MorningStar Partners (TXO) 8-K/A Eagle Mountain Energy Partners LLC

Exhibit 99.2

EAGLE MOUNTAIN ENERGY PARTNERS LLC

Consolidated Financials Statements

For the Years Ended December 31, 2023 and 2022

	KPMG LLP
	Suite 1400 2323 Ross Avenue
	Dallas, TX 75201-2721

Independent Auditors’ Report

The Members

Eagle Mountain Energy Partners, LLC:

Opinion

We have audited the consolidated financial statements of Eagle Mountain Energy Partners, LLC and its subsidiaries the (Company), which comprise the consolidated balance sheets as of December 31, 2023 and 2022, and the related consolidated statements of income, changes in members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for the years then ended in accordance with U.S. generally accepted accounting principles.

Basis for Opinion

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

Responsibilities of Management for the Consolidated Financial Statements

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

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

Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements

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

In performing an audit in accordance with GAAS, we:

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

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

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

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

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

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

Dallas, Texas

November 13, 2024

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Eagle Mountain Energy Partners LLC

Balance Sheets

(in thousands)	December 31, 2023			December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	1,594		$	7,202
Accounts receivable, net		9,015			7,607
Derivative fair value		1,451			—
Other		818			495
Total Current Assets		12,878			15,304
Property and Equipment, at cost – full-cost method:
Proved properties		183,253			135,088
Other		41			51
Total Property and Equipment		183,294			135,139
Accumulated depreciation, depletion and amortization		(35,503	)		(13,316	)
Net Property and Equipment		147,791			121,823
Other Assets:
Derivative fair value		929			—
Other assets		997			1,308
Total Other Assets		1,926			1,308
TOTAL ASSETS	$	162,595		$	138,435
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities:
Accounts payable	$	11,374		$	9,004
Accrued liabilities		6,344			3,723
Derivative fair value		3,575			7,705
Other current liabilities		166			153
Total Current Liabilities		21,459			20,585
Long-term Debt		48,400			38,800
Other Liabilities:
Asset retirement obligation		7,150			6,299
Derivative fair value		—			4,053
Other liabilities		132			116
Total Other Liabilities		7,282			10,468
Commitments and Contingencies
Members’ Equity:
Members’ equity		85,454			68,582
TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	162,595		$	138,435

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Eagle Mountain Energy Partners LLC

Statements of Income

	Years ended December 31,
(in thousands)	2023			2022
REVENUES
Oil and condensate	$	67,804		$	62,181
Natural gas liquids		3,799			5,025
Natural gas		1,153			2,647
Gain (loss) on derivatives		4,701			(15,345	)
Total Revenues		77,457			54,508
EXPENSES
Production		17,719			16,152
Taxes, transportation and other		6,433			5,916
Depreciation, depletion and amortization		17,906			12,146
Impairment of long-lived assets		4,530			—
Accretion of discount in asset retirement obligation		467			87
General and administrative		(2,016	)		(1,152	)
Total Expenses		45,039			33,149
OPERATING INCOME		32,418			21,359
OTHER INCOME (EXPENSE)
Other income		81			19
Loss on contingent consideration		(369	)		(1,491	)
Interest expense		(4,474	)		(2,351	)
Total Other Expense		(4,762	)		(3,823	)
NET INCOME BEFORE INCOME TAX		27,656			17,536
State income taxes		643			868
NET INCOME	$	27,013		$	16,668

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Eagle Mountain Energy Partners LLC

Statements of Changes in Members’ Equity

	Years ended December 31,
(in thousands)	2023			2022
Beginning balance, January 1	$	68,582		$	51,793
Net income		27,013			16,668
Member contributions		—			121
Member distributions		(10,141	)		—
Ending balance, December 31	$	85,454		$	68,582

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Eagle Mountain Energy Partners LLC

Statements of Cash Flows

	Years ended December 31,
(in thousands)	2023			2022
OPERATING ACTIVITIES
Net income	$	27,013		$	16,668
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,906			12,146
Impairment of long-lived assets		4,530			—
Accretion of discount in asset retirement obligation		467			87
Non-cash derivative (gain) loss		(4,332	)		16,836
Net cash (paid) received for derivatives		(4,031	)		(12,539	)
Amortization of deferred financing fees		339			338
Other non-cash items		30			77
Changes in operating assets and liabilities (a)		419			5,194
Cash Provided by Operating Activities		42,341			38,807
INVESTING ACTIVITIES
Proceeds from sale of property and equipment		2,350			3,313
Proved property acquisitions		(19,423	)		(26,291	)
Development costs		(27,896	)		(7,809	)
Other property and asset additions		(6	)		(8	)
Payments on contingent consideration		(2,200	)		—
Cash Used in Investing Activities		(47,175	)		(30,795	)
FINANCING ACTIVITIES
Proceeds from long-term debt		24,600			21,300
Payments on long-term debt		(15,000	)		(23,500	)
Member contributions		—			121
Debt issuance costs		—			35
Distributions to members		(10,141	)		—
Payments on finance leases		(233	)		(262	)
Cash Used in Financing Activities		(774	)		(2,306	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(5,608	)		5,706
Cash and Cash Equivalents, beginning of period		7,202			1,496
Cash and Cash Equivalents, end of period	$	1,594		$	7,202
(a)  Changes in Operating Assets and Liabilities
Accounts receivable	$	(1,408	)	$	274
Other current assets		(323	)		(297	)
Current liabilities		2,150			5,217
	$	419		$	5,194

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Eagle Mountain Energy Partners LLC

Notes to Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

The accompanying audited financial statements represent Eagle Mountain Energy Partners’ (“EMEP”) approximately 88% share of the EMEP Properties (as defined below). EMEP is a Delaware limited liability company (“LLC”) formed on January 10, 2020, and is engaged in the exploration, development, production and sale of crude oil and natural gas primarily in Montana and North Dakota (“Williston Basin Properties”). Its executive offices are located in Houston, Texas.

As an LLC, the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC and, unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution.

On August 30, 2024, MorningStar Operating LLC completed the acquisition from a wholly-owned subsidiary of EMEP and V4-ELM, LP, a Texas limited partnership (“Vendera” and together with EMEP, the “EMEP Entities”) of producing properties in the Greater Williston Basin of Montana and North Dakota (the “EMEP Properties”) for approximately $241.8 million and 2.5 million common units valued at $50.0 million. The purchase price was allocated primarily to proved properties.

The accompanying consolidated financial statements include the financial statements of EMEP and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

Basis of Presentation

The accounts of EMEP are presented in the accompanying financial statements. These financial statements have been prepared in accordance with U.S. GAAP.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

• estimates of proved reserves and related estimates of the present value of future revenues;

• the recoverability of oil and gas properties;

• contingent consideration arrangements;

• estimates of revenue earned but not yet received;

• asset retirement obligations; and

• legal and environmental risks and exposure.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.

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Concentrations of Credit Risk

Financial instruments that potentially subject EMEP to a concentration of credit risk consist principally of cash, accounts receivable, and derivative financial instruments.

Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss from the other companies. Including the bank that issued the letter of credit, we currently have greater concentrations of credit with several investment-grade (BBB- or better) rated companies.

Our production is sold to various purchasers, based on their credit rating and the location of our production. Sales to four purchasers for the year ended December 31, 2023 and four purchasers for the year ended December 31, 2022, were greater than 10% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.

Customer	2023			2022
Customer A		41	%		48	%
Customer B		17	%		22	%
Customer C		16	%		12	%
Customer D		15	%		10	%

Property and Equipment

EMEP follows the full-cost method of accounting for its oil and natural gas properties. Accordingly, all productive and nonproductive costs directly associated with the acquisition, exploration and development of oil and natural gas properties, including the cost of undeveloped leaseholds, dry holes and leasehold equipment, are capitalized to cost centers for the United States. All costs related to production, general corporate overhead and similar activities are expensed as incurred.

Depreciation, depletion, and amortization (DD&A) of capitalized costs within a cost center are depleted on a composite unit-of-production method based on estimated proved oil and gas reserves. The composite unit-of-production depletion rate is calculated by dividing current period production by estimated proved oil and gas reserves at the beginning of the period then applying such depletion rate to proved property costs, which include estimated asset retirement costs, less accumulated depletion, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. At December 31, 2023 and 2022, all of EMEP’s oil and natural gas revenues come from wells with proven reserve estimates that were prepared by an independent engineering firm.

At the end of each fiscal year, the net oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unproved properties not being amortized, and (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and natural gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and natural gas properties.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar date of each month during the 12-month period prior to the end of the current fiscal year, held flat for the life of the production. Prices do not include the impact of commodity derivative contracts.

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During the year end ended December 31, 2023, EMEP recognized an impairment of long-lived assets of $4.5 million primarily due to a significant increase in future development costs included in the depletable base of proved reserves as well as a decrease in crude oil prices. During the year ended December 31, 2022, EMEP did not recognize an impairment of long-lived assets.

Proceeds from the sale of oil and natural gas properties are accounted for as a reduction of capitalized costs unless such sales involve a significant change between costs and the fair value of proved reserves, in which a gain or loss is recognized. For the years ended December 31, 2023 and 2022, EMEP did not have any such sales of oil and natural gas properties.

Asset Retirement Obligation

If the fair value for asset retirement obligation can be reasonably estimated, the liability is recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. The retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of operations. See Note 4.

Derivatives

EMEP uses derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. EMEP records all derivatives on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. See Note 6.

EMEP has entered into agreements for acquisitions of oil and natural gas properties that include obligations to pay the seller additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration liabilities are required to be bifurcated and accounted for separate as derivative instruments and recognized at their acquisition date fair value in the consolidated balance sheets.

EMEP does not designate these derivative contracts as cash flow hedges. Changes in the fair value of commodity price derivatives, including contingent consideration agreements, are recognized currently in earnings. Realized and unrealized gains and losses on commodity price derivatives are recognized in gain (loss) on derivatives, and on contingent consideration agreements in loss on contingent consideration. Deferred premium obligations associated with commodity price derivatives are recognized as gain (loss) on derivatives. Settlements of derivatives are included in cash flows from operating activities and settlements on contingent consideration agreements are included in cash flows from financing activites up to the acquisition date fair value with any excess classified as cash flows used in investing activities.

Revenue Recognition

Oil, gas and natural gas liquids revenues are recognized upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for the product.

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The transaction price used to recognize revenue is a function of the contract billing terms which are indexed to a market price or an average index price. Performance obligations are considered satisfied upon transfer of control of the commodity. Revenue is recognized in the amount expected to be received once the consideration is adequately estimated (i.e., when market prices are known). Contracts with customers typically require payment within 30 days following invoicing.

The majority of the Company’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosures of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original duration of one year or less.

Fair Value of Financial Instruments

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

Income Taxes

EMEP is organized as an LLC and taxed as a partnership for federal income tax purposes with income tax liabilities and/or benefits of the Partnership passed through to the partners. As such, we are not a taxable entity, we do not directly pay federal income tax and recognition has not been given to federal income taxes for our operations.

State income positions are evaluated in a two-step process. EMEP first determines whether it is more likely than not that a tax position will be sustained upon examination. If a tax position meets the more likely than not threshold, it is then measured to determine the amount of expense to record in the consolidated financial statements. The tax expense recorded would equal the largest amount of expense related to the outcome that is 50% or greater likely to occur.

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Limited partnerships are subject to state income taxes in certain states. Income taxes related to state taxes have been included as a separate line in the statements of operations and no deferred tax amounts were calculated.

Loss Contingencies

When management determines that it is probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Any legal costs related to litigation are expensed as incurred.

Liquidity

Our primary sources of liquidity are cash provided by operating activities, borrowings under our credit facility and equity raised from members. Short-term liquidity needs are provided by borrowings under our credit facility. We believe that we have a sufficient combination of resources and operating flexibility to ensure that we remain in compliance with our future debt covenants for all of our outstanding debt for at least the next 12 months from the date of issuance of these financial statements. See Note 3.

Leases

Under ASC 842, EMEP recognized a right-of-use (“ROU”) asset and lease liability to account for its leases. ROU assets represent EMEP’s right to use an underlying asset for the lease term and lease liabilities represent EMEP’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized on the commencement date based on the present value of lease payments over the lease term. ROU assets are based on the lease liability and are increased by prepaid lease payments and decreased by lease incentives received. Lease incentives are amortized through the lease asset as reductions of expense over the lease term. For leases where EMEP is reasonably certain to exercise a renewal option, such option periods have been included in the determination of EMEP’s ROU assets and lease liabilities.

2. Acquisitions

On March 1, 2023, EMEP completed the acquisition of producing properties in the Williston Basin in Montana from Grayson Mill Williston, LLC and Glacier Peak Midstream, LLC (collectively, “Grayson”) for approximately $19.4 million. The purchase price allocation included $19.9 million to proved properties, $0.1 million to other current liabilities and $0.4 million to asset retirement obligation. The acquisition was funded by cash on hand and borrowings from our credit facility.

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On August 1, 2022, EMEP completed the acquisition of producing properties in the Williston Basin in Montana and North Dakota from Ovintiv USA Inc. (“Ovintiv”) for approximately $27.2 million. The purchase price allocation included $28.2 million to proved properties, $0.8 million as other current assets, $1.0 million to other current liabilities and $0.8 million to asset retirement obligation. The acquisition was funded by cash on hand and borrowings from our credit facility.

Concurrent with closing the Grayson acquisition on March 1, 2023, EMEP sold a portion of the mineral interest acquired to an unrelated party for approximately $2.4 million. The assets sold were allocated based on the relative fair value of the total purchase price, therefore no gain or loss was incurred on this transaction.

Concurrent with closing the Ovintiv acquisition on August 1, 2022, EMEP sold a portion of the mineral interest acquired to an unrelated party for approximately $3.3 million. The assets sold were allocated based on the relative fair value of the total purchase price, therefore no gain or loss was incurred on this transaction.

3. Debt

(in thousands)	December 31, 2023		December 31, 2022
EMEP Credit Facility	$	48,400	$	38,800

On November 1, 2021, EMEP entered into a new four-year, senior secured credit facility which provides up to $250 million of commitments. The facility has a maturity date of November 1, 2025. We use the facility for general corporate purposes. In connection with the credit facility, we incurred financing fees and expenses of approximately $1.4 million as of December 31, 2023 and $1.4 million as of December 31, 2022 before accumulated amortization of $0.8 million as of December 31, 2023 and $0.5 million as of December 31, 2022. These costs are being amortized over the life of the credit facility. Such amortized expenses are recorded as interest expense on the statements of operations.

Redetermination of the borrowing base under the credit facility, is based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually. Significant declines in commodity prices may result in a decrease in the borrowing base. Our obligations under the credit facility are secured by all of EMEP’s crude oil and natural gas properties. We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.25 to 1.0, as defined in the Credit Agreement. EMEP was in compliance with all debt covenants as of December 31, 2023.

At our election, interest on borrowings under the credit facility is determined by reference to either (i) a customary benchmark plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or (ii) a customary benchmark plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the borrowing availability. The weighted average interest rate on credit facility borrowings was 9.0% in 2023 and 8.1% in 2022.

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The borrowing base under the Credit Facility was $75 million as of December 31, 2023, and was $65 million as of December 31, 2022.

4. Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the years ended December 31, 2023 and 2022:

	Year Ended December 31,
(in thousands)	2023		2022
Asset retirement obligation, January 1	$	6,299	$	5,445
Liability incurred upon acquiring and drilling wells		384		767
Accretion of discount expense		467		87
Asset retirement obligation, December 31	$	7,150	$	6,299

5. Fair Value

We use commodity-based and financial derivative contracts to manage exposures to commodity price. We do not hold or issue derivative financial instruments for speculative or trading purposes. We periodically enter into futures contracts to hedge our exposure to price fluctuations on crude oil and natural gas sales (Note 6).

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2023 and 2022. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

	Asset (Liability)
	December 31, 2023						December 31, 2022
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Contingent consideration	$	(2,200	)	$	(2,200	)	$	(4,030	)	$	(4,030	)
Long-term debt	$	(48,400	)	$	(48,400	)	$	(38,800	)	$	(38,800	)
Net derivative asset (liability)	$	1,005		$	1,005		$	(7,728	)	$	(7,728	)

The fair value of our long-term debt approximates the carrying amount because the interest rate is reset periodically at then current market rates (Note 3).

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The fair value of our contingent consideration, net derivative asset (liability) (Note 6) and our long-term debt (Note 3) is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our net derivative asset (liability). As such, an adjustment for counterparty credit risk has been applied to the net derivative asset (liability) to account for the risk of nonperformance by the counterparty.

The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.

	Fair Value Measurements
	December 31, 2023					December 31, 2022
	Significant Other Observable Inputs			Significant Unobservable Inputs		Significant Other Observable Inputs			Significant Unobservable Inputs
(in thousands)	(Level 2)			(Level 3)		(Level 2)			(Level 3)
Contingent consideration	$	(2,200	)	$	—	$	(4,030	)	$	—
Long-term debt	$	(48,400	)	$	—	$	(38,800	)	$	—
Net derivative asset (liability)	$	1,005		$	—	$	(7,728	)	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable and are based upon Level 3 inputs. These assets and liabilities can include assets and liabilities acquired in a business combination, proved and unproved natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired.

Commodity Price Hedging Instruments

We periodically enter into futures contracts and costless price collars to hedge our exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 6.

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The fair value of our derivatives contracts consists of the following:

	Asset Derivatives				Liability Derivatives
	December 31,				December 31,
(in thousands)	2023		2022		2023			2022
Derivatives not designated as hedging instruments:
Commodity instruments	$	2,380	$	—	$	(1,375	)	$	(7,728	)
Contingent consideration	$	—	$	—	$	(2,200	)	$	(4,030	)
Total	$	2,380	$	—	$	(3,575	)	$	(11,758	)

Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated income statements, comprises the following realized and unrealized components:

(in thousands)	2023			2022
Net cash (received from) paid to counterparties	$	4,031		$	12,539
Non-cash change in derivative fair value	$	(8,363	)	$	4,297
Derivative fair value (gain) loss	$	(4,332	)	$	16,836

6. Commodity Sales Commitments

Our policy is to consider hedging a portion of our production at commodity prices the general partner deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, the general partner may enter into hedging agreements because of the benefits of predictable, stable cash flows.

We enter futures contracts and costless price collars to hedge our exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. Costless price collars set a ceiling and floor price to hedge exposure to price fluctuations on crude oil and natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement.

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Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 5.

Production Period	Bbls per Day		Weighted Average NYMEX Price per Bbl
January 2024 – March 2024		1,800	$	71.26
April 2024 – June 2024		1,710	$	72.07
July 2024 – September 2024		1,441	$	70.31
October 2024 – December 2024		1,038	$	72.27
January 2025 – December 2025		657	$	72.62

Net settlement losses on oil futures and sell basis swap contracts decreased oil revenues by $4.2 million in 2023 and $11.0 million in 2022. An unrealized gain in 2023 and an unrealized loss in 2022 to record the fair value of derivative contracts increased oil revenues by $3.7 million in 2023 and decreased oil revenues by $13.3 million in 2022.

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments. See Note 5.

Production Period	MMBtu per Day		Weighted Average NYMEX Price per MMBtu
January 2024 – March 2024		521	$	3.42
April 2024 – June 2024		769	$	2.87
July 2024 – September 2024		748	$	2.95
October 2024 – December 2024		491	$	3.04

Net settlement gain on gas futures increased gas revenues by $0.2 million in 2023 and losses decreased gas revenues by $1.5 million in 2022. An unrealized gain in 2023 and an unrealized loss in 2022 to record the fair value of derivative contracts increased gas revenues by $1.0 million in 2023 and decreased gas revenues by $2.1 million in 2022.

Contingent Consideration

Pursuant to a contingent consideration arrangement we entered into on August 27, 2021, EMEP is required to pay $2.2 million if the average daily settlement price of NYMEX WTI for calendar year 2022 exceeds $65.00 per barrel and an additional $2.2 million if the average daily settlement price of NYMEX WTI for calendar year 2023 exceeds $60.00 per barrel. In accordance with this contingent agreement, EMEP paid $2.2 million in the first quarter of 2023 and has recorded a contingent liability of $2.2 million as of December 31, 2023. Payment of this contingent liability was made in the first quarter of 2024.

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7. Members’ Equity and Incentive Units

Profits and losses will be determined and allocated with respect to each fiscal year as of the end of such fiscal year. Profits and losses will be allocated among the members in a manner such that the adjusted capital account of each member is as nearly as possible, equal (proportionately) to the distributions that would be made to such member if EMEP were dissolved. The members of EMEP have committed to contribute $90.9 million of which $57.5 million was contributed as of December 31, 2023.

The LLC agreement authorizes EMEP to issue incentive units. As of December 31, 2023, 3,000,000 incentive units were authorized, and 2,205,000 units were issued and outstanding. The incentive units are designed as a profits interest, and the incentive unit holders are entitled to an increased share of the distributable cash flow generated by EMEP in the event that certain performance hurdles are met. Given the metrics set forth by the incentive unit plan and the limited history of EMEP as well as the practical scenarios under which similar instruments are typically realized (units typically do not have a value until a major asset liquidation occurs, which cannot be deemed “probable” under GAAP until it has occurred), the realization of these units is not probable at the date of grant. Due to the nature of the incentive units, no compensation expense was recorded during the years ended December 31, 2023 and 2022.

8. Commitments and Contingencies

From time to time, the Company is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company.

To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Commodity Commitments

During 2023 and 2022, we entered into futures contracts that effectively fixed natural gas and crude oil prices. See Note 6.

9. Supplemental Cash Flow Information

Interest payments totaled $4.0 million for in 2023 and $1.7 million in 2022. State income tax payments totaled $0.9 million in 2023 and $0.0 million in 2022.

10. Subsequent Events

We have evaluated subsequent events through November 13, 2024, the date the financial statements were available to be issued.

On February 8, 2024, EMEP’s borrowing base was reaffirmed and remained at $75 million.

In February 2024, EMEP entered into new commodity derivative contracts, including NYMEX WTI price swaps and costless price collars.

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