entered into a master service agreement with a provider of wellsite equipment requiring a minimum service period.

Other

The Company is party to natural gas delivery contracts with a five-year delivery period that commenced during the fourth quarter of 2020. Under the terms of the agreements, the Company is obligated to deliver 100,000 MMBtu per day and receives a market-based contract price. The Company may purchase third-party volumes to satisfy its commitment under the delivery contracts.

During the first quarter of 2020, the Company entered into a natural gas supply agreement pursuant to which the Company is obligated to sell 50,000 MMBtu per day and receives a market-based contract price for a five-year term commencing between November 1, 2021 and November 1, 2022 if certain terms and conditions are met.

The Company is required to provide security to Ovintiv in order to cover any losses actually incurred by Ovintiv due to the Company failing to satisfy its plugging and abandonment obligations. The Company posted a $27.0 million

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

surety bond in favor of Ovintiv on November 9, 2015. In connection with the Vine Asset Exchange, the Company reduced its security requirement with Ovintiv from $27.0 million to $14.8 million and assumed a security requirement with Shell Gulf of Mexico, Inc. for $12.5 million. The Company further reduced its security requirement with Ovintiv to $14.4 million in connection with the Comstock Asset Exchange. Lastly, the Company has $1.9 million of surety bonds with federal, state, and local government agencies. The Company was in compliance with its security obligations as of December 31, 2020.

(14)    Well Control Incident

On August 30, 2019, the Company experienced a well control incident on the GEP ETAL 9-16 HC-2 ALT Haynesville Shale well in Red River Parish, Louisiana. The subject well is operated by the Company and is located on a pad site with three additional wellbores. The initial incident resulted in the uncontrolled flow of natural gas from all four wells on the location. On October 8, 2019, the Company successfully completed intervention procedures on the final well on the pad to arrest the flow of natural gas. In December 2019, all four wells were returned to production.

There were no injuries and limited environmental impact stemming from the well control event. The Company worked in close coordination with all appropriate state and local stakeholders to ensure the situation was addressed in a safe and environmentally compliant manner.

The Company incurred total gross costs of approximately $30.9 million related to the well control incident as of December 31, 2020. The Company carries insurance to protect against potential financial losses. The Company’s control of well insurance coverage applies to gross covered costs up to a level of $50.0 million, less a deductible of $1.0 million. Based on the Company’s approximately 78% working interest in the subject well, the Company estimates its potential net insurance coverage at $38.9 million, less a deductible of $0.8 million. The Company recognized a receivable of $2.1 million, net of deductible, for insurance recoveries within accounts receivable – other on its consolidated balance sheet as of December 31, 2020 for the costs associated with the well control incident as these expenses are considered an insurable loss. The Company collected $22.2 million of well control insurance reimbursement as of December 31, 2020. Recognition of the insurance recovery receivable is netted against incurred expenses with no gain recognized on the consolidated statements of operations.

(15)    Transactions with Affiliates and Related Parties

The majority equity owner of GeoSouthern holds an equity interest in Haynesville LP. GeoSouthern provides certain management and general and administrative support services to the Company in accordance with the terms of the MSA effective as of November 12, 2015. In consideration for such services, GeoSouthern is entitled to receive reimbursement of its actual general, administrative, and supervision costs; office expenses; salaries, wages, and benefits of GeoSouthern’s officers, directors, and employees; and other overhead expenses of a similar nature in the form of a management fee. GeoSouthern’s management fee is capped at the lesser of allocated actual costs and the MSA budget amount plus tolerance as approved by the Company’s Board of Directors annually. For the years ended December 31, 2020 and 2019, the Company incurred $16.1 million and $16.2 million, respectively, for management fees and $1.0 million and ($0.6) million, respectively, for other amounts. The management fees are classified as general and administrative expenses in the consolidated statements of operations. These expenses may not fully reflect the expenses that would have been incurred by the Company had such services been provided by an unaffiliated company during the periods presented.

(16)    Subsequent Events

On January 28, 2021, the Company entered into an amendment to the purchase and sale agreement with Ovintiv and Pavillion to amend certain provisions of the purchase agreement and modify the security requirements for any successor in interest to the Company. Concurrently, the Company terminated the gas purchase and marketing

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GEP HAYNESVILLE, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2020 and 2019 and for the Years Ended December 31, 2020 and 2019

agreement and netting and set off agreement with Ovintiv. The Company prepaid $5.5 million of marketing costs in connection with the early contract termination.

Subsequent to December 31, 2020, the Company entered into the following natural gas derivative contracts:

Contract Description	Production Period	Volume (MMBtu/d)		Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
Swaps	April 2021 - December 2021		50,000	$	3.03

There are no other subsequent events that require adjustment to or disclosure in the consolidated financial statements, except as listed above.

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Supplemental Information on Natural Gas Exploration and Production Activities (Unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for natural gas acquisition, exploration, and development activities and the related amounts of accumulated depreciation, depletion, and amortization for the years ended December 31, 2020 and 2019 are shown in the table below:

	2020				2019
Proved properties	$	2,146,164			$	1,857,539
Unproved properties			365,090				434,870
Total			2,511,254				2,292,409
Accumulated depreciation, depletion, and amortization			(965,230	)			(664,680	)
Net capitalized costs	$	1,546,024			$	1,627,729

Costs Incurred in Natural Gas Property Acquisition, Exploration, and Development Activities

The costs incurred in the Company’s natural gas acquisition, exploration, and development activities for the years ended December 31, 2020 and 2019 are displayed in the table below and include costs whether capitalized or expensed as well as additions to asset retirement obligations.

	2020			2019
Property acquisition costs:
Proved	$		—	$		—
Unproved			—			—
Development costs			216,942			332,688
Exploration costs			177			865
Total costs incurred	$	217,119		$	333,553

Results of Operations for Natural Gas Producing Activities

The results of operations for natural gas producing activities, which exclude general and administrative expenses and interest expense for the years ended December 31, 2020 and 2019 are presented in the table below:

	2020				2019
Natural gas revenues	$	369,604			$	423,647
Operating expenses
Lease operating			51,841				46,617
Gathering and transportation			94,726				100,336
Production and ad valorem taxes			14,599				14,764
Exploration			193				948
Leasehold impairment	—						10,191
Depreciation, depletion, and amortization			301,227				242,868
Accretion of gas gathering liabilities and asset    retirement obligations			1,577				3,534
Gain on sale of assets			(30	)			(3,099	)
Results of operations	$		(94,529	)	$	7,488

Since the Company is a limited liability company treated as a pass-through entity for federal and state income tax purposes, there is no income tax provision included in the results of operations above.

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Estimated Quantities of Proved Natural Gas Reserves

The Company retained Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, to prepare the estimates of its proved reserves as of December 31, 2020, 2019, and 2018. The Company’s reserves are principally located within the Haynesville and Middle Bossier shale formations in North Louisiana. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. There are numerous uncertainties inherent in estimating quantities of proved natural gas reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Reserve estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available.

Proved reserves are the estimated quantities of natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves are only attributed to undrilled locations if the Company’s development plans indicate such locations are scheduled to be developed within five years from the date it was booked as proved reserves. The Company’s development plans for the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, cash flows from operations, future drilling and completion costs, and other economic factors. A variety of methodologies are used to determine proved reserve estimates. The principal methodologies employed, often in combination, are material balance, performance analysis, volumetric analysis, and analogy.

Proved reserves were estimated using an average of the first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. Benchmark natural gas prices are adjusted for basis differentials, heating value, and other factors affecting the prices the Company receives. Average benchmark and realized natural gas prices at December 31, 2020 and 2019 are shown in the table below:

	2020		2019
Benchmark price ($ per MMBtu)	$	1.985	$	2.578
Realized price ($ per Mcf)	$	1.854	$	2.361

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The following table summarizes changes in the Company’s estimated proved reserves for the years ended December 31, 2020, 2019 and 2018.

	Natural Gas (MMcf)
Proved developed and undeveloped reserves:
Balance, December 31, 2018		1,694,158
Revisions of previous estimates		(318,567	)
Extensions, discoveries, and additions		201,958
Purchases of reserves in place		—
Sales of reserves in place		—
Production		(179,191	)
Balance, December 31, 2019		1,398,358
Revisions of previous estimates		(57,895	)
Extensions, discoveries, and additions		378,080
Purchases of reserves in place		98,296
Sales of reserves in place		(620	)
Production		(202,192	)
Balance, December 31, 2020		1,614,027
Proved developed reserves:
December 31, 2018		555,990
December 31, 2019		487,391
December 31, 2020		602,330
Proved undeveloped reserves:
December 31, 2018		1,138,168
December 31, 2019		910,967
December 31, 2020		1,011,697

Notable changes in proved reserves for the year ended December 31, 2019

Revisions of previous estimates. Proved reserves were revised downward by 318,567 MMcf due to the following:

•Performance of producing wells (decrease of 39,850 MMcf)

•Revisions to proved undeveloped type curves (increase of 19,248 MMcf)

•Changes in year-end prices and production costs (decrease of 78,030 MMcf)

•Development plan revisions (decrease of 222,697 MMcf)

•Other revisions (increase of 2,762 MMcf)

Extensions, discoveries, and additions. Extensions of 174,546 MMcf, discoveries of 24,810 MMcf, and additions of 2,602 MMcf increased proved reserves as a result of ongoing delineation and development drilling in both the Haynesville and Middle Bossier shale formations.

Notable changes in proved reserves for the year ended December 31, 2020

Revisions of previous estimates. Proved reserves were revised downward by 57,895 MMcf due to the following:

•Performance of producing wells (decrease of 16,483 MMcf)

•Revisions to proved undeveloped type curves (increase of 83,487 MMcf)

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•Changes in year-end prices and production costs (decrease of 248,540 MMcf)

•Changes in estimated future development costs (increase of 131,772 MMcf)

•Development plan revisions (decrease of 8,186 MMcf)

•Other revisions (increase of 55 MMcf)

Extensions, discoveries, and additions. Extensions of 244,282 MMcf, discoveries of 132,340 MMcf, and additions of 1,458 MMcf increased proved reserves as a result of ongoing delineation and development drilling in both the Haynesville and Middle Bossier shale formations.

Purchases of reserves in place. The Company acquired 98,296 MMcf of proved reserves in connection with the Comstock Asset Exchange and through organic leasing efforts.

Sales of reserves in place. The Company sold 620 MMcf of proved reserves in connection with the Comstock Asset Exchange.

Proved Undeveloped Reserves

The following table summarizes changes in the Company’s estimated proved undeveloped reserves for the year ended December 31, 2020:

	Natural Gas (MMcf)
Proved undeveloped reserves at December 31, 2019		910,967
Conversions to proved developed		(167,525	)
Revisions of previous estimates		(67,428	)
Extensions, discoveries, and additions		244,282
Purchases of reserves in place		91,401
Sales of reserves in place		—
Proved undeveloped reserves at December 31, 2020		1,011,697

Conversions to proved developed. In 2020 the Company incurred costs of approximately $87.0 million to convert 167,525 MMcf of proved undeveloped reserves to proved developed reserves. The converted reserves equate to approximately 18% of proved undeveloped reserves at December 31, 2019.

Revisions of previous estimates. Proved undeveloped reserves were revised downward by 67,428 MMcf due to the following:

•Revisions to type curves (increase of 83,487 MMcf)

•Development plan revisions (decrease of 8,186 MMcf)

•Changes in year-end prices and production costs (decrease of 270,084 MMcf)

•Changes in estimated future development costs (increase of 131,772 MMcf)

•Other revisions (decrease of 4,417 MMcf)

Extensions, discoveries, and additions. Extensions, discoveries, and additions represent extensions to reserves attributable to undrilled locations scheduled to be developed by 2025 (as that year entered the five-year development window). Extensions of 244,282 MMcf resulted from ongoing delineation and development drilling activity.

During 2020, approximately $96.3 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Estimated future development costs relating to the development of the Company’s proved undeveloped reserves at December 31, 2020 are approximately $761.6 million over the next five years. The Company’s reserve report at December 31, 2020 assigned proved undeveloped reserves to 119 drilling locations

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targeting the Haynesville shale and 7 drilling locations targeting the Middle Bossier shale. All of the Company’s proved undeveloped reserves are scheduled to be developed within five years of initial disclosure.

Standardized Measure of Discounted Future Net Cash Flows

The Company developed the standardized measure of discounted future net cash flows from production of proved reserves by:

1.Estimating quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.

2.Calculating future cash flows by applying the twelve-month average of the first-day-of-the-month prices to the quantities of proved reserves expected to be produced in each future year.

3.Future cash flows are reduced by estimated future production, development, and abandonment costs, all based on year-end economic conditions.

4.The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the SEC and the FASB. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived or costs to be incurred related to its proved reserves, nor their present value. The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the Company’s natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following table presents the Company’s standardized measure of discounted future net cash flows for the years ended December 31, 2020 and 2019:

	2020				2019
Future cash inflows	$	2,992,324			$	3,301,167
Future production costs			(1,261,349	)			(1,269,538	)
Future development costs			(806,451	)			(789,982	)
Future net cash flows			924,524				1,241,647
10% annual discount for estimated timing of cash flows			(406,342	)			(515,967	)
Standardized measure of discounted future net cash flows	$	518,182			$	725,680

The following summarizes the principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2020 and 2019:

	2020				2019
Balance at beginning of period	$	725,680			$	1,299,200
Sales of natural gas, net of production costs			(208,437	)			(261,931	)
Previously estimated development costs incurred			99,772				263,638
Net changes in prices and production costs			(366,175	)			(623,723	)
Changes in estimated future development costs			44,556				(31,665	)
Revisions of previous quantity estimates			29,947				(29,791	)
Extensions, discoveries, and additions			148,816				90,729
Purchases of reserves in place			14,670				—
Sales of reserves in place			(331	)			—
Accretion of discount			34,926				59,077
Changes in timing and other			(5,242	)			(39,854	)
Balance at end of period	$	518,182			$	725,680

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The Company’s calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated future income taxes because the Company is a limited liability company treated as a pass-through entity for federal and state income tax purposes and does not directly pay federal or state income tax.

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