EX-99.3

EX-99.3 13 d319755dex993.htm EX-99.3 EX-99.3

Exhibit 99.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Kimmeridge Mineral Fund, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Kimmeridge Mineral Fund, LP and subsidiaries (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to those charged with governance and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Estimated proved oil and natural gas reserves used in the depletion of evaluated oil and natural gas properties

As discussed in Note 2 to the consolidated financial statements, the Partnership uses the successful efforts method of accounting for its oil and natural gas producing properties and depletes capitalized costs using the unit-of-production basis over total proved oil and natural gas reserves. The Partnership had $1,147.1 million of net oil and natural gas properties as of December 31, 2021, and recorded depletion expense of proved oil

and natural gas properties of $40.3 million for the year ended December 31, 2021. The Partnership engages independent petroleum engineers to prepare the estimates of proved oil and natural gas reserves.

We identified the assessment of the estimated proved oil and natural gas reserves used in the depletion of proved oil and natural gas properties as a critical audit matter. A high degree of subjective auditor judgement was required in evaluating the estimate of proved oil and natural gas reserves, as auditor judgment was required to evaluate the assumptions used by the Partnership related to forecasted production and oil and natural gas prices, inclusive of price differentials.

The following are the primary procedures we performed to address this critical audit matter. We evaluated (1) the professional qualifications of the lead internal petroleum engineer as well as the engineer assigned to the Partnership by the independent petroleum engineering firm engaged by the Partnership, (2) the knowledge, skills, and ability of the lead internal petroleum engineer, the engineer assigned to the Partnership by the independent petroleum engineering firm, as well as the independent petroleum engineering firm engaged by the Partnership, and (3) the relationship of the independent petroleum engineering firm and the engineer assigned to the Partnership. We assessed the method used by the Partnership’s independent petroleum engineers to estimate the proved oil and natural gas reserves for consistency with industry and regulatory standards. We compared the Partnership’s historical production forecasts to actual production volumes to assess the Partnership’s ability to accurately forecast and we compared the future forecasted production used by the Partnership in the current period to historical production. We evaluated the oil and natural gas prices used by the Partnership’s independent petroleum engineers by comparing them to publicly available prices and tested the relevant price differentials by comparing them to historical differentials. We read and considered the findings of the independent petroleum engineers engaged by the Partnership in connection with our evaluation of the Partnership’s reserve estimates. We analyzed the depletion expense calculation for compliance with regulatory standards, and checked the accuracy of the depletion expense calculation.

Accrued revenue

As discussed in Note 3 to the consolidated financial statements, the Partnership recognizes oil, natural gas and NGL revenues from its mineral and royalty interests when control of the product is transferred to the customer and the performance obligations under the terms of the contracts with customers are satisfied. As a mineral and royalty interest owner, the Partnership has limited visibility into the timing of when new wells start producing as production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within accrued revenue and accounts receivable, net. The difference between the Partnership’s estimates of mineral and royalty income and the actual amounts received for oil, natural gas and NGL sales are recorded in the month that the mineral and royalty payment is received from the customer. At December 31, 2021, the Partnership had accrued revenue and accounts receivable, net of $36.2 million, a portion of which related to accrued revenue.

We identified the assessment of accrued revenue as a critical audit matter. A high degree of subjective auditor judgment was required to evaluate the estimated volume of production delivered to the related customers, as well as the price that will be received for the sale of the oil, natural gas, and NGLs produced.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design of certain internal controls related to the Partnership’s oil, natural gas and NGL revenue accrual process, including controls related to the development of the estimates of delivered production volumes and the price that will be received for the sale of such volumes. We compared the Partnership’s historical revenue accruals to actual cash collections to assess the Partnership’s ability to accurately estimate. We independently developed an expectation of accrued revenue and compared such expectation to the amounts recorded by the Partnership. For a selection of transactions where third-party evidence was available, we compared management’s estimate of accrued revenue related to delivered production to third-party

evidence. We evaluated the prices used by the Partnership to estimate the price to be received for the sale of the oil, natural gas, and NGLs produced by independently developing an expectation of price using publicly available market prices and historical differentials.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2020.

Denver, Colorado

March 22, 2022

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED BALANCE SHEETS

(In thousands)


	December 31,
	2021			2020
ASSETS
Current assets
Cash and cash equivalents	$	12,379		$	7,531
Accrued revenue and accounts receivable, net		36,202			8,505
Other current assets		235			138

Total current assets		48,816			16,174

Property and equipment
Oil and natural gas properties, successful efforts method:
Unproved properties		817,873			399,229
Proved properties		447,369			254,854
Other property and equipment		8,187			7,990
Accumulated depreciation, depletion and amortization		(121,536	)		(80,630	)

Net oil and gas properties and other property and equipment		1,151,893			581,443

Other long-term assets
Deferred financing costs		2,145			1,011

Total long-term assets		2,145			1,011

TOTAL ASSETS	$	1,202,854		$	598,628

LIABILITIES AND EQUITY
Current liabilities
Accrued expenses and other liabilities	$	4,140		$	2,035
Due to affiliates		442			55

Total current liabilities		4,582			2,090

Long-term debt		134,000			33,500
Deferred rent		1,129			641
Total liabilities		139,711			36,231

COMMITMENTS AND CONTINGENCIES (NOTE 10)
Equity
Partners’ capital		560,622			562,397

Noncontrolling interests		502,521			—

Total equity		1,063,143			562,397

TOTAL LIABILITIES AND EQUITY	$	1,202,854		$	598,628

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

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2021			2020			2019
	(In thousands)
Revenue:
Oil, natural gas and natural gas liquids revenues	$	118,548		$	44,194		$	50,886
Lease bonus and other income		2,040			1,505			5,319
Water sales		—			—			3,475
Commodity derivatives losses		—			(2,573	)		—

Total revenue		120,588			43,126			59,680

Operating Expenses:
Management fees to affiliates		7,480			7,480			7,480
Depreciation, depletion and amortization		40,906			32,049			26,201
General and administrative		4,143			4,981			2,349
General and administrative – affiliates		8,855			4,407			8,167
Severance taxes, ad valorem taxes and operating expense		6,858			3,151			5,249
Impairment of oil and natural gas properties		—			812			—
Deferred offering costs write off		2,396			2,747			—
Bad debt expense (recovered)		—			(251	)		405
Gain on sale of property		—			(42	)		—

Total operating expenses		70,638			55,334			49,851

Net income (loss) from operations		49,950			(12,208	)		9,829
Other income (expense):
Interest income (expense)		(1,893	)		(1,968	)		(868	)

Net income (loss) before income tax expense		48,057			(14,176	)		8,961
Income tax expense		(562	)		(38	)		(171	)

Net income (loss) including noncontrolling interests		47,495		$	(14,214	)	$	8,790

Net income attributable to noncontrolling interests		18,781			—			—

Net income (loss) attributable to partners	$	28,714		$	(14,214	)	$	8,790

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

KIMMERIDGE MINERAL FUND, LP

STATEMENTS OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2021, 2020 AND 2019


	General Partners			Limited Partners			Noncontrolling interests			Total Equity
				(In thousands)
Equity at January 1, 2019	$	4,623		$	385,458			—		$	390,081

Capital contributions		2,388			162,352			—			164,740
Net income		235			8,555			—			8,790
Equity at December 31, 2019	$	7,246		$	556,365			—		$	563,611

Capital contributions		166			12,834			—			13,000
Net loss		(86	)		(14,128	)		—			(14,214	)

Equity at December 31, 2020	$	7,326		$	555,071			—		$	562,397

Capital contributions		78			7,922			—			8,000
Capital distributions		(862	)		(66,638	)		(60,882	)		(128,382	)

Issuance of equity in consolidated subsidiary		849			65,621			507,163			573,633

Deemed distribution in connection with common control acquisition		(478	)		(36,981	)		37,459			—
Net income		462			28,252			18,781			47,495

Equity at December 31, 2021	$	7,375		$	553,247			502,521		$	1,063,143

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

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED STATEMENTS OF CASH FLOW


	Year ended December 31,
	2021			2020			2019
	(In thousands)
Cash flows from operating activities
Net income (loss)	$	47,495		$	(14,214	)	$	8,790
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		40,906			32,049			26,201
Impairment of oil and natural gas properties		—			812			—
Deferred offering costs write off		2,396			2,747			—
Loss on extinguishment of debt		—			—			308
Bad debt expense (recovered)		—			(251	)		405
Gain on sale of property		—			(42	)		—
Change in operating assets and liabilities:
Accounts receivable		(27,697	)		4,436			(1,340	)
Due from affiliates		—			—			610
Other current assets		(97	)		14			(60	)
Other long-term assets		440			256			53
Accrued expenses and other liabilities		1,673			(328	)		(121	)
Due to affiliates		325			(51	)		(107	)
Deferred rent		488			588			52

Net cash provided by operating activities		65,929			26,016			34,791

Cash flows from investing activities
Purchases of oil and gas properties		(38,470	)		(35,543	)		(266,538	)
Proceeds from sale of oil and gas properties		(137	)		14,069			22,019
Purchases of other property and equipment		(136	)		(293	)		(1,041	)
Proceeds from sale of other property and equipment		—			210			—
Escrow deposits		—			—			(3,067	)

Net cash used in investing activities		(38,743	)		(21,557	)		(248,627	)

Cash flows from financing activities
Capital contributions		8,000			13,000			164,740
Issuance of equity in consolidated subsidiary		1,467			—			—
Distributions to Partners		(67,500	)		—			—
Distributions to noncontrolling interests		(60,882	)		—			—
Borrowings on credit facility		147,000			10,000			60,000
Repayments on credit facility, net		(46,500	)		(36,500	)		—
Payments of deferred financing costs		(1,588	)		(316	)		(1,284	)
Deferred initial public offering costs		(2,335	)		(1,245	)		(1,502	)

Net cash used in financing activities		(22,338	)		(15,061	)		221,954

Net change in cash, cash equivalents and restricted cash		4,848			(10,602	)		8,118
Cash, cash equivalents and restricted cash, beginning of year		7,531			18,133			10,015

Cash, cash equivalents and restricted cash end of year	$	12,379		$	7,531		$	18,133

Supplemental disclosure of non-cash transactions:
Escrow deposits reclassified to oil and gas properties:	$	—		$	3,067		$	—
Increase in current liabilities for additions to property and equipment:		446			2,145			2,184
Oil and gas properties acquired through issuance of equity in consolidated subsidiary:		572,166			—			—
Oil and gas properties acquired through deemed distribution in connection with common control transaction:		37,459			—			—
Supplemental disclosure of cash flow information:
Cash paid for income taxes:	$	101		$	230		$	175
Cash paid for interest expense:		1,268			1,687			676

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

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2021, 2020, AND 2019

1.	Organization

Kimmeridge Mineral Fund, LP (together with its subsidiaries, the “Partnership”) is a Delaware limited partnership operating under the Third Amendment to the Second Amended and Restated Limited Partnership Agreement (the “Partnership Agreement”) dated as of July 19, 2019. The Partnership formed on November 1, 2016 and commenced operation on November 11, 2016. The primary purpose of the Partnership is to acquire, own and manage mineral and royalty interests in the Permian Basin, located in West Texas and southeastern New Mexico of the United States. Mineral interests are real property interests that are typically perpetual and grant ownership of the oil and natural gas underlying a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased to third party operators, usually for a one to three-year term, the Partnership typically receives an upfront cash payment, known as a lease bonus, and the Partnership retains a mineral royalty, which entitles the Partnership to a cost-free percentage (up to 25%) of production or revenue from production free of lease operating expenses. The Partnership also owns surface rights which generate revenues from the sale of water produced from the Partnership’s water supply assets and from rights-of-way, easements and other rights.

The Partnership Agreement provides that the Partnership will continue (unless earlier dissolved) for ten years from the final closing date provided, however, that Kimmeridge Mineral GP, LLC (the “General Partner” or “Management”), may, in its discretion, extend the term of the Partnership for two additional one-year periods. In addition, the General Partner may extend the term of the Partnership for a third additional three-year period (the “Final Extension”); provided however, that the General Partner shall provide notice of such a proposed extension to the Limited Partners at least 60 calendar days before the expiration of the then current term. The Final Extension shall automatically take effect unless a majority of the Limited Partnership Advisory Committee (“LPAC”) members notify the General Partner in writing within 30 calendar days of receipt of the extension notice of their decision not to allow the Final Extension. Except as may be required by law or expressly provided for in the Partnership Agreement, the liability of each Limited Partner is limited to its Capital Commitment.

2.	Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Partnership’s financial position as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years ended December 31, 2021, 2020, and 2019. The Partnership has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Partnership’s estimates and classification of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such

data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of the Partnership’s oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Partnership’s wholly-owned subsidiaries and any entities in which the Partnership owns a controlling interest. All intercompany accounts and transactions have been eliminated in consolidation. Noncontrolling interests in the Partnership’s consolidated financial statements represents the interests in a subsidiary of the Partnership, DPM HoldCo, LLC (“DPM HoldCo”), which are owned by outside parties. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Partnership’s consolidated balance sheets.

Risks and Uncertainties

The ongoing global spread of the novel coronavirus (“COVID-19”), has caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. This disruption has been somewhat alleviated in 2021. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Additionally, significant geopolitical events may cause increased volatility in the price of oil and natural gas.

The markets for oil, natural gas and natural gas liquids (“NGL”) have experienced significant price fluctuations. Such price volatility is expected to continue into the future. Lower commodity prices may reduce the amount of oil, natural gas and NGL that can be produced economically by operators. Increases or decreases in commodity prices could impact the Partnership’s financial performance and expected operating results, which may include future reserves estimates and potential recognition of impairment charges related to the Partnership’s mineral and royalty interests.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented on the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases: Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The new

standards become effective for the Partnership during the fiscal year ending December 31, 2022 and interim periods within the fiscal year ending December 31, 2023. Early adoption is permitted. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses, which amends current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 is effective for annual periods beginning after December 15, 2022 and interim periods within those annual periods. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

In March 2020, the FASB issued ASU 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2021, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contract modifications, hedging relations, and other affected transactions. The Partnership currently only has one contract subject to LIBOR, its revolving credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update is effective immediately, but may be adopted through December 31, 2022, and allows for elections to be made by the Partnership in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

Cash and Cash Equivalents

The Partnership considers all highly-liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments.

Accrued Revenue and Accounts Receivable

Accrued revenue and accounts receivable represent amounts due to the Partnership and are uncollateralized, consisting primarily of royalty revenue receivable. Royalty revenue receivable consists of royalties due from operators for oil, natural gas and NGL volumes sold to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to the Partnership. Receivables from third parties for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated.

The Partnership routinely assesses the recoverability of all material accounts receivable to determine their collectability. The Partnership accrues a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. The Partnership had an allowance for doubtful accounts related to its KMF Water, LLC (“KMF Water”) receivables of $0.2 million and $0.2 million as of December 31, 2021 and 2020, respectively. There were no such allowances for KMF Land, LLC’s (“KMF Land”) royalty revenue receivables as of December 31, 2021 and 2020.

Oil and Gas Properties

The Partnership uses the successful efforts method of accounting for oil and natural gas producing properties, as further defined under ASC 932, Extractive Activities—Oil and Natural Gas. Under this

method, costs to acquire mineral interests in oil and natural gas properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of Exploration and Production (“E&P”) operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved oil and gas properties by basin. Capitalized costs for proved oil and natural gas mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions. Depletion expense totaled approximately $40.3 million, $31.4 million, and $25.7 million for the years ended December 31, 2021, 2020, and 2019, respectively.

Other Property and Equipment

Other property and equipment is recorded at cost, which includes water supply assets (water wells and water storage pits), and leasehold improvements. Depreciation and amortization are calculated using the straight-line method over the estimated useful lives of the assets. Leasehold improvements are depreciated over the shorter of the lease term or the useful lives of the assets. For the years ended December 31, 2021, 2020, and 2019, the Partnership recorded approximately $0.6 million, $0.6 million, and $0.5 million respectively, in depreciation for water assets and other property and equipment.

The costs to drill water wells are capitalized while drilling is in progress. If a water well is determined to be unsuccessful or unproductive prior to being placed in service, the associated costs will be charged to expense in the period the determination is made. No expense was recognized in connection with unsuccessful water wells for the years ended December 31, 2021, 2020, and 2019. Additionally, we evaluate our other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset that has been placed in service may not be recoverable. No impairment charge was recorded for the years ended December 31, 2021, 2020, and 2019.

Impairment of Oil and Gas Properties

The Partnership evaluates its producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, the Partnership compares the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. There was no impairment of proved properties for the years ended December 31, 2021, 2020, and 2019. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include but are not limited to commodity price outlooks, current and future operator activity in the Permian Basin, and analysis of recent mineral transactions in the surrounding area. The Partnership recognized no impairment of unproved properties for the year ended December 31, 2021 and 2019. The Partnership recognized approximately $0.8 million of unproved property impairment for the year ended December 31, 2020. This impairment was related to capitalized acquisition costs for a prospective mineral interest acquisition that the Partnership did not complete.

Derivative Financial Instruments

In order to manage its exposure to oil, natural gas, and NGLs price volatility, the Partnership may periodically enter into derivative transactions, which may include commodity swap agreements, basis swap agreements, and other similar agreements which help manage the price risk associated with the Partnership’s production. These derivatives are not entered into for trading or speculative purposes. To the extent legal right of offset exists with a counterparty, the Partnership reports derivative assets and liabilities on a net basis. The Partnership has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Partnership actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions.

The Partnership records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Partnership’s consolidated statements of operations. The Partnership’s derivatives have not been designated as hedges for accounting purposes. In October 2020, KMF Land terminated all of its outstanding oil and basis swap derivative contracts. KMF was not party to any derivative contracts as of December 31, 2021 and 2020.

Accrued Expenses and Other Liabilities

The Partnership’s accrued expenses and other liabilities consisted of the following as of the dates indicated (in thousands):


	December 31, 2021		December 31, 2020
Ad valorem taxes payable	$	1,750	$	1,200
General and administrative		904		445
Other taxes payable		529		68
Acquisition costs		391		—
Interest expense		274		88
Deferred rent expense		128		63
Other		164		171

Total accrued expenses and other liabilities	$	4,140	$	2,035

Income Taxes

The Partnership is organized as a pass-through entity for income tax purposes. As a result, the partners are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. However, the Partnership is required to pay Texas State franchise taxes and certain New Mexico income taxes. The Partnership recognized approximately $562 thousand, $38 thousand, and $171 thousand of Texas state franchise taxes and New Mexico income taxes for the years ended December 31, 2021, 2020, and 2019, respectively.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGL, less production taxes and post-production expenses. The prices of oil, natural gas, and NGL from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs.

Oil, natural gas, and NGL revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

Water sales are recognized when control of the water is transferred to an E&P operator and collectability is reasonably assured.

The Partnership also earns revenue related to lease bonuses. The Partnership earns lease bonus revenue by leasing its mineral interests to E&P companies. The Partnership recognizes lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

See Note 3 for additional disclosures regarding revenue recognition.

Concentration of Revenue

Collectability of the Partnership’s royalty revenue is dependent upon the financial condition of the Partnership’s operators as well as general economic conditions in the industry.

For the year ended December 31, 2021, in the Oil and Gas Producing Activities segment, revenue from Coterra Energy, Diamondback Energy, Inc, Callon Petroleum Company, and Oxy USA Inc represented approximately 12%, 11%, 11%, and 10% of total revenue, respectively. These figures are the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the year ended December 31, 2021 were de minimis.

For the year ended December 31, 2020, in the Oil and Gas Producing Activities segment, revenue from Diamondback Energy, Inc, Cimarex Energy, and Oxy USA Inc represented approximately 15%, 12% and 10% of total revenue, respectively. These figures are the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the year ended December 31, 2020 were de minimis.

For the year ended December 31, 2019, in the Oil and Gas Producing Activities segment, revenue from Cimarex Energy, Oxy USA Inc and PDC Energy represented approximately 16%, 10% and 10% of total revenue, respectively. In the Water Services Operations segment PDC Energy, WPX Energy, OXY USA Inc. and BTA Oil Producers represented 37%, 24%, 20% and 16% of total revenue, respectively. Combining both the Water Services Operations and Oil and Gas Producing Activities segments, Cimarex Energy, PDC Energy, and Oxy USA Inc represented approximately 15%, 12% and 11% of total revenue, respectively.

Although the Partnership is exposed to a concentration of credit risk, the Partnership does not believe the loss of any single operator would materially impact the Partnership’s operating results as crude oil, natural gas, and natural gas liquids are fungible products with well-established markets and numerous purchasers. If multiple operators were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving the Partnership’s operators have stipulated that royalty owners must still be paid for oil, natural gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, the Partnership does not expect the entry of one of our operators into bankruptcy proceeding to materially affect our operating results.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accrued revenue and accounts receivable, accrued expenses, and other liabilities approximate fair value, as of December 31, 2021 and 2020 due to their short term nature.

The Revolving Credit Facility (defined in Note 7) has a recorded value that approximates its fair value as the interest rates are based on prevailing market rates.

Deferred Financing Costs

Debt issuance costs incurred in connection with KMF Land’s entry into its credit facility, and subsequent amendments, are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. As of December 31, 2021 and 2020, KMF Land had unamortized debt issuance costs of $2.1 million and $1.0 million, respectively, in connection with its entry into the facility and subsequent amendments.

Deferred Offering Costs

The Partnership recognized a write-offs of approximately $2.4 million and $2.7 million of deferred offering costs for the years ended December 31, 2021 and 2020 related to the cancelation of an initial public offering in accordance with SAB Topic 5.A of the Securities and Exchange Commission.

Deferred Rent

The Partnership recognizes rental expense for an operating lease on a straight-line basis over the term of the lease agreement. The deferred rent liability on the Partnership’s condensed consolidated balance sheets is attributable to the difference between rental expense (recognized on a straight-line basis) and the variable lease payments over the term of the agreement. The Partnership has historically leased office space under a single operating lease. In September 2021, the Partnership entered into an agreement to lease new office space under a different operating lease. In December 2021, the Partnership entered into a sublease of its current office space with an unaffiliated third-party. In conjunction with the sublease, the Partnership recognized a non-cash loss of $536 thousand, which is recorded in General and Administrative on the Consolidated Statement of Operations.

Public Transaction Costs

General and administrative expense of $4.1 million for the year ended December 31, 2021 included $602 thousand related to the merger with Falcon Minerals Operating Partnership, LP (“Falcon”). See Note 14.

3.	Revenue from Contracts with Customers

Oil and natural gas sales

Oil, natural gas and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Partnership’s oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the Partnership’s contracts with customers are satisfied at a point in time when control transfers at the wellhead, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities. The Partnership typically receives payment for oil, natural gas and NGL sales within 30 to 90 days of the month of delivery after initial production from the well. Such periods can extend longer due to factors outside of our control. The Partnership’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.

Lease bonus and other income

The Partnership also earns revenue from lease bonuses, delay rentals, and right-of-way payments. The Partnership generates lease bonus revenue by leasing its mineral interests to E&P companies. A mineral lease agreement represents our contract with a customer and generally transfers the rights, for a specified

period of time, to explore for and develop any oil, natural gas and NGL discovered, grants us a specified royalty interest in the hydrocarbons produced from the leased property, and requires that drilling and completion operations commence within a specified time period. The Partnership recognizes lease bonus revenues when the lease agreement has been executed and payment is determined to be collectible. At the time the Partnership executes the lease agreement, the lease bonus payment is delivered to the Partnership. Upon receipt of the lease bonus payment, the Partnership will release the recordable original lease documents to the customer. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period and payment has been received. Right-of-way payments are recorded by the Partnership when the agreement has been executed and payment is determined to be collectable. Payments for lease bonus and other income become unconditional upon the execution of an associated agreement. Accordingly, the Partnership’s lease bonus and other income transactions do not give rise to contract assets or liabilities.

Water sales

Historically, the Partnership earned revenue from water sales to various E&P operators located near its water supply assets. Water sales revenues are recognized when control of the water is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. The performance obligations for the Partnership’s water sales are satisfied when control of the water is transferred to the customer, which may occur at the location of the Partnership’s water operations or at the customer’s well site. The Partnership’s water sales agreements are inherently short-term in nature and are executed on an as-needed basis with customers. The Partnership’s contracts for water sales are satisfied at the point in time when control of the water is transferred to the customer, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities.

In 2020, KMF Water entered into an agreement (the “Water Services Agreement”) with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations. See Note 11 for additional information. In October of 2021, the agreement was terminated.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.

Lease bonus and other income

Given that the Partnership does not recognize lease bonus or other income until an agreement has been executed, at which point its performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Water sales and leasing income

Given that the Partnership does not recognize water revenue until water is delivered or water leasing income until the lessee receives payment from its customer, at which point its performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. As a royalty interest owner, the Partnership has limited visibility into the timing of when new wells start producing as production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. The difference between the Partnership’s estimates of royalty income and the actual amounts received for oil and natural gas sales are recorded in the month that the royalty payment is received from the customer. For the years ended December 31, 2021, 2020, and 2019, revenue recognized related to performance obligations satisfied in prior reporting periods was primarily attributable to production revisions by operators or amounts for which the information was not available at the time when revenue was estimated.

4.	Oil and Gas Properties

The Partnership has been and is engaged in the purchase of mineral rights in the Permian Basin in West Texas and southeastern New Mexico. The following is a summary of oil and natural gas properties as of December 31, 2021 and 2020 (in thousands):


Oil and natural gas properties:	December 31, 2021			December 31, 2020
Unproved properties	$	817,873		$	399,229
Proved properties		447,369			254,854

Oil and natural gas properties, gross		1,265,242			654,083
Accumulated depletion and impairment		(118,175	)		(77,857	)

Oil and natural gas properties, net	$	1,147,067		$	576,226

The Partnership paid mineral acquisition costs of approximately $38.5 million, $35.5 million, and $266.5 million for the years ended December 31, 2021, 2020, and 2019 respectively. Additionally, the Partnership acquired mineral and royalty interests of $572.2 million in three separate transactions in exchange for equity interests in a subsidiary of the Partnership. See Note 5 for additional information regarding these transactions. No such transactions occurred in the years ended December 31, 2020 and 2019. The Partnership paid $137 thousand related to purchase price adjustments from prior property sales for the year ended December 31, 2021. The Partnership received proceeds from the sale of mineral interests of $14.1 million and $22.0 million for the year ended December 31, 2020 and 2019.

5.	Acquisitions

Source Acquisition

In August 2021, KMF Land completed the acquisition of approximately 25,000 NRAs in the Midland and Delaware Basins from Source Energy Leasehold, LP and Permian Mineral Acquisitions, LP (together, “Source”). At close, subject to the terms and conditions of the transaction agreement, Source contributed its mineral and royalty interests to KMF Land and in consideration for the contribution, Kimmeridge affiliates caused DPM HoldCo to issue equity interests in DPM HoldCo to Source.

The Source acquisition was accounted for as an asset acquisition and, therefore, the acquired interests were recorded based on the fair value of the total assets acquired on the acquisition date. Based on the estimated fair values of the assets received, the Partnership recorded $183.2 million of the total consideration as unproved oil and gas property and $69.7 million as proved oil and gas property. Additionally, $3.5 million of transaction costs were capitalized related to the transaction.

Rock Ridge Acquisition

In June 2021, KMF Land completed the acquisition of approximately 18,700 NRAs from Rock Ridge Royalty, LLC (“RRR”). At close, subject to the terms and conditions of the transaction agreement, RRR contributed its mineral and royalty interests to KMF Land and in consideration for the contribution, Kimmeridge affiliates caused DPM HoldCo (a subsidiary of the Partnership and the sole member of KMF Land, LLC) to issue equity interests in DPM HoldCo to RRR.

The RRR acquisition was accounted for as an asset acquisition and, therefore, the acquired interests were recorded based on the fair value of the total assets acquired on the acquisition date. Based on the estimated fair values of the assets received, the Partnership recorded $190.3 million of the total consideration as unproved oil and gas property and $68.3 million as proved oil and gas property. Additionally, $1.1 million of transaction costs were capitalized related to the transaction.

Delaware ORRIs Acquisition

In October 2020, another partnership owned and managed by Kimmeridge, (“Fund V”), acquired a 2.0% (on an 8/8ths basis) overriding royalty interest in all of Callon Petroleum Company’s (“Callon”) operated assets in the Delaware, Midland and Eagle Ford Basins, proportionately reduced to Callon’s net revenue interest (the “Chambers ORRI”).

In June 2021, KMF Land entered into a definitive agreement to acquire 84% of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, a subsidiary of Fund V (the “Chambers Acquisition”). Immediately following the consummation of the contributions of assets to KMF Land, Chambers HoldCo, LLC (the managing member of Chambers Minerals, LLC) was issued equity in DPM HoldCo. As the general partner of Fund V and the General Partner of the Partnership are affiliated, the transaction was approved by the Partnership’s Limited Partner Advisory Committee on June 3, 2021.

The Chambers Acquisition was accounted for as an asset acquisition. The Chambers Acquisition was also accounted for as a transaction between entities under common control; the controlling ownership and management of the general partner of Fund V and the general partner of the Partnership have significant overlap, including responsibility for the management, control, and direction of the business affairs of the respective partnerships. As KMF Land and Fund V are entities under common control, the Partnership recorded the acquisition utilizing the properties’ net book value. The properties acquired by KMF Land had a historical net book value to Fund V at the time of sale of approximately $60.6 million ($45.3 million was allocated to unproved property and $15.3 million was allocated to proved property). Accordingly, the $37.5 million excess of the fair value of the properties above their net book value was recorded as a decrease to partners’ capital at the date of the transaction.

DRC Acquisition

In July 2019, KMF Land entered into a Purchase and Sale Agreement and a Cooperation Agreement with Desert Royalty Company (“DRC”) pursuant to which KMF Land agreed to acquire an undivided 25% interest in DRC’s Delaware Basin oil and gas mineral and royalty interests. In January 2020, the entities executed an Amendment to the Letter Agreement and certain Special Warranty Deeds. In March 2021, a notice of KMF’s intent to pursue an initial public offering (an “IPO Notice”) was provided to DRC in accordance with the last agreement executed. Subsequent to this notice, the Partnership terminated the Letter Agreement with DRC in accordance with its terms.

Other Acquisitions

In February 2020, the Partnership acquired certain mineral and royalty interests in the Delaware Basin for $30.3 million. The Partnership funded the acquisition with capital contributions, cash flows from operations and borrowings under the KMF Revolving Credit Facility.

In July 2021, the Partnership acquired certain mineral and royalty interests in the Delaware Basin for a total of $21.8 million in cash. The Partnership predominantly funded the acquisitions with capital contributions, cash flows from operations and borrowings under the KMF Revolving Credit Facility.

6.	Equity

Committed Capital

As of December 31, 2021, the Partnership had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At December 31, 2021, approximately $29.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Partnership. Through December 31, 2021, the Partnership’s contributed capital as a percentage of total Committed Capital was approximately 95%.

As of December 31, 2020, the Partnership had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At December 31, 2020, approximately $37.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Partnership. Through December 31, 2020, the Partnership’s contributed capital as a percentage of total Committed Capital was approximately 94%.

The General Partner may admit additional Subscription Limited Partners, or permit any existing Subscription Limited Partner to increase its Committed Capital, at one or more subsequent closings on or before the nine month anniversary of the Initial Closing except with respect to the Extended Closing Date and the Second Extended Closing Date. The General Partner and each Subscription Limited Partner that is admitted or that increases its Committed Capital at a Subsequent Closing shall make, at such Subsequent Closing, Capital Contributions for Investments, Management Fees, and Expenses such that such partners’ Capital Contributions included or made as of the date of the Subsequent Closing are equal to their Pro Rata Share of such amounts made by the Partnership as of the date of such Subsequent Closing. In September 2019, the Partnership had a Subsequent Closing and increased its Committed Capital to a total of $626.4 million, with $618.4 million from Limited Partners and $8.0 million from the General Partner. In September 2019, pursuant of Article III of the Partnership Agreement, a subsequent close rebalance was executed to reflect the change in partner ownership.

Allocation of Partners’ Net Profits and Losses

In accordance with the Partnership Agreement, net profit or net loss is generally allocated among the Capital Accounts of the Partners in accordance with the following distribution methodology.

Partners’ Distributions

Subject to the provisions of the Partnership Agreement, investment proceeds shall be distributed to the Partners, in proportion to each of their respective percentage interests, as follows:

First - 100% to such Limited Partner until such Limited Partner has received cumulative distributions pursuant to this clause (i) in an amount equal to all Capital Contributions of such Limited Partner (whether such Capital Contributions were made to fund Investments, utilized for the payment of Partnership Expenses, Management Fees or applied for any other purpose);

Second - 100% to such Limited Partner until the cumulative distributions to such Limited Partner represents an 8% per annum (compounded annually) internal rate of return on the Capital Contributions of such Limited Partner referred to in clause (i) above calculated from the due date specified in the applicable Payment Notice until the date of the distribution (the “Preferred Return Amount”);

Third - 50% to the General Partner and 50% to such Limited Partner until the General Partner has received distributions pursuant to this clause (iii) equal to the sum of (A) the ratio of such Limited Partner’s Capital Contribution to the total Capital Contributions of all Limited Partners multiplied by the General Partner’s aggregate Capital Contribution plus (B) 20% of the sum of (Y) the amount distributed to such Limited Partner pursuant to clause (ii) above and (Z) the amount distributed to such Limited Partner and to the General Partner with respect to such Limited Partner pursuant to this clause (iii); and;

Thereafter - 80% to such Limited Partner and, 20% to the General Partner.

Upon the final distribution of proceeds attributable to the Partnership’s investments, the General Partner, if required, must return to the Limited Partners, in proportion to their capital contributions used to fund the Partnership’s investments an aggregate amount, not to exceed the General Partner’s reallocation, to assure that the total distributions of proceeds attributable to the Partnership’s investments are made in accordance with the above formula.

In October 2021, DPM HoldCo distributed $60.9 million to its outside owners, including $8.7 million to an affiliate Kimmeridge fund. In November 2021, the Partnership made a distribution of $67.5 million to its partners, comprised of approximately $66.6 million to Limited Partners and $0.9 million to the General Partner.

7.	Long-Term Debt

Revolving Credit Facility

KMF Land is party to a credit agreement with a syndicate of banks led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent, and Capital One National Association and Barclays Bank PLC as Co-Documentation Agents (the “Revolving Credit Facility”).

Availability under our Revolving Credit Facility is governed by a borrowing base, which is subject to redetermination semi-annually each year. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. The Partnership can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base requires unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The determination of the borrowing base takes into consideration the estimated value of KMF Land’s oil and gas mineral interests in accordance with the lenders’ customary practices for oil and gas loans. The Revolving Credit Facility is guaranteed by KMF Land and is collateralized by substantially all of the assets of KMF Land.

In June 2021, KMF Land and the Partnership entered into the Fourth Amendment to Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, allowed for the consummation of the acquisitions described in Note 5.

In October 2021, KMF Land and DPM HoldCo entered into the Amended and Restated Credit Agreement with a syndicate of banks led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent. Pursuant to the Amended and Restated Credit Agreement, the initial borrowing base under the new facility is $150.0 million.

As of December 31, 2021, the borrowing base was $150.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $134.0 million. As of December 31, 2020, the borrowing base was $75.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $33.5 million.

The Revolving Credit Facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of

our Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of adjusted LIBOR rate loans, 2.500% to 3.500%. The Partnership may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of our Revolving Credit Facility. The Revolving Credit Facility is subject to other customary fee, interest and expense reimbursement provisions.

As of December 31, 2021 and 2020, the weighted average interest rate related to our outstanding borrowings was 3.36% and 2.66%, respectively. As of December 31, 2021 and 2020, KMF Land had unamortized debt issuance costs of $2.1 million and $1.0 million, respectively, in connection with its entry into the facility and subsequent amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. For the years ended December 31, 2021 and 2020, we recognized $0.4 million and $0.3 million, respectively, in interest expense related to the amortization of deferred financing costs.

Our Revolving Credit Facility matures on September 26, 2024. Loans drawn under our Revolving Credit Facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, the Partnership may permanently reduce or terminate in full the commitments under our Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our Revolving Credit Facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our Revolving Credit Facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Our Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject only to no default or borrowing base deficiency) and investments. In addition, our Revolving Credit Facility requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00. EBITDA for the period ending on December 31, 2021 is equal to EBITDA for the period beginning on July 1, 2021 and ending on December 31, 2021, multiplied by two. The Partnership was in compliance with the terms and covenants of the Revolving Credit Facility at December 31, 2021 and 2020.

8.	Fair Value Measurement

The Partnership is subject to ASC 820, Fair Value Measurements and Disclosures. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Inputs are used in applying the various valuation techniques and broadly refer to the assumptions that market participants use to make valuation decisions, including assumptions about risk. Inputs may include price information, volatility statistics, specific and broad credit data, liquidity statistics, and other factors. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. However, the determination of what constitutes “observable” requires significant judgment by Management. Management considers observable data to be market data which is readily available, regularly distributed or updated, reliable and verifiable, not proprietary, and provided by independent sources that are actively involved in the relevant market. The categorization of a financial instrument within the hierarchy is based upon the pricing transparency of the instrument and does not necessarily correspond to Management’s perceived risk of that instrument.

Level 1 - Fair values are based on unadjusted quoted prices in active markets that are accessible at the measurement date of identical, unrestricted assets.

Level 2 - Fair values are based on quoted prices for markets that are not active or financial instruments for which all significant inputs are observable, either directly or indirectly.

Level 3 - Inputs that are unobservable and significant to the overall fair value measurement and include situations where there is little, if any, market activity for the asset or liability.

The Partnership’s proved oil and gas properties are assessed for impairment on a periodic basis. If the Partnership’s proved properties are determined to be impaired, the carrying basis of the properties is adjusted down to fair value. This represents a fair value measurement that would qualify as a non-recurring Level 3 fair value measurement. The fair value represents Management’s best estimate using the inputs available as of December 31, 2021 and 2020. No impairment of proved properties was recorded for the years ended December 31, 2021 and 2020.

The fair value of the Partnership’s derivative instruments (Level 2) was estimated using discounted cash flows and credit risk adjustments. As of December 31, 2021 and 2020, the Partnership did not have any derivative instruments outstanding. See Note 12 for further information on the fair value of our derivative instruments.

9.	Related Party Transactions

Management Fees

The Partnership has entered into a management services arrangement with Kimmeridge Energy Management Company, LLC (the “Manager”).

As compensation for services rendered in the management of the Partnership, the Partnership will pay the Manager with respect to each Limited Partner an annual management fee (“Management Fee”) computed on a daily basis from the date of the Initial Closing. Limited Partners who increased their Commitment to the Partnership at the Extended Closing Date will only be required to pay Management Fees with respect to their increased Commitment from and after the Extended Closing Date. Limited Partners who increased their Commitments on the Second Extended Closing Date will not be obligated to pay Management Fees with respect to such increased Commitments until after the Commitment Period Expiration Date. The Management Fee will be paid in quarterly installments on the first business day of each Fiscal Quarter with each installment to be equal to one-quarter of the amount that would be payable on the last day of its preceding Fiscal Quarter. Until the earlier of (A) the Commitment Period Expiration Date and (B) the date that the General Partner, any Principal or any Affiliate thereof first accrues or is paid a Management Fee, advisory fee or similar fee with respect to a Successor Fund (the earlier of the dates referred to in (A) or (B) being the “Initial Step-Down Date”), 2% per annum of such Limited Partner’s Commitment.

Beginning on the day after the Initial Step-Down Date and until the earlier of (A) termination of the Partnership pursuant to Article IX of the Partnership Agreement and (B) the sixth anniversary of the Final Closing (the earlier of the dates referred to in (A) or (B) being the “Second Step-Down Date”), 2% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

Beginning on the day after the Second Step-Down Date and until the termination of the Partnership, 1% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

Each quarterly installment of the Management Fee calculated with respect to each Limited Partner, shall be reduced by the Limited Partner’s pro rata percentage (based on Capital Contributions) of any application fees, closing fees, breakup fees or similar fees associated with an Investment or proposed investment and

other routine fees, received by the General Partner during the quarter. If the credited amounts exceed the quarterly Management Fee payment next due and payable, such excess shall be carried forward from quarter to quarter to reduce the Management Fee payable in future periods. For the years ended December 31, 2021, 2020, and 2019, there were no adjustments or credited amounts and the Manager earned and was paid approximately $7.5 million in Management Fees relating to management services.

Common Control Transaction

The Partnership has acquired oil and gas properties from separate limited partnerships whereby the General Partner of the Partnership and the general partner of the separate limited partnerships are affiliated. These transactions were accounted for as a reduction to partners’ capital as the affiliated entities were under common control. The following transaction was completed during the year ended December 31, 2021:

Delaware ORRIs Acquisition

In October 2020, another partnership owned and managed by Kimmeridge acquired a 2.0% (on an 8/8ths basis) overriding royalty interest in all of Callon’s operated assets in the Delaware, Midland and Eagle Ford Basins, proportionately reduced to Callon’s net revenue interest.

In June 2021, KMF Land entered into a definitive agreement to acquire 84% of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, a subsidiary of Fund V. Immediately following the consummation of the contributions of assets to KMF Land, Chambers HoldCo, LLC (the managing member of Chambers Minerals, LLC) was issued equity in DPM HoldCo. As the general partner of Fund V and the General Partner of the Partnership are affiliated, the transaction was approved by the Partnership’s Limited Partner Advisory Committee on June 3, 2021.

Cost Reimbursements and Allocations from Affiliates

General and administrative expenses and certain capitalizable costs are not directly associated with the generation of the Partnership’s revenues and include costs such as employee compensation, office expenses and fees for professional services. These costs are allocated on a “time spent” basis, a pro rata basis, or by another manner which is designed to be fair and equitable. Some of those costs are incurred on the Partnership’s behalf and allocated to the Partnership by the Manager and its affiliates and reimbursed by the Partnership. These costs may not be indicative of costs incurred by the Partnership had such services been provided by an unaffiliated company during the period presented. We have not estimated what these costs and expenses would be if they were incurred by the Partnership on a standalone basis as such estimate would be impractical and lack precision. We believe the methodology utilized by Kimmeridge Operations and the Manager for the allocation of these costs to be reasonable.

Kimmeridge Operations Reimbursements

From time to time, the Partnership reimburses Kimmeridge Operations, LLC (“Kimmeridge Operations”), a wholly owned subsidiary of the Manager and affiliate of the Partnership, for general and administrative

expenses. As a subsidiary of the Manager, Kimmeridge Operations staff perform land and administrative services on behalf of the Partnership. For the years ended December 31, 2021, 2020, and 2019, the Partnership reimbursed Kimmeridge Operations for approximately $8.5 million, $3.8 million, and $7.3 million related to these services, respectively. As of December 31, 2021 and 2020, there were no amounts due to Kimmeridge Operations.

Kimmeridge Energy Management Company Reimbursements

From time to time, the Partnership reimburses the Manager for investments and expenses prefunded on behalf of the Partnership. For the years ended December 31, 2021, 2020, and 2019, the Partnership reimbursed the Manager for approximately $0.3 million, $0.4 million, and $1.5 million, respectively. As of December 31, 2021 and 2020, approximately $142 thousand and $55 thousand was due to the Manager, respectively.

10. Commitment

and Contingencies

The Partnership leases office space under an operating lease. In September 2021, the Partnership entered into an agreement to lease new office space under a different operating lease. In December 2021, the Partnership entered into a sublease of its current office space with an unaffiliated third-party. Future minimum lease commitments under the lease at December 31, 2021 are presented below (in thousands):


Year	Total
2022	$	539
2023		600
2024		614
2025		628
2026		643
Thereafter		1,533

Total	$	4,557

Legal Proceedings

From time to time, the Partnership may be involved in various legal proceedings, lawsuits, and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. Management does not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

11. Lease

Income

In April 2020, KMF Water entered into the Water Services Agreement with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations for an initial term of three months. Under the terms of the agreement, the third party is responsible for the production, marketing, and sales of water from the Partnership’s water properties, but each entity will each be entitled to fifty percent of the proceeds generated from water sales. The agreement also prescribes which entity (KMF or the third party) will be responsible for various costs under the arrangement. The initial term has been renewed for successive three-month periods and will continue to automatically renew for successive three-month terms unless terminated.

The Water Services Agreement constitutes a leasing arrangement under which the Partnership is a lessor. Under the terms of the agreement, the Partnership is not entitled to any income until the lessee has completed a water sale and received payment from its customer. The Partnership does not accrue this

contingent rental income until the lessee has received payment. Leasing income related to the Water Sales Agreement was $0.2 million and $13 thousand during the years ended December 31, 2021 and 2020. The agreement was terminated in October 2021.

12.

Derivative Instruments

Commodity Derivatives

KMF Land may enter into commodity derivative contracts to manage its exposure to oil and gas price volatility associated with its production. These derivatives are not entered into for trading or speculative purposes. While the use of these instruments limits the downside risk of adverse commodity price changes, their use may also limit future cash flows from favorable commodity price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, the Partnership may increase or decrease its derivative positions. The Partnership’s commodity derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses on commodity derivatives are recognized in the Partnership’s statement of operations.

In 2020, the Partnership utilized fixed price swaps and basis swaps to manage commodity price risks. The Partnership has entered into these swap contracts when management believes that favorable future sales prices for the Partnership’s production can be secured. Under fixed price swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Partnership pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Partnership receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price that is representative of the price received by many of the operators in the Delaware Basin.

In October 2020, KMF Land terminated all of its outstanding oil and basis swap derivative contracts. KMF was not party to any derivative contracts as of December 31, 2021 and 2020.

The following table is a summary of derivative gains and losses, and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019 (in thousands):


	Statement of operations location		Year ended December 31, 2021		Year ended December 31, 2020			Year ended December 31, 2019
Commodity derivative losses		Revenue	$	—	$	(2,573	)	$	—

The fair value of commodity derivative instruments was determined using Level 2 inputs.

13. Business

Segment Information

The Partnership has two reportable segments: Oil and Gas Producing Activities and Water Service Operations. The segments provide the chief operating decision maker (“CODM”) with a comprehensive financial view of the Partnership’s core business. The Partnership’s Management has been determined to be the CODM. The CODM assesses performance and allocates resources based on the two reportable segments.

The Oil and Gas Producing Activities segment is comprised of managing the mineral and royalty interests and related revenue streams of KMF Land. The revenue streams of this segment principally consist of royalties from oil, natural gas and NGL producing activities and revenues from lease bonus payments and easements. We are not a producer and the Partnership’s oil, natural gas, and NGL revenues are derived from a fixed percentage of the oil, natural gas and NGL produced from the acreage underlying our interests, net of post-production expenses and production taxes. The Water Service Operations segment comprises the

water supply assets and revenues of KMF Water. The revenue of this segment consists of water sales to various basin operators produced from the water supply assets of the Partnership, as well as lease income under the Water Services Agreement.

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profit. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the CODM in deciding how to allocate resources and assess performance. Segment profit is defined as segment revenues less operating expenses, depreciation, depletion and amortization, income taxes, and interest expense. Partnership expenses include general expenses associated with managing the Partnership and are not allocated directly to the two reportable segments.

The following table sets forth certain financial information with respect to the Partnership’s reportable segments (in thousands):


	For the year ended December 31, 2021
	Oil and Gas Producing Activities			Water Service Operations		Partnership			Consolidated Total
Revenues	$	120,362		$	226	$	—		$	120,588
Depreciation, depletion and amortization		40,619			287		—			40,906
Income tax expense		(555	)		—		(7	)		(562	)
Interest expense		(1,918	)		—		—			(1,918	)
Segment income (loss)		55,272			32		(7,834	)		47,470
Total assets as of December 31, 2021		1,195,520			3,314		4,020			1,202,854
Capital expenditures including mineral acquisitions		38,470			—		—			38,470

A reconciliation of segment profit (loss) to net income is as follows:
Segment profit	$	47,470
Interest income		25
Net income attributable to noncontrolling interests		18,781
Net income attributable to partners		28,714


	For the year ended December 31, 2020
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	43,113		$	13		$	—		$	43,126
Depreciation, depletion and amortization		31,746			303			—			32,049
Income tax expense		(38	)		—			—			(38	)
Interest expense		(2,021	)		—			—			(2,021	)
Segment loss		(6,253	)		(165	)		(7,849	)		(14,267	)
Total assets as of December 31, 2020		591,140			3,602			3,886			598,628
Capital expenditures including mineral acquisitions		35,836			—			—			35,836

A reconciliation of segment profit (loss) to net income is as follows:
Segment loss	$	(14,267	)
Interest income		53
Net loss		(14,214	)


	For the year ended December 31, 2019
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	56,205		$	3,475		$	—		$	59,680
Depreciation, depletion and amortization		25,730			471			—			26,201
Income tax (expense) benefit		(166	)		3			(8	)		(171	)
Interest expense		(1,099	)		(10	)		—			(1,109	)
Segment profit (loss)		19,559			537			(11,547	)		8,549
Total assets as of December 31, 2019		608,170			5,445			18,190			631,805
Capital expenditures including mineral acquisitions		266,942			637			—			267,579

A reconciliation of segment profit (loss) to net income is as follows:
Segment profit	$	8,549
Interest income		241
Net income		8,790

14.

Subsequent Events

Merger with Falcon Minerals

On January 11, 2022, DPM HoldCo, LLC entered into an Agreement and Plan of Merger with Falcon, pursuant to which Falcon will merge with and into DPM HoldCo, LLC, with DPM HoldCo, LLC continuing as the surviving entity in the Merger in an all-stock transaction, subject to Falcon shareholder approval.

15.

Supplemental Oil and Gas Information (Unaudited)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):


	December 31, 2021			December 31, 2020
Oil and natural gas interests:
Unproved	$	817,873		$	399,229
Proved		447,369			254,854

Total oil and natural gas interests		1,265,242			654,083
Accumulated depletion and impairment		(118,175	)		(77,857	)

Net oil and natural gas interests capitalized	$	1,147,067		$	576,226

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):


	December 31, 2021		December 31, 2020		December 31, 2019
Acquisition costs
Unproved properties	$	20,192	$	21,840	$	220,992
Proved properties		18,278		13,703		45,546

Total	$	38,470	$	35,543	$	266,538

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Partnership’s oil, natural gas and NGL operations.


	December 31, 2021			December 31, 2020			December 31, 2019
Oil, natural gas and natural gas liquids revenues	$	118,548		$	44,194		$	50,886
Severance and ad valorem taxes		(6,858	)		(3,147	)		(3,774	)
Depletion		(40,318	)		(31,440	)		(25,684	)
Impairment of oil and natural gas properties		—			(812	)		—
Income tax expense		(562	)		(38	)		(171	)

Results of operations from oil, natural gas and natural gas liquids	$	70,810		$	8,757		$	21,257

The reserves at December 31, 2021, 2020, and 2019 presented below were prepared by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Texas and New Mexico.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGL to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future ad valorem taxes are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently

imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Partnership’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:


	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBOE)
Balance, December 31, 2018		3,676			16,191			1,988			8,363
Revisions		(438	)		934			(22	)		(305	)
Extensions		1,929			6,214			704			3,668
Acquisition of Reserves		1,655			4,904			555			3,028
Divestiture of Reserves		(167	)		(513	)		(58	)		(310	)
Production		(816	)		(3,237	)		(393	)		(1,749	)

Balance as of December 31, 2019		5,839			24,493			2,774			12,695
Revisions		(1,098	)		(867	)		65			(1,178	)
Extensions		995			3,486			423			1,999
Acquisition of Reserves		445			633			77			628
Divestiture of Reserves		(173	)		(209	)		(26	)		(234	)
Production		(933	)		(4,134	)		(488	)		(2,110	)

Balance as of December 31, 2020		5,075			23,402			2,825			11,800
Revisions		180			6,531			405			1,674
Extensions		610			1,991			216			1,158
Acquisition of Reserves		7,240			19,165			2,076			12,511
Production		(1,261	)		(4,746	)		(499	)		(2,551	)

Balance as of December 31, 2021		11,844			46,343			5,023			24,592


Proved developed and undeveloped reserves:	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBOE)
Developed as of December 31, 2018		2,541		12,840		1,576		6,259
Undeveloped as of December 31, 2018		1,135		3,351		412		2,104

Balance at December 31, 2018		3,676		16,191		1,988		8,363

Developed as of December 31, 2019		4,223		20,293		2,298		9,903
Undeveloped as of December 31, 2019		1,616		4,200		476		2,792

Balance at December 31, 2019		5,839		24,493		2,774		12,695

Developed as of December 31, 2020		3,731		19,505		2,352		9,334
Undeveloped as of December 31, 2020		1,344		3,897		473		2,466

Balance at December 31, 2020		5,075		23,402		2,825		11,800

Developed as of December 31, 2021		9,285		40,747		4,417		20,494
Undeveloped as of December 31, 2021		2,559		5,596		606		4,098

Balance at December 31, 2021		11,844		46,343		5,023		24,592

For the year ended December 31, 2021, the Partnership had upward revisions of 180 MBbls of oil and 6,531 MMcf of gas and 405 MBbls of NGL. Total upward revisions of 1,674 MBOE were primarily due to

upward revisions of 1,184 MBOE related to changes in estimated ultimate recovery and upward revisions of 490 MBOE due to increases in pricing. For the year ended December 31, 2021, the Partnership had extensions of 610 MBbls of oil, 1,991 MMcf of gas, and 216 MBbls of NGLs of which 289 MBbls of oil, 883 MMcf of gas, and 96 MBbls of NGLs were from conversions of non-proved resources to proved developed producing and proved developed not producing due to operator drilling activity and 321 MBbls of oil, 1,108 MMcf of gas, and 120 MBbls of NGLs were from additional proved undeveloped reserves. In 2021, the Partnership acquired royalty and mineral interests of 7,240 MBbls of oil, 19,165 MMcf of gas, and 2,076 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2021, the Partnership did not divest any royalty and mineral interests.

For the year ended December 31, 2020, the Partnership had downward revisions of 1,098 MBbls of oil and 867 MMcf of gas and upward revisions of 65 MBbls of NGL. Total downward revisions of 1,178 MBOE were primarily due to downward revisions of 887 MBOE related to changes in estimated ultimate recovery and downward revisions of 239 MBOE due to decreases in pricing. For the year ended December 31, 2020, the Partnership had extensions of 995 MBbls of oil, 3,486 MMcf of gas, and 423 MBbls of NGLs of which 192 MBbls of oil, 672 MMcf of gas, and 81 MBbls of NGLs were from conversions of non-proved resources to proved developed producing due to operator drilling activity and 803 MBbls of oil, 2,814 MMcf of gas, and 342 MBbls of NGLs were from additional proved undeveloped reserves. In 2020, the Partnership acquired royalty and mineral interests of 445 MBbls of oil, 633 MMcf of gas, and 77 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2020, the Partnership divested royalty and mineral interests of 173 MBbls, 209 MMcf, and 26 MBbls of proved oil, natural gas, and NGL, respectively, in conjunction with the conveyances to DRC described in Note 5.

For the year ended December 31, 2019, the Partnership had downward revisions of 13 MBbls of oil, 34 MMcf of gas and 4 MBbls of NGL due to the removal of 11 wells that were no longer economically feasible. Additional downward revisions of 425 MBbls of oil and 18 MBbls of NGLs were largely due to decreases in pricing. Decreases in gas pricing were offset by positive performance revisions, resulting in an upward revision of 968 MMcf of gas. For the year ended December 31, 2019, the Partnership had extensions of 1,929 MBbls of oil, 6,214 MMcf of gas, and 704 MBbls of NGLs of which 837 MBbls of oil, 3,234 MMcf of gas, and 367 MBbls of NGLs were from conversions of non-proved resources to proved developed producing due to operator drilling activity and 1,092 MBbls of oil, 2,980 MMcf of gas, and 337 MBbls of NGLs were from additional proved undeveloped reserves. In 2019, the Partnership acquired royalty and mineral interests of 1,655 MBbls of oil, 4,904 MMcf of gas and 555 MBbls of NGLs through multiple acquisitions including the acquisition of DRC described in Note 5. For the year ended December 31, 2019, the Partnership divested royalty and mineral interests of 167 MBbls, 513 MMcf, and 58 MBbls of proved oil, gas and NGL, respectively, in conjunction with the conveyances to DRC described in Note 5.

Standardized Measure of Oil and Gas

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein include Texas margin tax and do not include the effect of estimated federal income tax expenses because the Partnership is not subject to federal income taxes.

As of December 31, 2021, the reserves are comprised of 48% crude oil, 32% natural gas and 20% NGL on an energy equivalent basis.

For the years ended December 31, 2021, 2020, and 2019, future cash inflows are calculated by applying the 12-month arithmetic average of the first-of-month price from January to December, of oil and gas relating to

the Partnership’s proved reserves, to the year-end quantities of those reserves. The values for the December 31, 2021, 2020, and 2019 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 45% of WTI for 2021, 28% of WTI for 2020 and 27% of WTI for 2019; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.


	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2021 (Average)	$	64.33	$	3.35	$	30.14
December 31, 2020 (Average)	$	36.28	$	1.02	$	11.01
December 31, 2019 (Average)	$	50.92	$	0.69	$	14.90

The standardized measure of discounted future net cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following summary sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):


	Year Ended December 31,
	2021			2020			2019
Future oil and natural gas sales	$	1,068,652		$	238,977		$	355,551
Future production costs		(90,137	)		(19,379	)		(28,178	)
Future income tax expense (1)		(5,302	)		(1,236	)		(1,852	)

Future net cash flows		973,213			218,362			325,521

10% annual discount		(437,910	)		(94,803	)		(142,296	)

Standardized measure of discounted future net cash flows	$	535,303		$	123,559		$	183,225

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):


	Year Ended December 31,
	2021			2020			2019
Balance at the beginning of the period	$	123,559		$	183,225		$	155,432
Net change in prices and production costs		119,993			(59,911	)		(38,177	)
Sales, net of production costs		(111,691	)		(41,043	)		(47,112	)
Extensions and discoveries		29,853			25,196			53,246
Acquisitions of reserves		326,192			9,137			43,946
Divestiture of reserves		—			(3,563	)		(5,795	)
Revisions of previous quantity estimates		43,843			(18,140	)		(6,414	)
Net change in income taxes (1)		(2,205	)		343			(150	)
Accretion of discount		12,426			18,427			15,632
Changes in timing and other		(6,667	)		9,888			12,617

Balance at the end of the period	$	535,303		$	123,559		$	183,225

(1)

The Company was not subject to U.S. federal income taxes for the years ended December 31, 2021, 2020, and 2019. Accordingly, no provision for income taxes has been provided in the Consolidated Statement of Operations. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2021, 2020, and 2019 would have been $3.8 million, $6.9 million, and $24.7 million, respectively. The unaudited pro forma standardized measure of discounted future net cash flows at December 31, 2021, 2020, and 2019 would have been $534.4 million, $120.0 million, and $169.8 million, respectively.