EX-99.5

EX-99.5 15 d319755dex995.htm EX-99.5 EX-99.5

Exhibit 99.5

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF DESERT PEAK

The following discussion and analysis should be read in conjunction with the audited consolidated financial statements and notes thereto for the years ended December 31, 2021, 2020 and 2019 of Kimmeridge Mineral Fund, L.P. (“Desert Peak,” “KMF,” “our,” or “we”) appearing as Exhibit 99.3 to this Current Report on Form 8-K (the “Form 8-K”), the interim unaudited condensed consolidated financial statements and notes thereto for the three months ended March 31, 2022 and 2021 appearing as Exhibit 99.4 to the Form 8-K, and the definitive proxy statement filed with the Securities and Exchange Commission (“SEC”) on May 5, 2022 (the “Proxy Statement”). The discussion and analysis should also be read together with the unaudited pro forma condensed consolidated combined financial information appearing as Exhibit 99.6 to this Form 8-K. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of Desert Peak prior to the consummation of the transactions contemplated by the Agreement and Plan of Merger (the “Merger Agreement”) between Sitio Royalties Corp. (formerly known as Falcon Minerals Corporation), Sitio Royalties Operating Partnership, LP, a Delaware limited partnership (formerly known as Falcon Minerals Operating Partnership, LP, “Sitio OpCo”), Ferrari Merger Sub A LLC, a Delaware limited liability company (“Merger Sub”), and DPM HoldCo, LLC, a Delaware limited liability company (“Desert Peak”), pursuant to which Merger Sub merged with and into Desert Peak (the “Merger”), with Desert Peak continuing as the surviving entity in the Merger as a wholly owned subsidiary of Sitio OpCo. The transactions contemplated by the Merger Agreement are referred to herein as the “Merger Transactions.”

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to several factors which include, but are not limited to market prices for oil, natural gas and natural gas liquids (“NGLs”), production volumes, estimates of proved reserves, capital for mineral acquisitions, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Form 8-K and those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in the Proxy Statement. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

As of March 31, 2022, we owned mineral and royalty interests representing 105,427 NRAs when adjusted to a 1/8th royalty. For the three months ended March 31, 2022, the average net daily production associated with our mineral and royalty interests was 11,387 BOE/d, consisting of 5,948 Bbls/d of oil, 18,826 Mcf/d of natural gas and 2,301 Bbls/d of NGLs. Since our formation in November 2016, we have accumulated our acreage position by making 180 acquisitions. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. Unlike owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs which reduce the amount of revenue we recognize. For the three months ended March 31, 2022, our production and ad valorem taxes were approximately $3.63 per BOE, relative to an average realized price of $63.38 per BOE. As a result, our operating margin and cash flows are higher, as a percentage of revenue, than those of traditional E&P companies. We do not anticipate engaging in any activities, other than acquisitions, that will incur capital costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to stockholders.

We have historically had two reportable segments: Oil and Gas Producing Activities and Water Service Operations.

The Oil and Gas Producing Activities segment is comprised of managing our mineral and royalty interests and related revenue streams, which principally consist of royalties from crude oil, natural gas and NGLs producing activities and revenues from lease bonuses, delay rentals and easements. We are not a producer, and our crude oil, natural gas and NGLs revenue is derived from a fixed percentage of the crude oil, natural gas and NGLs produced by E&P operators from the acreage underlying our interests, net of post-production expenses and taxes.

The Water Service Operations segment is comprised of our water supply assets and revenues. The income of this segment consists of the sale of water to various Permian Basin E&P operators produced from our water supply assets. In connection with the Merger Transactions, Desert Peak will not contribute the Water Service Operations business or assets, and we anticipate that the Post-Combination Company will have one reportable segment after completion of the Merger Transactions.

Recent Developments

Credit Facility

On October 8, 2021, KMF Land, LLC, a Delaware limited liability company (“KMF Land”), as borrower, Desert Peak, as parent, Bank of America, N.A., as the administrative agent and issuing bank, and certain lenders entered into that certain Amended and Restated Credit Agreement (as amended, restated, supplemented or otherwise modified and as in effect immediately prior to the Closing Date, the “Existing Credit Agreement”), pursuant to which the lenders thereunder made loans and other extensions of credit to the borrower thereunder.

On June 7, 2022 (the “Closing Date”), the Existing Credit Agreement was amended and restated in its entirety pursuant to a Second Amended and Restated Credit Agreement (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”) entered into by Sitio OpCo, as borrower, KMF Land, Bank of America, N.A., as the administrative agent and issuing bank, the lenders party thereto (the “Lenders”) and other financial institutions from time to time party thereto. The Credit Agreement has a scheduled maturity date in June 2026 and provides for an aggregate principal amount of up to $750 million. As of the Closing Date, the Credit Agreement had a $300 million borrowing base and $300 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15 million. Existing letters of credit in place under our revolving credit facility immediately prior to the Closing Date are continued and now deemed issued under and governed by the terms of the Credit Agreement. Please see the “—Our Revolving Credit Facility” for a description of the material terms of the Credit Agreement.

Acquisitions

As of March 31, 2022, we have evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 180 acquisitions from landowners and other mineral interest owners. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in the Permian Basin designed to increase our cash flows per share. In connection with the market conditions resulting from the COVID-19 pandemic, our acquisition activity saw a significant decline during 2020 but rebounded in 2021.

Production and Operations

Our average daily production during the three months ended March 31, 2022 and 2021 was 11,387 BOE/d (52% crude oil) and 4,885 BOE/d (43% crude oil), respectively. For the three months ended March 31, 2022, we received an average of $92.04 per Bbl of crude oil, $4.63 per Mcf of natural gas and $37.81 per Bbl of NGLs, for an average realized price of $63.38 per BOE. For the three months ended March 31, 2021, we received an average of $54.81 per Bbl of crude oil, $3.66 per Mcf of natural gas and $29.29 per Bbl of NGLs, for an average realized price of $37.42 per BOE.

Our average daily production during the years ended December 31, 2021, 2020 and 2019 was 6,989 BOE/d (49% crude oil), 5,764 BOE/d (44% crude oil) and 4,793 BOE/d (47% crude oil), respectively. For the year ended December 31, 2021, we received an average of $67.29 per Bbl of crude oil, $3.61 per Mcf of natural gas and $33.22 per Bbl of NGLs, for an average realized price of $46.47 per BOE. For the year ended December 31, 2020, we

received an average of $37.40 per Bbl of crude oil, $1.03 per Mcf of natural gas and $10.32 per Bbl of NGLs, for an average realized price before derivatives of $20.95 per BOE. For the year ended December 31, 2019, we received an average of $52.90 per Bbl of crude oil, $0.74 per Mcf of natural gas and $13.48 per Bbl of NGLs, for an average realized price of $29.09 per BOE.

As of March 31, 2022, we had 4,646 gross (37.974 net) producing horizontal wells on our acreage. Additionally, as of March 31, 2022, there were 712 gross (4.982 net) horizontal wells in various stages of drilling or completion and 439 gross active horizontal drilling permits on our acreage.

As of December 31, 2021, we had 4,459 gross (36.887 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2021, there were 659 gross (4.644 net) horizontal wells in various stages of drilling or completion and 533 active horizontal drilling permits on our acreage. As of December 31, 2020, we had 1,650 gross (17.767 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2020, there were 196 gross (2.123 net) horizontal wells in various stages of drilling or completion and 207 active horizontal drilling permits on our acreage. As of December 31, 2019, we had 1,270 gross (14.715 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2019, there were 321 gross (2.461 net) horizontal wells in various stages of drilling or completion and 133 active horizontal drilling permits on our acreage.

COVID-19 Pandemic

The initial outbreak of COVID-19 caused a 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 was somewhat alleviated in 2021 and 2022, with the increase in domestic vaccination programs and reduced spread of the COVID-19 virus contributing to an improvement in the economy and higher realized prices for commodities. Since mid-2020 through mid-2022, oil prices have generally improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, which have continued to inhibit a full global demand recovery. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Furthermore, although certain E&P operators of our mineral and royalty interests announced reductions to their capital budgets for 2021 and beyond in connection with the outbreak of COVID-19, many operators have resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices since mid-2020. Given the dynamic nature of these events, Desert Peak cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist and the impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.

The impact of recent developments in Ukraine

In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, has contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of $123.64 per barrel. This volatility could negatively impact commodity prices and cause rising inflation that could impact demand for refined products. Given the uncertain timing of a return of refined product demand to historical levels, the extent these events will have an impact on our results of operations is unclear. The geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. The Russian conflict with Ukraine continues to evolve, and the extent to which these events may impact our business, financial condition, liquidity, results of operations, and prospects will depend highly on future developments, which are very uncertain and cannot be predicted with confidence.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

•

volumes of oil, natural gas and NGLs produced;

•

number of rigs on our acreage and number of producing wells, spud wells and permitted wells;

•

commodity prices; and

•

Adjusted EBITDA.

Volumes of Oil, Natural Gas and NGLs Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Number of Rigs on our Acreage, Spud Wells and Permitted Wells

In order to track and assess the performance of our assets, we monitor and analyze the number of rigs currently drilling on our properties. We also constantly monitor the number of permitted wells, spud wells, completions, and producing wells on our mineral and royal interests in an effort to evaluate near-term production growth.

Commodity Prices

Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a low of negative ($36.98) per barrel in April 2020 to a high of $123.64 per barrel in March 2022. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically.

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Natural Gas. The New York Mercantile Exchange, Inc. (“NYMEX”) price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP supplemental financial measure used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We define Adjusted EBITDA as net income (loss) including noncontrolling interests plus (i) interest expense, (ii) provisions for taxes, (iii) depreciation, depletion and amortization, (iv) share-based compensation expense, (v) impairment of oil and natural gas properties, (vii) gains or losses on unsettled derivative instruments, (viii) write off of deferred offering costs, (ix) management fee to affiliates, and (x) one-time transaction costs. Adjusted EBITDA is not a measure determined by GAAP.

This non-GAAP financial measure does not represent and should not be considered an alternative to, or more meaningful than, its most directly comparable GAAP financial measure or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

Sources of Revenue

Our revenues are primarily derived from mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas and NGLs production from our interests. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix and volumes of production sold by our E&P operators. For the three months ended March 31, 2022 and 2021, mineral and royalty revenue made up 98% and 97%, respectively, of our total revenue. For the years ended December 31, 2021, 2020 and 2019, mineral and royalty revenue made up 98%, 102% and 85%, respectively, of our total revenue. Mineral and royalty revenues made up more than 100% of our total revenues in 2020 due to the impact of commodity derivative losses on our total revenues. As a result of our royalty income production mix, our income is more sensitive to fluctuations in crude oil prices than it is to fluctuations in natural gas or NGLs prices.

Royalties received related to crude oil sales constituted 76% and 63% of total mineral and royalty revenue for the three months ended March 31, 2022 and 2021, respectively. Royalties received related to crude oil sales constituted 72%, 79% and 85% of total mineral and royalty revenue for the years ended December 31, 2021, 2020 and 2019, respectively. Crude oil, natural gas and NGL prices have historically been volatile, and we expect this volatility to continue.

Additionally, we earn lease bonus income by leasing our mineral interests to exploration and production companies and income from delay rentals and easements. Lease bonus and other income constituted 2% and 3%, respectively, of our total revenue for the three months ended March 31, 2022 and 2021. Lease bonus and other income constituted 2%, 2% and 9%, respectively, of our total revenue for the years ended December 31, 2021, 2020 and 2019.

Further, we earned revenue through the provision of water to various Permian Basin E&P operators produced from our water supply assets. For the years ended December 31, 2021 and 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement was terminated in October 2021 and no longer constitutes a leasing arrangement. Contingent rental income earned under this arrangement was $0 and $202,000, respectively, for the three months ended March 31, 2022 and 2021. Contingent rental income earned under this arrangement was $205,000 and $13,000 for the years ended December 31, 2021 and 2020, respectively. Water sales were $3.5 million for the year ended December 31, 2019.

Principal Components of Our Cost Structure

The following is a description of the principal components of our cost structure. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs, which reduce the amount of revenue we recognize. Unlike E&P operators and owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production.

Production and Ad Valorem Taxes

Production taxes are paid at fixed rates on produced crude oil and natural gas based on a percentage of revenues from products sold, established by federal, state or local taxing authorities. The E&P companies who operate on our interests withhold and pay our pro rata share of production taxes on our behalf. We directly pay ad valorem taxes in the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas and NGLs properties.

Gathering, Processing and Transportation Costs

Gathering, processing and transportation costs are representative of the costs to process and transport our respective volumes to applicable sales points. The terms of the lease with the applicable E&P operator on our interests determine if the operator is able to pass through these costs to us by deducting a pro rata portion of such costs from our production revenues.

General and Administrative

General and administrative expenses consist of costs incurred related to overhead, including executive and other employee compensation and related benefits, office expenses and fees for professional services such as audit, tax, legal and other consulting services. Some of those costs were incurred on our behalf by our general partner and its affiliates and reimbursed by Desert Peak. For example, we reimburse an affiliate of our general partner for personnel costs on our behalf. As a result of becoming a public company, we anticipate incurring incremental general and administrative expenses relating to SEC reporting requirements, including annual and quarterly reports, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our common stock, independent auditor fees, legal expenses and investor relations expenses. These incremental general and administrative expenses are not reflected in the historical financial statements or the unaudited pro forma financial statements included as exhibits to the Form 8-K.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of capitalized costs. Under the successful efforts method of accounting, capitalized costs of our proved crude oil, natural gas and NGLs mineral interest properties are depleted on a unit-of-production basis based on proved crude oil, natural gas and NGLs reserve quantities. Our estimates of crude oil, natural gas and NGLs 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. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas and NGLs properties. DD&A also includes the expensing of office leasehold costs and water wells and equipment.

Income Tax Expense

We are subject to the Texas margin tax, which is a state franchise tax, and certain state income taxes. We incurred $0.5 million and $81,000 for the three months ended March 31, 2022 and 2021, respectively, for state income taxes. For the years ended December 31, 2021, 2020 and 2019, we incurred $0.6 million, $38,000 and $0.2 million, respectively, for state franchise tax payable to the Texas Comptroller of Public Accounts and other certain state income taxes. Desert Peak did not record a provision for U.S. federal income taxes because the partners reported their respective share of our income or loss on their income tax returns. Following the events comprising the Merger Transactions described in the Form 8-K, we will be subject to U.S. federal income taxes as a corporation. We will also continue to be subject to the Texas margin tax as a corporation.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.

Surface Rights

The historical consolidated financial statements included as exhibits to the Form 8-K are based on our financial statements prior to the Merger Transactions. The assets to be acquired in connection with the Merger Transactions will not include KMF’s surface rights, which generate revenue from the sale of water, payments for rights-of-way and other rights associated with the ownership of the surface acreage, which are included in our historical financial statements but will be retained by KMF following the closing of the Merger Transactions. As a result, the historical consolidated financial data may not give you an accurate indication of what the actual results would have been if the Merger Transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Management Fees

KMF incurred and paid annual fees under an investment management agreement with Kimmeridge Energy Management Company, LLC, an affiliate of Kimmeridge, of which Noam Lockshin, a Director Nominee, is a managing member. Fees incurred under the agreement totaled approximately $1.9 million for the three months ended March 31, 2022 and 2021. Fees incurred under the agreement totaled approximately $7.5 million for the years ended December 31, 2021, 2020 and 2019, respectively. We will not incur future expense under the agreement upon completion of the Merger Transactions. Additionally, certain other expenses associated with the limited partnership structure of Desert Peak will not be incurred by us in future periods.

Acquisitions

Our historical financial statements as of and for the years ended December 31, 2020 and 2019 or the three months ended March 31, 2021 do not include the results of operations for the assets acquired in the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition. Our historical financial statements as of and for the year ended, subsequent to the respective acquisition dates, December 31, 2021 include the results of operations for the assets acquired in the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition. As a result, our historical financial data as of and for the years ended December 31, 2020 and 2019 and for the year ended December 31, 2021 does not give an accurate indication of what the actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be. For additional information, please see the unaudited pro forma condensed combined financial statements and related notes included as Exhibit 99.6 to the Form 8-K.

In addition, we plan to pursue potential accretive acquisitions of additional mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to stockholders.

Debt and Interest Expense

We had no debt until September 26, 2019, when we established our original credit facility. As a public company, we may finance a portion of our acquisitions with borrowings under our revolving credit facility. As a result, we will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Public Company Expenses

Following the closing of the Merger Transactions, we anticipate incurring incremental general and administrative expenses as a result of Kimmeridge no longer providing services to us and as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and

quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our common stock, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in our historical financial statements. Additionally, in anticipation of the Merger Transactions, we have hired additional employees, including accounting, engineering and land personnel, in order to prepare for the requirements of being a publicly traded company.

Income Taxes

We will be subject to U.S. federal and state income taxes as a corporation. KMF was generally not subject to U.S. federal income tax at the entity level. As such, our financial statements do not contain a provision for U.S. federal income taxes. The only tax expense that appeared in our financial statements was the Texas margin tax and certain state income taxes, to which we will continue to be subject as a corporation.

Results of Operations

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

Consolidated Results

The following table summarizes our consolidated revenue and expenses and production data for the three months ended March 31, 2022 and 2021 (in thousands):


	For the three months ended March 31,
	2022			2021
Statement of Operations Data:
Revenue:
Total Revenue	$	66,363		$	17,049
Operating Expenses:
Management fees to affiliates	$	1,870		$	1,870
Depreciation, depletion and amortization		15,385			6,865
General and administrative		3,983			703
General and administrative—affiliates		80			1,638
Severance and ad valorem taxes		3,725			1,110
Total operating expenses		25,043			12,186

Net income from operations		41,320			4,863

Interest expense (net)(1)		(1,168	)		(306	)
Commodity derivative losses		(1,114	)		—
Net income before income tax expense		39,038			4,557
Income tax expense		(516	)		(81	)

Net income including noncontrolling interests		38,522			4,476
Net income attributable to noncontrolling interests		19,242			—

Net income	$	19,280		$	4,476


	For the three months ended March 31,
	2022		2021
Production Data:
Crude oil (Mbbls)		535		189
Natural gas (Mmcf)		1,694		1,025
NGLs (Mbbls)		207		79

Total (BOE)(6:1)		1,025		440

Average daily production (BOE/d)(6:1)		11,387		4,885
Average Realized Prices:
Crude oil (per Bbl)	$	92.04	$	54.81
Natural gas (per Mcf)	$	4.63	$	3.66
NGLs (per Bbl)	$	37.81	$	29.29
Combined (per BOE)	$	63.38	$	37.42
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)	$	92.04	$	54.81
Natural gas (per Mcf)	$	4.63	$	3.66
NGLs (per Bbl)	$	37.81	$	29.29
Combined (per BOE)	$	63.38	$	37.42

(1)	Interest expense is presented net of interest income.

Revenue

Our consolidated revenues for the three months ended March 31, 2022 totaled $66.4 million as compared to $17.0 million for the three months ended March 31, 2021, an increase of 289%. The increase in revenues was due to an increase of $48.6 million in mineral and royalty revenue and an increase of $0.8 million in lease bonus and other income. The increase in mineral and royalty revenue was primarily due to increased commodity prices, production volumes from our acquisitions of additional mineral and royalty interests, and production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement was terminated in October 2021 and no longer constitutes a leasing arrangement. Contingent rental income earned under this arrangement was $202,000 for the three months ended March 31, 2021. There was no income earned under this arrangement for the three months ended March 31, 2022.

Our Oil and Gas Producing Activities segment generated 100% and 99% of our total revenues for the three months ended March 31, 2022 and 2021, respectively, with our Water Service Operations segment contributing a de minimis amount of our total revenues for the three months ended March 31, 2022.

Oil revenue for the three months ended March 31, 2022 was $49.3 million as compared to $10.4 million for the three months ended March 31, 2021, an increase of $38.9 million. An increase of $37.23/Bbl in our average price received for oil production, from $54.81/Bbl for the three months ended March 31, 2021 to $92.04/Bbl for the three months ended March 31, 2022, accounted for an approximate $19.9 million increase in our year-over-year oil revenue. Additionally, we realized a $19.0 million increase in year-over-year oil revenue due to a 183% increase in oil production volumes, which increased from 189 Mbbls for the three months ended March 31, 2021 to 535 Mbbls for the three months ended March 31, 2022.

Natural gas revenue for the three months ended March 31, 2022 was $7.8 million as compared to $3.7 million for the three months ended March 31, 2021, an increase of $4.1 million. An increase of $0.97/Mcf in our average price received for gas production, from $3.66/Mcf for the three months ended March 31, 2021 to $4.63/Mcf for the three months ended March 31, 2022, accounted for an approximate $1.7 million increase in our year-over-year gas revenue. Additionally, we realized a $2.4 million increase in year-over-year gas revenue due to a 65% increase in gas production volumes, which increased from 1,025 MMcf for the three months ended March 31, 2021 to 1,694 MMcf for the three months ended March 31, 2022.

NGLs revenue for the three months ended March 31, 2022 was $7.8 million as compared to $2.3 million for the three months ended March 31, 2021, an increase of $5.5 million. An increase of $8.52/Bbl in our average price received for NGLs production, from $29.29/Bbl for the three months ended March 31, 2021 to $37.81/Bbl for the three months ended March 31, 2022, accounted for an approximate $1.8 million increase in our year-over-year NGLs revenue. Additionally, we realized a $3.7 million increase in year-over-year NGLs revenue due to a 161% increase in NGLs production volumes, which increased from 79 MBbls for the three months ended March 31, 2021 to 207 MBbls for the three months ended March 31, 2022.

Lease bonus revenue for the three months ended March 31, 2022 was $1.2 million as compared to $41,000 for the three months ended March 31, 2021. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the three months ended March 31, 2022 were $180,000 as compared to $555,000 for the three months ended March 31, 2021, which include payments for right-of-way and surface damages, which are also subject to significant variability.

Operating Expenses

Management fees to affiliates expense remained consistent at $1.9 million for the three months ended March 31, 2022 and 2021.

Depreciation, depletion and amortization expense was $15.4 million for the three months ended March 31, 2022 as compared to $6.9 million for the three months ended March 31, 2021, an increase of $8.5 million, or 124%. The increase was primarily due to 133% increase in year-over-year production offset by a lower depletion rate, which decreased from $15.28/Boe for the three months ended March 31, 2021 to $14.87/Boe for the three months ended March 31, 2022.

General and administrative expense was $4.0 million for the three months ended March 31, 2022 as compared to $703,000 for the three months ended March 31, 2021, an increase of $3.3 million, or 467%. The increase was primarily due to increased personnel costs captured here for the three months ended March 31, 2022, public transaction costs related to the Merger Transactions, and professional services costs noted below.

General and administrative—affiliates expense was $80,000 for the three months ended March 31, 2022 as compared to $1.6 million for the three months ended March 31, 2021, a decrease of $1.5 million, or 95%. The decrease was primarily a result of decreased reimbursement to our general partner for services provided on our behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of mineral and royalty interests. These costs were captured in the General and administrative expense line item for the first three months of 2022.

On a combined basis, the General and administrative expense and General and administrative expense— affiliates expense was $4.1 million for the three months ended March 31, 2022 as compared to $2.3 million for the three months ended March 31, 2021, an increase of $1.8 million, or 74%, primarily due to $1.2 million of transaction costs related to the Merger Transactions, $0.2 million of employee compensation due in increased headcount, $0.1 million of additional rent expense, and $0.3 million of other professional services.

Severance and ad valorem taxes was $3.7 million for the three months ended March 31, 2022 as compared to $1.1 million for the three months ended March 31, 2021, an increase of $2.6 million or 236%. The increase was primarily due to an increase in severance taxes in conjunction with the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests and existing interests.

Interest expense of approximately $1.2 million and $0.3 million during the three months ended March 31, 2022 and 2021, respectively, relates to interest incurred on borrowings under our revolving credit facility. The increase in interest expense was due to higher average borrowings under the facility during the three months ended March 31, 2022 as compared to March 31, 2021 due to funding acquisitions and distributions to the members of DPM HoldCo in the second half of 2021.

Commodity derivatives losses totaled $1.1 million for the three months ended March 31, 2022, whereas there were no derivatives gains or losses for the three months ended March 31, 2021. In 2022, we entered into oil and gas fixed price swaps to manage commodity price risks associated with our production.

Income tax expense primarily relates to state franchise taxes and certain state income taxes, and totaled approximately $0.5 million and $81,000 for the three months ended March 31, 2022 and 2021, respectively.

Segment Results

The following table sets forth certain financial information with respect to our reportable segments (in thousands):


	For the three months ended March 31, 2022
	Oil and Gas Producing Activities			Water Service Operations		Partnership			Consolidated Total
Revenues	$	66,261		$	102	$	—		$	66,363
Depreciation, depletion and amortization		15,313			72		—			15,385
Income tax expense		(491	)		—		(25	)		(516	)
Interest expense		(1,176	)		—		—			(1,176	)
Segment profit (loss)		40,446			21		(1,953	)		38,514
Total assets as of March 31, 2022		1,199,215			3,250		2,120			1,204,585
Capital expenditures, including mineral acquisitions		676			—		—			676

A reconciliation of segment profit to net income is as follows:


Segment profit	$	38,514
Interest income		8
Net income attributable to noncontrolling interests		19,242
Net income attributable to partners		19,280


	For the three months ended March 31, 2021
	Oil and Gas Producing Activities			Water Service Operations		Partnership			Consolidated Total
Revenues	$	16,847		$	202	$	—		$	17,049
Depreciation, depletion and amortization		6,793			72		—			6,865
Income tax expense		(81	)		—		—			(81	)
Interest expense		(307	)		—		—			(307	)
Segment profit (loss)		6,259			130		(1,914	)		4,475
Total assets as of March 31, 2021		588,979			3,529		2,143			594,651
Capital expenditures (reimbursements), including mineral acquisitions		(105	)		—		—			(105	)

A reconciliation of segment profit to net income is as follows:


Segment profit	$	4,475
Interest income		1
Net income attributable to noncontrolling interests		—
Net income attributable to partners		4,476

Oil and Gas Producing Activities

The following table presents the breakdown of our royalty revenues attributable to sales of crude oil, natural gas and NGLs totaling approximately $65.0 million and $16.5 million for the three months ended March 31, 2022 and 2021, respectively:


	Three months ended March 31,
	2022			2021
Royalty Revenue
Crude oil sales		76	%		63	%
Natural gas sales		12	%		23	%
NGLs sales		12	%		14	%

Total Royalty Revenue		100	%		100	%

Our oil and gas producing activities segment revenues are primarily a function of crude oil, natural gas, and NGLs production volumes sold and average prices received for those volumes, each of which can vary significantly from period to period. Despite such variability, we expect our royalty revenues to continue to be primarily attributable to crude oil sales.

Operating expenses for the oil and gas producing activities segment totaled approximately $23.0 million for the three months ended March 31, 2022, and consisted primarily of depreciation, depletion and amortization of $15.3 million, employee compensation and benefits of $1.9 million, general and administrative of $2.1 million, and severance and ad valorem taxes of $3.7 million.

Operating expenses for the oil and gas producing activities segment totaled approximately $10.2 million for the three months ended March 31, 2021, and consisted primarily of depreciation, depletion and amortization of $6.8 million, production and ad valorem taxes of $1.1 million, employee compensation and benefits of $1.6 million, and general and administrative of $0.7 million.

Income tax expense attributable to the oil and gas producing activities segment primarily relate to state franchise taxes and state income taxes, and totaled approximately $0.5 million and $81,000 for the three months ended March 31, 2022 and 2021, respectively.

Water Service Operations

In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer. Contingent rental income earned under this arrangement was $0.2 million for the three months ended March 31, 2021. There was no income earned under this arrangement for the three months ended March 31, 2022. In October 2021, the agreement was terminated.

Operating expenses totaled approximately $81,000 and $72,000 for the three months ended March 31, 2022 and 2021, respectively, and consisted primarily of depreciation, depletion and amortization and employee compensation.

Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020

Consolidated Results

The following table summarizes our consolidated revenue and expenses and production data for the years ended December 31, 2021 and 2020 (in thousands):


	For the year ended December 31,
	2021			2020
Statement of Operations Data:
Revenue:
Total Revenue	$	120,588		$	43,126
Operating Expenses:
Management fees to affiliates	$	7,480		$	7,480
Depreciation, depletion and amortization		40,906			32,049
General and administrative		4,143			4,981
General and administrative—affiliates		8,855			4,407
Impairment of oil and natural gas properties		—			812
Severance and ad valorem taxes		6,858			3,151
Deferred offering costs write off		2,396			2,747
Bad debt recovered		—			(251	)
Gain on sale of other property		—			(42	)
Total operating expenses		70,638			55,334

Net income (loss) from operations		49,950			(12,208	)

Interest expense (net)(1)		(1,893	)		(1,968	)
Net income (loss) before income tax expense		48,057			(14,176	)
Income tax expense		(562	)		(38	)

Net income (loss) including noncontrolling interests		47,495			(14,214	)
Net income attributable to noncontrolling interests		18,781			—

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


	For the year ended December 31,
	2021		2020
Production Data:
Crude oil (Mbbls)		1,261		933
Natural gas (Mmcf)		4,746		4,134
NGLs (Mbbls)		499		488

Total (BOE)(6:1)		2,551		2,110

Average daily production (BOE/d)(6:1)		6,989		5,764
Average Realized Prices:
Crude oil (per Bbl)	$	67.29	$	37.40
Natural gas (per Mcf)	$	3.61	$	1.03
NGLs (per Bbl)	$	33.22	$	10.32
Combined (per BOE)	$	46.47	$	20.95
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)	$	67.29	$	34.64
Natural gas (per Mcf)	$	3.61	$	1.03
NGLs (per Bbl)	$	33.22	$	10.32
Combined (per BOE)	$	46.47	$	19.73

(1)	Interest expense is presented net of interest income.

Revenue

Our consolidated revenues for the year ended December 31, 2021 totaled $120.6 million as compared to $43.1 million for the year ended December 31, 2020, an increase of 180%. The increase in revenues was due to an increase of $74.4 million in mineral and royalty revenue, an increase of $0.5 million in lease bonus and other income, and a commodity derivative loss of $2.6 million in 2020. The increase in mineral and royalty revenue was primarily due to increased commodity prices, increased production volumes from our acquisitions of additional mineral and royalty interests, and increased production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. Contingent rental income earned under this arrangement was $0.2 million and $13,000 for the years ended December 30, 2021 and 2020, respectively. The agreement was terminated in October 2021.

Our Oil and Gas Producing Activities segment generated approximately 100% of our total revenues for the years ended December 31, 2021 and 2020, with our Water Service Operations segment contributing a de minimis amount of our total revenues for the years ended December 31, 2021 and 2020.

Oil revenue for the year ended December 31, 2021 was $84.8 million as compared to $34.9 million for the year ended December 31, 2020, an increase of $49.9 million. An increase of $29.89/Bbl in our average price received for oil production, from $37.40/Bbl for the year ended December 31, 2020 to $67.29/Bbl for the year ended December 31, 2021, accounted for an approximate $37.7 million increase in our year-over-year oil revenue. Additionally, we realized a $12.2 million increase in year-over-year oil revenue due to a 35% increase in oil production volumes, which increased from 933 Mbbls for the year ended December 31, 2020 to 1,261 Mbbls for the year ended December 31, 2021.

Natural gas revenue for the year ended December 31, 2021 was $17.1 million as compared to $4.3 million for the year ended December 31, 2020, an increase of $12.8 million. An increase of $2.58/Mcf in our average price received for gas production, from $1.03/Mcf for the year ended December 31, 2020 to $3.61/Mcf for the year ended December 31, 2021, accounted for an approximate $12.2 million increase in our year-over-year gas revenue. Additionally, we realized a $0.6 million increase in year-over-year gas revenue due to a 15% increase in gas production volumes, which increased from 4,134 MMcf for the year ended December 31, 2020 to 4,746 MMcf for the year ended December 31, 2021.

NGLs revenue for the year ended December 31, 2021 was $16.6 million as compared to $5.0 million for the year ended December 31, 2020, an increase of $11.6 million. An increase of $22.90/Bbl in our average price received for NGLs production, from $10.32/Bbl for the year ended December 31, 2020 to $33.22/Bbl for the year ended December 31, 2021, accounted for an approximate $11.5 million increase in our year-over-year NGLs revenue, and a $0.1 million increase in year-over-year NGLs revenue due to a 2% increase in NGLs production volumes, which increased from 488 MBbls for the year ended December 31, 2020 to 499 MBbls for the year ended December 31, 2021.

Lease bonus revenue for the year ended December 31, 2021 was $1.2 million as compared to $0.7 million for the year ended December 31, 2020. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the years ended December 31, 2021 and 2020, were $0.8 million, which include payments for right-of-way and surface damages, which are also subject to significant variability.

Operating Expenses

Management fees to affiliates expense remained consistent at $7.5 million for the years ended December 31, 2021 and 2020.

Depreciation, depletion and amortization expense was $40.9 million for the year ended December 31, 2021 as compared to $32.0 million for the year ended December 31, 2020, an increase of $8.9 million, or 28%. The increase was primarily due to our 21% increase in year-over-year production as well as a higher depletion rate, which increased from $14.90/Boe for the year ended December 31, 2020 to $15.80/Boe for the year ended December 31, 2021 due to reserves increasing at a slower rate than our net depletable capitalized costs from December 31, 2020 to December 31, 2021.

General and administrative expense was $4.1 million for the year ended December 31, 2021 as compared to $5.0 million for the year ended December 31, 2020, a decrease of $0.9 million, or 17%. The decrease was primarily due to decreased personnel costs captured here for the first half of 2020 as noted below and professional services costs.

General and administrative—affiliates expense was $8.9 million for the year ended December 31, 2021 as compared to $4.4 million for the year ended December 31, 2020, an increase of $4.5 million, or 101%. The increase was primarily a result of increased reimbursement to our general partner for services provided on our behalf, including personnel costs.. These costs were captured in the general and administrative expense line item for the first half of 2020.

On a combined basis, the general and administrative expense and general and administrative expense— affiliates expense was $13.0 million for the year ended December 31, 2021 as compared to $9.4 million for the year ended December 31, 2020, an increase of $3.6 million, or 38%. The increase was a result of increased reimbursement to our general partner for services provided on our behalf, including personnel costs.

Impairment of oil and gas properties of approximately $0.8 million for the year ended December 31, 2020 was recognized in connection with capitalized acquisition costs for a prospective mineral interest acquisition that we did not complete. We did not recognize impairment of oil and gas properties for the year ended December 31, 2021.

Severance and ad valorem taxes was $6.9 million for the year ended December 31, 2021 as compared to $3.2 million for the year ended December 31, 2020, an increase of $3.7 million or 118%. The increase was primarily due to an increase in severance taxes in conjunction with the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests.

During the years ended December 31, 2021 and 2020, we recognized approximately $2.4 million and $2.7 million of expense, respectively, in connection with the cancelation of an initial public offering.

During the year ended December 31, 2020, we reversed approximately ($0.3) million of bad debt expense due to the collection of accounts receivable of KMF Water for which an allowance had previously been established. No such charges or benefits were recorded during the year ended December 31, 2021.

Interest expense of approximately $1.9 million and $2.0 million during the years ended December 31, 2021 and 2020, respectively, relates to interest incurred on borrowings under our revolving credit facility. The decrease in interest expense was due to lower average borrowings under the facility during the majority of the year ended December 31, 2021 as we continued to make payments to reduce the outstanding balance throughout 2020 and into 2021. During the second half of 2021, we funded acquisitions and the distributions to the members of DPM HoldCo with increased borrowings.

Income tax expense primarily relates to state franchise taxes and totaled approximately $0.6 million and $38,000 for the years ended December 31, 2021 and 2020, respectively.

Segment Results

The following table sets forth certain financial information with respect to our 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 profit (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	)

Oil and Gas Producing Activities

The following table presents the breakdown of our royalty revenues attributable to sales of crude oil, natural gas and NGLs totaling approximately $118.5 million and $44.2 million for the year ended December 31, 2021 and 2020, respectively:


	Year ended December 31,
	2021			2020
Royalty Revenue
Crude oil sales		72	%		79	%
Natural gas sales		14	%		10	%
NGLs sales		14	%		11	%

Total Royalty Revenue		100	%		100	%

Commodity derivatives losses totaled $2.6 million for the year ended December 31, 2020, whereas there were no derivatives gains or losses for the year ended December 31, 2021. In 2020, we entered into oil fixed price swaps and oil basis swaps to manage commodity price risks associated with our production. In October 2020, we terminated all of our outstanding oil and basis swap derivative contracts. We were not party to any derivative contracts as of December 31, 2021 and 2020.

Operating expenses for the oil and gas producing activities segment totaled approximately $62.5 million for the year ended December 31, 2021, and consisted primarily of depreciation, depletion and amortization of $40.6 million, employee compensation and benefits of $8.6 million, general and administrative of $4.0 million, production and ad valorem taxes of $6.9 million, and write off of deferred offering costs of $2.4 million.

Operating expenses for the oil and gas producing activities segment totaled approximately $47.3 million for the year ended December 31, 2020, and consisted primarily of depreciation, depletion and amortization of $31.7 million, employee compensation and benefits of $6.1 million, general and administrative of $2.8 million, write off of deferred offering costs of $2.7 million, impairment of unproved oil and gas properties of $0.8 million, and production and ad valorem taxes of $3.2 million.

Income tax expense attributable to the oil and gas producing activities segment primarily relate to state franchise taxes, and totaled approximately $0.6 million and $38,000 for the year ended December 31, 2021 and 2020, respectively.

Water Service Operations

For the year ended December 31, 2021 and 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer. Contingent rental income earned under this arrangement was $0.2 million and $13,000 for the years ended December 31, 2021 and 2020, respectively. In October 2021, the agreement was terminated.

Operating expenses totaled approximately $0.3 million and $0.2 million for the years ended December 31, 2021 and 2020, respectively, and consisted primarily of depreciation, depletion and amortization and employee compensation.

Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Consolidated Results

The following table summarizes our consolidated revenue and expenses and production data for the years ended December 31, 2020 and 2019 (in thousands):


	For the year ended December 31,
	2020			2019
Statement of Operations Data:
Revenue:
Total Revenue	$	43,126		$	59,680
Operating Expenses:
Management fees to affiliates	$	7,480		$	7,480
Depreciation, depletion and amortization		32,049			26,201
General and administrative		4,981			2,349
General and administrative—affiliates		4,407			8,167
Impairment of oil and natural gas properties		812			—
Production costs, ad valorem taxes and operating expense		3,151			5,249
Deferred offering costs write off		2,747			—
Bad debt expense (recovered)		(251	)		405
Gain on sale of other property		(42	)		—

Total operating expenses		55,334			49,851

Net income (loss) from operations		(12,208	)		9,829
Interest expense (net)(1)		(1,968	)		(868	)
Net income (loss) before income tax expense		(14,176	)		8,961
Income tax expense		(38	)		(171	)

Net income (loss)	$	(14,214	)	$	8,790


	For the year ended December 31,
	2020		2019
Production Data:
Crude oil (Mbbls)		933		816
Natural gas (Mmcf)		4,134		3,237
NGLs (Mbbls)		488		393

Total (BOE)(6:1)		2,110		1,749

Average daily production (BOE/d)(6:1)		5,764		4,793
Average Realized Prices:
Crude oil (per Bbl)	$	37.40	$	52.90
Natural gas (per Mcf)	$	1.03	$	0.74
NGLs (per Bbl)	$	10.32	$	13.48
Combined (per BOE)	$	20.95	$	29.09
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)	$	34.64	$	52.90
Natural gas (per Mcf)	$	1.03	$	0.74
NGLs (per Bbl)	$	10.32	$	13.48
Combined (per BOE)	$	19.73	$	29.09

(1)	Interest expense is presented net of interest income.

Revenue

Our consolidated revenues for the year ended December 31, 2020 totaled $43.1 million as compared to $59.7 million for the year ended December 31, 2019, a decrease of 28%. The decrease in revenues was due to a decrease of $6.7 million in mineral and royalty revenue, a decrease of $3.8 million in lease bonus and other income, a $3.5 million decrease in water sales revenue, and a commodity derivative loss of $2.6 million in 2020. The decrease in mineral and royalty revenue was primarily due to decreased commodity prices. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. For the year ended December 31, 2020, there were no water sales, whereas we generated total water revenues of $3.5 million for the year ended December 31, 2019. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. Contingent rental income earned under this arrangement was $13,000 for the year ended December 31, 2020, as compared to the $3.5 million of water sales revenue for the year ended December 31, 2019, primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

Our Oil and Gas Producing Activities segment generated 100% and 94% of our total revenues for the years ended December 31, 2020 and 2019, respectively, with our Water Service Operations segment representing the remaining 0% and 6%, respectively.

Oil revenue for the year ended December 31, 2020 was $34.9 million as compared to $43.2 million for the year ended December 31, 2019, a decrease of $8.3 million. A decrease of $15.50/Bbl in our average price received for oil production, from $52.90/Bbl for the year ended December 31, 2019 to $37.40/Bbl for the year ended December 31, 2020, accounted for an approximate $14.5 million decrease in our year-over-year oil revenue, which was partially offset by an approximate $6.2 million increase in year-over-year oil revenue due to a 14% increase in oil production volumes, which increased from 816 Mbbls for the year ended December 31, 2019 to 933 Mbbls for the year ended December 31, 2020.

Natural gas revenue for the year ended December 31, 2020 was $4.3 million as compared to $2.4 million for the year ended December 31, 2019, an increase of $1.9 million. A 28% increase in gas production volumes, from 3,238 MMcf for the year ended December 31, 2019 to 4,134 MMcf for the year ended December 31, 2020, accounted for an approximate $0.7 million increase in year-over-year gas revenue and an increase of $0.29/Mcf in our average price received for gas production, from $0.74/Mcf for the year ended December 31, 2019 to $1.03 for the year ended December 31, 2020, accounted for an approximate $1.2 million increase in our year-over-year gas revenue.

NGLs revenue for the year ended December 31, 2020 was $5.0 million as compared to $5.3 million for the year ended December 31, 2019, a decrease of $0.3 million. A decrease of $3.16/Bbl in our average price received for NGLs production, from $13.48/Bbl for the year ended December 31, 2019 to $10.32/Bbl for the year ended December 31, 2020, accounted for an approximate $1.5 million decrease in our year-over-year NGLs revenue, which was partially offset by an approximate $1.2 million increase in year-over-year NGLs revenue due to a 24% increase in NGLs production volumes, which increased from 393 Mbbls for the year ended December 31, 2019 to 488 Mbbls for the year ended December 31, 2020.

Lease bonus revenue for the year ended December 31, 2020 was $0.7 million as compared to $2.8 million for the year ended December 31, 2019. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the year ended December 31, 2020 was $0.8 million as compared to $2.5 million for the year ended December 31, 2019 which include payments for right-of-way and surface damages, which are also subject to significant variability.

Operating Expenses

Management fees to affiliates expense remained consistent at $7.5 million for the years ended December 31, 2020 and 2019.

Depreciation, depletion and amortization expense was $32.0 million for the year ended December 31, 2020 as compared to $26.2 million for the year ended December 31, 2019, an increase of $5.8 million, or 22%. The increase was primarily due to a 21% increase in year-over-year production with the remaining 1% increase due to a higher depletion rate, which increased from $14.68/Boe for the year ended December 31, 2019 to $14.90/Boe for the year ended December 31, 2020 due to reserves decreasing at a higher rate than our net depletable capitalized costs from December 31, 2019 to December 31, 2020.

General and administrative expense was $5.0 million for the year ended December 31, 2020 as compared to $2.3 million for the year ended December 31, 2019, an increase of $2.7 million, or 112%. The increase was primarily due to increased personnel costs captured here for the first half of 2020 as noted below and professional services costs.

General and administrative—affiliates expense was $4.4 million for the year ended December 31, 2020 as compared to $8.2 million for the year ended December 31, 2019, a decrease of $3.8 million, or 46%. The decrease was primarily as a result of decreased reimbursement to our general partner for services provided on our behalf, including personnel costs. These costs were captured in the general and administrative expense line item for the first half of 2020. On a combined basis, the general and administrative expense and general and administrative expense—affiliates expense was $9.4 million for the year ended December 31, 2020 as compared to $10.5 million for the year ended December 31, 2019, a decrease of $1.1 million, or 11%, primarily due to decreased employee compensation and other cost-saving measures enacted in 2020 in connection with the depressed commodity price environment.

Impairment of oil and gas properties of approximately $0.8 million during the year ended December 31, 2020 was recognized in connection with capitalized acquisition costs for a prospective mineral interest acquisition that we did not complete.

Production costs, ad valorem taxes and operating expense was $3.2 million for the year ended December 31, 2020 as compared to $5.2 million for the year ended December 31, 2019, a decrease of $2.0 million or 40%. The decrease was primarily due to decreased operating expense for the water service operations segment, which was primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

During the year ended December 31, 2020, we recognized approximately $2.7 million of expense in connection with the temporary postponement of an initial public offering. No such charges were incurred during the year ended December 31, 2019.

During the year ended December 31, 2020, we reversed approximately ($0.3) million of bad debt expense due to the collection of accounts receivable of KMF Water for which an allowance had previously been established. During the year ended December 31, 2019, we recognized approximately $0.4 million of bad debt expense associated with accounts receivable for KMF Water which we no longer believed were collectible.

Interest expense of approximately $2.0 million and $0.9 million during the years ended December 31, 2020 and 2019, respectively, relates to interest incurred on borrowings under our original credit facility. The increase in interest expense is primarily due to borrowings outstanding under our original credit facility for all of 2020, whereas we had no outstanding borrowings in 2019 until our entry into the original credit facility on September 26, 2019.

Income tax expense primarily relates to state franchise taxes, and totaled approximately $38,000 and $0.2 million for the years ended December 31, 2020 and 2019, respectively.

Segment Results

The following table sets forth certain financial information with respect to our reportable segments (in thousands):


	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 loss		8,790

Oil and Gas Producing Activities

Natural gas revenue for the year ended December 31, 2020 was $4.3 million as compared to $2.4 million for the year ended December 31, 2019, an increase of $1.9 million. A 28% increase in gas production volumes, from 3,238 Mmcf for the year ended December 31, 2019 to 4,134 Mcf for the year ended December 31, 2020, accounted for an approximate $0.7 million increase in year-over-year gas revenue and an increase of $0.29/Mcf in our average price received for gas production, from $0.74/Mcf for the year ended December 31, 2019 to $1.03 for the year ended December 31, 2020, accounted for an approximate $1.2 million increase in our year-over-year gas revenue.

The following table presents the breakdown of our royalty revenues attributable to sales of crude oil, natural gas and NGLs totaling approximately $44.2 million and $50.9 million for the years ended December 31, 2020 and 2019, respectively:


	Year ended December 31,
	2020			2019
Royalty Revenue
Crude oil sales		79	%		85	%
Natural gas sales		10	%		5	%
NGLs sales		11	%		10	%

Total Royalty Revenue		100	%		100	%

Lease bonus and other income, which totaled approximately $1.5 million and $5.3 million for the years ended December 31, 2020 and 2019, respectively, is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues include payments for right-of-way and surface damages, which are also subject to significant variability.

Commodity derivatives losses totaled $2.6 million for the year ended December 31, 2020, whereas there were no derivatives gains or losses for the year ended December 31, 2019. In 2020, we entered into oil fixed price swaps and oil basis swaps to manage commodity price risks associated with our production. In October 2020, we terminated all of our outstanding oil and basis swap derivative contracts. We were not party to any derivative contracts as of December 31, 2020.

Operating expenses for the oil and gas producing activities segment totaled approximately $35.4 million for the year ended December 31, 2019, and consisted primarily of depreciation, depletion and amortization of $25.7 million, production and ad valorem taxes of $3.8 million, employee compensation and benefits of $5.7 million, and general and administrative of $0.1 million.

Income tax expense attributable to the oil and gas producing activities segment primarily relate to state franchise taxes, and totaled approximately $38,000 and $0.2 million for the years ended December 31, 2020 and 2019, respectively.

Water Service Operations

For the year ended December 31, 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer. Contingent rental income earned under this arrangement was $13,000 for the year ended December 31, 2020. For the year ended December 31, 2019, we sold approximately 6.2 million Bbls of water, generating revenue totaling approximately $3.5 million, or $0.56/Bbl. The decrease in overall income from the Water Service Operations segment was primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

Operating expenses totaled approximately $0.2 million and $2.9 million for the years ended December 31, 2020 and 2019, respectively, and consisted primarily of gathering and hauling costs, electricity and fuel, depreciation, depletion and amortization and employee compensation.

Liquidity and Capital Resources

Overview

Prior to the completion of the Merger Transactions, our primary sources of liquidity have been contributions of capital from our limited partners, cash flows from operations and borrowings under our revolving credit facility. Subsequent to the completion of the Merger Transactions, cash flows from operations and borrowings under our revolving credit facility will be the primary day to day sources of our funds. Future sources of liquidity may also include other credit facilities we may enter into in the future and additional issuances of debt or equity securities. Our primary uses of cash have been, and are expected to continue to be, the acquisition of mineral and royalty interests. We also expect to pay dividends to our stockholders. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors.

We believe internally generated cash flows from operations, available borrowing capacity under our revolving credit facility, and access to capital markets will provide us with sufficient liquidity and financial flexibility to continue to acquire attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any development or maintenance capital expenditures, which are entirely borne by the E&P operator and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no other capital expenditure requirements. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather, general economic, financial and competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us.

As of March 31, 2022, our liquidity was $99.1 million, comprised of $13.6 million of cash and cash equivalents, $56.0 million of revolving credit facility availability and $29.5 million of unused capital commitments.

Cash Flows three months ended March 31, 2022 Compared to the three months ended March 31, 2021 (in thousands):


	For the Three Months Ended March, 31,
	2022			2021
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	44,603		$	9,494
Investing activities		(3,376	)		51
Financing activities		(40,021	)		(8,526	)

Net increase in cash	$	1,206		$	1,019

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2022 were $44.6 million as compared to $9.5 million for the three months ended March 31, 2021, primarily as a result of increases in realized prices and production volume from our oil and gas producing activities segment.

Investing Activities

Cash flows used in investing activities totaled $3.4 million for the three months ended March 31, 2022 as compared to cash flows provided by investing activities of $51,000 for the three months ended March 31, 2021, an increase of $3.4 million. During the three months ended March 31, 2022, we made advance deposits of $2.7 million for acquisitions of crude oil and gas properties. Such deposits are reclassified to oil and gas properties upon closure of the acquisitions. Our expenditures for purchases of oil and gas properties increased by $0.7 million related to certain capitalizable transaction costs.

Financing Activities

Cash flows used in financing activities for the three months ended March 31, 2022 totaled $40.0 million as compared to $8.5 million for the three months ended March 31, 2021, an increase of $31.5 million. Repayments on our credit facility for the three months ended March 31, 2022 and 2021 were $40.0 million and $8.5 million, respectively, largely provided by cash flows from operations.

Cash Flows Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020 (in thousands):


	For the year ended December 31,
	2021			2020
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	65,929		$	26,016
Investing activities		(38,743	)		(21,557	)
Financing activities		(22,338	)		(15,061	)

Net increase (decrease) in cash	$	4,848		$	(10,602	)

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2021 were $65.9 million as compared to $26.0 million for the year ended December 31, 2020, primarily as a result of increases in realized prices and production volume from our oil and gas producing activities segment.

Investing Activities

Cash flows used in investing activities totaled $38.7 million for the year ended December 31, 2021 as compared to $21.6 million for the year ended December 31, 2020, an increase of $17.1 million. Our expenditures for crude oil and gas properties increased by $2.9 million in the year ended December 31, 2021 as compared to the year ended December 31, 2020. We paid $0.1 million related to purchase price adjustments from prior property sales for the year ended December 31, 2021, whereas we received proceeds from the sale of mineral interests of $14.1 million for the year ended December 31, 2020. Although we completed several acquisitions during the year ended December 31, 2021, the three largest acquisitions were completed through the issuance of equity in one of our consolidated subsidiaries with no cash consideration provided. The properties acquired through these acquisitions increased the balance of our oil and gas properties by $572.2 million. See our audited consolidated financial statements for the year ended December 31, 2021 and 2020 included as Exhibit 99.3 to the Form 8-K for additional information.

Financing Activities

Cash flows used in financing activities for the year ended December 31, 2021 totaled $22.3 million as compared to $15.1 million for the year ended December 31, 2020, an increase of $7.2 million. Capital contributions from our partners totaled $8.0 million and $13.0 million during the years ended December 31, 2021 and 2020, respectively, which were primarily used for the acquisition of mineral and royalty interests. Borrowings on our credit facility for the years ended December 31, 2021 and 2020 totaled $147.0 million and $10.0 million, respectively, which were also used for the acquisition of mineral and royalty interests and distributions to members of DPM HoldCo. Repayments on our credit facility for the years ended December 31, 2021 and 2020 were $46.5 million and $36.5 million, respectively, largely provided by cash flows from operations as well as the sale of certain properties to another mineral owner during the year ended December 31, 2020.

Cash Flows Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019 (in thousands):


	For the Year Ended December 31,
	2020			2019
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	26,016		$	34,791
Investing activities		(21,557	)		(248,627	)
Financing activities		(15,061	)		221,954

Net (decrease) increase in cash	$	(10,602	)	$	8,118

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. Additionally, revenues and operating expenses within our Water Service Operations segment are subject to significant variability due to fluctuations in market pricing, demand and competition. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2020 were $26.0 million as compared to $34.8 million for the year ended December 31, 2019, primarily as a result of decreases in realized prices from our oil and gas producing activities segment as well as $2.6 million of commodity derivative losses incurred for the year ended December 31, 2020.

Investing Activities

Cash flows used in investing activities totaled $21.6 million for the year ended December 31, 2020 as compared to $248.6 million for the year ended December 31, 2019, a decrease of $227.0 million. Our expenditures for crude oil and gas properties and proceeds from sale of oil and gas properties decreased by $231.0 million and $8.0 million respectively in 2020 as compared to 2019. Although we continued to evaluate and pursue acquisitions of attractive mineral and royalty interests during 2020, we were unable to reach agreeable terms, which resulted in a significant decline in our acquisition activity. During the year ended December 31, 2019, we placed $3.1 million in an escrow account for an acquisition of crude oil and gas properties, which was reclassified to oil and gas properties during the year ended December 31, 2020.

Financing Activities

Cash flows used in financing activities for the year ended December 31, 2020 totaled $15.1 million as compared to cash flows provided by financing activities for the year ended December 31, 2019 of $222.0 million. Capital contributions from our partners totaled $13.0 million and $164.7 million for the years ended December 31, 2020 and 2019, respectively, which were primarily used for the acquisition of mineral and royalty interests. Borrowings on our credit facility for the years ended December 31, 2020 and 2019 totaled $10.0 million and $60.0 million,

respectively, which were also used for the acquisition of mineral and royalty interests. Credit facility borrowings during the year ended December 31, 2020 were offset by repayments of $36.5 million, largely provided by cash flows from operations as well as the sale of certain properties to another mineral owner. There were no repayments on our credit facility during the year ended December 31, 2019.

Our Revolving Credit Facility

On October 8, 2021, KMF Land, as borrower, Desert Peak, as parent, Bank of America, N.A., as the administrative agent and issuing bank, and certain lenders entered into the Existing Credit Agreement, pursuant to which the lenders thereunder made loans and other extensions of credit to the borrower thereunder.

On the Closing Date, the Existing Credit Agreement was amended and restated in its entirety pursuant to the Credit Agreement. The Credit Agreement has a scheduled maturity date in June 2026. Pursuant to the terms and conditions of the Credit Agreement, the Lenders committed to providing a credit facility to Sitio OpCo in an aggregate principal amount of up to $750 million. The availability under the Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the proved reserves of Sitio OpCo and its subsidiaries and elected commitments provided by the Lenders. As of the Closing Date, the Credit Agreement has a $300 million borrowing base and $300 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15 million. Existing letters of credit in place under the Existing Credit Agreement immediately prior to the Closing Date are continued and now deemed issued under and governed by the terms of the Credit Agreement.

Interest accrues on advances, at the borrower’s option, at a Term SOFR rate or a base rate, plus an applicable margin. The fees for letters of credit are also based on the applicable margin. The applicable margin used in connection with interest rates and fees is based on the Borrowing Base Utilization Percentage (as defined in the Credit Agreement). The applicable margin for Term SOFR rate loans and letter of credit fees ranges from 2.500% to 3.500%, and the applicable margin for base rate loans ranges from 1.500% to 2.500%. The borrower will also pay a fee based on the borrowing base utilization percentage on the actual daily unused amount of the aggregate revolving commitments ranging from 0.375% to 0.500%.

The borrowings under the Credit Agreement are secured by liens on certain assets of the borrower, the borrower’s subsidiaries and Sitio Royalties GP, LLC, a Delaware limited liability company, and guaranteed by the borrower and the borrower’s subsidiaries. Proceeds from borrowings under the Credit Agreement may be used (i) for working capital, exploration and production operations, and other general company purposes including acquisitions, (ii) for payment of certain transaction fees and expenses, and (iii) to repay third party debt of the borrower and its subsidiaries existing prior to the Closing Date.

The Credit Agreement contains customary representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Lenders may take a number of actions, including, among others, declaring the entire amount then outstanding under the Credit Agreement to be due and payable.

The Credit Agreement includes a financial covenant limiting, as of the last day of each fiscal quarter, the ratio of (a) (i) Total Net Debt (as defined in the Credit Agreement) as of such date to (ii) EBITDA (as defined in the Credit Agreement) for the period of four fiscal quarters ending on such day (the “Leverage Ratio”), to not more than 3.50 to 1.00, and (b) (i) consolidated current assets (including the available commitments under the Credit Agreement) to (ii) consolidated current liabilities (excluding current maturities under the Credit Agreement), to not less than 1.00 to 1.00, in each case, with certain rights to cure.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules related to the implementation of Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to

comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, systems, processes and procedures.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting.

New and Revised Financial Accounting Standards

Refer to “Recent Accounting Pronouncements” in Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” to our audited consolidated financial statements for the years ended December 31, 2021, 2020 and 2019 included as Exhibit 99.3 to the Form 8-K and Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” to our unaudited condensed consolidated financial statements for the three months ended March 31, 2022 and 2021 included as Exhibit 99.4 to the Form 8-K for a discussion of recent accounting pronouncements.

Critical Accounting Policies and Related Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.

We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates and assumptions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included as exhibits to the Form 8-K.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us 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. Changes in estimates are accounted for prospectively.

Our 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 our oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.

Oil and Gas Properties

We use 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 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. 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.

Impairment of Oil and Gas Properties

We evaluate our proved 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, we compare 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. 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.

Crude Oil, Natural Gas and NGLs Reserve Quantities and Standardized Measure of Oil and Gas

Our estimates of crude oil, natural gas and NGLs reserves and associated future net cash flows are prepared by our independent reservoir engineers. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves. Crude oil, natural gas and NGLs reserve engineering is a process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify positive or negative revisions of reserve estimates.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production taxes and post-production expenses. The prices of oil, natural gas, and NGLs 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 NGLs revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

Water sales for the year ended December 31, 2019 were recognized when control of the water was transferred to an E&P operator and collectability was reasonably assured. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constituted a leasing arrangement under which we were a lessor. Under the terms of the agreement, we were not entitled to any income until the lessee had completed a water sale and received payment from its customer. The agreement was terminated in October 2021.

We also earn revenue related to lease bonuses by leasing our mineral interests to E&P companies. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible. We do not accrue this contingent rental income until the lessee has received payment.

Contractual Obligations

As of March 31, 2022, we did not have any long-term debt, capital lease obligations, operating lease obligations or long-term liabilities, other than borrowings under our revolving credit facility, two operating lease agreements for office space, and an obligation to pay Kimmeridge an annual fee under an investment management agreement. Please see “—Our Revolving Credit Facility” for a description of our revolving credit facility, and Note 11 to our interim unaudited condensed consolidated financial statements for the three months ended March 31, 2022 and 2021 included as Exhibit 99.4 to the Form 8-K for our contractual obligations under the office lease agreements. Fees incurred under the management services arrangement totaled approximately $1.9 million for the three months ended March 31, 2022 and 2021, respectively. We do not expect to incur future expense under the management services arrangement following the completion of the Merger Transactions.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the crude oil, natural gas and NGLs production of our E&P operators, which affects the royalty payments we receive from our E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil, natural gas and NGLs production has been volatile historically and we expect this volatility to continue in the future. The prices that our E&P operators receive for production depend on many factors outside of our or their control.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.5 million change in our oil revenues for the three months ended March 31, 2022. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the three months ended March 31, 2022. A $1.00 per Bbl change in NGL prices would have resulted in a $0.2 million change in our NGL revenues for the three months ended March 31, 2022. Royalties on oil sales contributed 76% of our mineral and royalty revenues for the three months ended March 31, 2022. Royalties on natural gas sales contributed 12% and royalties on NGL sales contributed 12% of our total mineral and royalty revenues for the three months ended March 31, 2022.

A $1.00 per Bbl change in our realized oil price would have resulted in a $1.3 million change in our oil revenues for the year ended December 31, 2021. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.5 million change in our natural gas revenues for the year ended December 31, 2021. A $1.00 per Bbl change in NGL prices would have resulted in a $0.5 million change in our NGL revenues for the year ended December 31, 2021. Royalties on oil sales contributed 72% of our mineral and royalty revenues for the year ended December 31, 2021. Royalties on natural gas sales contributed 14% and royalties on NGL sales contributed 14% of our total mineral and royalty revenues for the year ended December 31, 2021.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.9 million change in our oil revenues for the year ended December 31, 2020. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.4 million change in our natural gas revenues for the year ended December 31, 2020. A $1.00 per Bbl change in NGL prices would have resulted in a $0.5 million change in our NGL revenues for the year ended December 31, 2020. Royalties on oil sales contributed 79% of our mineral and royalty revenues for the year ended December 31, 2020. Royalties on natural gas sales contributed 10% and royalties on NGL sales contributed 11% of our total mineral and royalty revenues for the year ended December 31, 2020.

Credit Risk

The collectability of our royalty revenue is dependent upon the financial condition of our E&P operators, as well as general economic conditions in the industry.

For the three months ended March 31, 2022, in the Oil and Gas Producing Activities segment, revenue from Callon Petroleum Company represented approximately 17% of total revenue. This figure is the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the three months ended March 31, 2022 were de minimis.

For the year ended December 31, 2021, in the Oil and Gas Producing Activities segment, revenue from Coterra Energy Inc., 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 Inc., 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 we are exposed to a concentration of credit risk, we do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers 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 our E&P operators have stipulated that royalty owners must still be paid for oil, gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators into bankruptcy proceedings to materially affect our operating results.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility, which has a floating interest rate. The average annual interest rate incurred on our borrowings under the Existing Credit Agreement during the three months ended March 31, 2022 was 3.26%. We estimate that an increase of 1.0% in the average interest rate during the three months ended March 31, 2022 would have resulted in an

approximately $0.3 million increase in interest expense. The average annual interest rate incurred on our borrowings under the Existing Credit Agreement during the three months ended March 31, 2021 was 2.62%. We estimate that an increase of 1.0% in the average interest rate during the three months ended March 31, 2021 would have resulted in an approximately $0.1 million increase in interest expense.