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Report of Independent Certified Public Accountants			3
Combined Balance Sheets			5
Combined Statements of Operations			6
Combined Statements of Partners’ Equity			7
Combined Statements of Cash Flows			8
Notes to the Combined Financial Statements			9

We have audited the combined financial statements of Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP (collectively, the “Businesses”), which comprise the combined balance sheets as of December 31, 2022 and 2021, and the related combined statements of operations, changes in partners’ equity, and cash flows for the years then ended, and the related notes to the financial statements.

In our opinion, the accompanying combined financial statements present fairly, in all material respects, the financial position of the Businesses as of December 31, 2022 and 2021, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

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

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

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

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

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

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

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


	December 31,
	2022		2021
Assets
Current assets:
Cash and cash equivalents	$	26,523,350	$	25,625,173
Accounts receivable-oil and gas sales and other	30,393,393		23,085,831
Prepaid expenses and other current assets	765,488		593,431
Total current assets	57,682,231		49,304,435

Property:
Oil and gas properties	660,404,232		612,856,556
Accumulated depletion	(101,043,279)		(70,916,751)
Impairment	(164,532,161)		(164,532,161)
Total oil and gas properties, net	394,828,792		377,407,644
Total assets	$	452,511,023	$	426,712,079

Liabilities and Partner’s equity

Current liabilities:
Accounts payable and accrued expenses	$	1,620,000	$	—

Commitments and contingencies (Note 3)

Partners’ equity	450,891,023		426,712,079

Total liabilities and Partner’s equity	$	452,511,023	$	426,712,079


	Year Ended December 31,
	2022		2021
Revenues
Oil and gas sales	$	156,930,913	$	96,271,733
Lease bonuses	3,615,406		510,152
Total revenues	160,546,319		96,781,885
Operating expenses
Production and ad valorem taxes	10,059,617		6,380,218
Depletion	30,126,528		23,353,101
General and administrative	12,947,795		8,254,093
Total operating expenses	53,133,940		37,987,412

Income from operations	107,412,379		58,794,473

Other income (expense)
Other income, net	645,449		998,936
Total other income	645,449		998,936

Net income	$	108,057,828	$	59,793,409


	Limited Partners
Balance at December 31, 2020	$	360,865,786
Net income	59,793,409
Contributions	59,834,243
Distributions	(53,781,359)
Balance at December 31, 2021	426,712,079
Net income	108,057,828
Contributions	45,927,676
Distributions	(129,806,560)
Balance at December 31, 2022	$	450,891,023


	Year Ended December 31,
	2022		2021
Cash flows from operating activities:
Net income	$	108,057,828	$	59,793,409
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	30,126,528		23,353,101
Effect of changes in current assets and liabilities:
Accounts receivable-oil and gas sales and other	(7,307,562)		(9,870,133)
Prepaid expenses and other current assets	(172,057)		75,233
Accounts payable and accrued expenses	1,620,000		—
Net cash provided by operating activities	132,324,737		73,351,610

Cash flows from investing activities:
Acquisition of oil and gas properties	(47,547,676)		(84,027,425)
Net cash used in investing activities	(47,547,676)		(84,027,425)

Cash flows from financing activities:
Contributions	45,927,676		59,834,243
Distributions	(129,806,560)		(53,781,359)
Net cash provided by (used in) financing activities	(83,878,884)		6,052,884

Net increase (decrease) in cash and cash equivalents	898,177		(4,622,931)
Cash, cash equivalents and restricted cash at beginning of period	25,625,173		30,248,104
Cash, cash equivalents and restricted cash at end of period	$	26,523,350	$	25,625,173

Business - Royalty Asset Holdings, LLC (“RAH LLC”) was formed as a Texas limited liability company on September 22, 2016. On March 7, 2017, RAH LLC was converted into Royalty Asset Holdings, LP (“RAH LP”), a Texas limited partnership pursuant to the filing of a certificate of conversion with the Secretary of State of the State of Texas and in accordance with the provisions of the Texas Limited Partnership Law.

Prior to the filing of the certificate of conversion, Royalty Asset Holdings GP, LLC (“RAH GP”), a Texas limited liability company and Brigadier Royalty Warehouse, LLC (“BRW”), a Texas limited liability company owned 0.1% and 99.9% equity interest in RAH LLC respectively. On March 7, 2017, RAH GP was appointed as the sole general partner and BRW was appointed as the sole limited partner of RAH LP. Effective as of April 1, 2017, BRW assigned to Warwick Royalty and Mineral Master Fund LP (“WRMF”) a Delaware limited partnership, all of BRW’s equity interests in and to each of RAH GP and RAH LP.

Royalty Asset Holdings II, LP (“RAH II LP”), a Delaware limited partnership was formed on February 11, 2019, by Warwick Royalty and Mineral Fund II GP Limited (“WRMF II GP”), a Cayman Islands exempted limited company, as the sole general partner, and Brigadier Royalty Warehouse II, LLC (“BRW II”), a Delaware limited liability company, as the sole limited partner. Effective as of April 18, 2019, BRW II assigned to Warwick Royalty and Mineral Master Fund II LP (“WRMF II”), a Delaware limited partnership, all BRW II’s equity interests in RAH II LP.

Saxum Asset Holdings, LP (“Saxum LP”) was formed on April 15, 2020, by Warwick Royalty and Mineral Fund III GP Limited, a Cayman Islands exempted company as the sole general partner (“WRMF III GP”) and Warwick Royalty and Mineral Master Fund III LP (“WRMF III”), a Delaware limited partnership, as the sole limited partner to Saxum LP.

RAH LP, RAH II LP and Saxum LP (together the “Businesses”) were formed to seek and acquire both producing and nonproducing mineral interests, royalty interests, overriding royalty interests, net profit interests, and production payments, in each case, in the United States.

The General Partners and the Businesses have delegated, subject to its responsibility and supervision, day-to-day investment management of the Partnership’s assets to GRP Royalty Holdings LLC, a Texas limited liability company and their affiliates, GRP RAH I Holdings LLC, GRP RAH II Holdings LLC and GRP Saxum Holdings, LLC, all of which are Delaware limited liability company (together the “Manager”).

Basis of Presentation - The accompanying combined financial statements and related notes thereto were prepared in conformity with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated in combination.

Use of Estimates in the Preparation of Financial Statements - Management is required to make certain estimates and assumptions in the preparation of the combined financial statements that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The impact of oil and gas prices has a significant impact on estimates made by management. Changes in the value of these commodities has a direct impact on the economic limits of estimated oil and gas reserves. These economic limits have significant effects upon predicted reserve values. These estimates are the basis for the calculation of depletion for the oil and gas properties and the assessment as to whether an impairment of such properties is required.

Further, these estimates and other factors, including those outside of the Businesses’ control, such as the impact of sustained lower commodity prices, can potentially impact operators' current and future development plans (including the impact to undeveloped oil & gas properties), which could have a significant adverse impact to the Businesses’ financial condition, results of operations and cash flows.

The Businesses’ oil, natural gas, and natural gas liquid reserves represent estimated quantities of oil and gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values including many factors beyond the Businesses’ control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered.

Accrued Revenue Recognized on Production Income Basis - Production estimates are made based upon internal estimated ultimate recovery curves in the routine course of business if publicly available data does not exist for new Proved Developed Producing (PDP) wells.

Revenues from oil, natural gas and natural gas liquids are generally recognized when control of the product is transferred to the purchaser, which is the point where performance obligations are satisfied based on the Businesses’ percentage ownership share of the revenue, net of any deductions for gathering and transportation. All the Businesses’ oil and gas sales are made under contracts between the operators of the properties in which the Businesses hold interest and their respective customers. The Businesses' contract is with the operator of the oil and gas properties; however, we have concluded that the substance of the transactions between the Businesses and the end customer results in the Businesses being the principal within the context of Accounting Standards Codification 606, Revenue from Contracts with Customers, "ASC 606". The Businesses' performance obligations are satisfied at the point in time the product is delivered by the operator to the purchaser of the hydrocarbons. Accordingly, the Businesses' contracts do not give rise to contract assets or liabilities.

The Businesses typically receive payment for oil and gas sales within 60 days, unless the product being sold is related to a newly drilled well, in which case, payment may be received up to six months beyond the date of first production. Contracts for the sale of oil, natural gas and natural gas liquids are industry standard contracts that include variable consideration based upon a monthly index and may include provisions related to gravity, price differentials, discounts and other adjustments and deductions. As each unit of production represents a separate performance obligation, the consideration is variable as it relates to oil and gas prices, and the variability is resolved as each unit of production is delivered to the purchaser, variable consideration does not need to be estimated. Additionally, the Businesses' right to royalties does not originate until production occurs and, therefore, is not considered to exist beyond each day's production. Therefore, there are no unsatisfied performance obligations at the end of the period.

The Businesses earn revenue from lease bonuses. Lease bonus revenue is generated by leasing the Businesses’ mineral interests to exploration and production companies. A lease agreement represents a contract with a customer (in this case the operator of oil and gas properties) and generally transfers the rights to any oil, natural gas and natural gas liquids discovered, grants the Businesses a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time frame. The Businesses recognize lease bonus revenue when the lease agreement has been executed, payment has been received, and the Businesses have no obligation to refund the payment. At the time the Businesses execute the lease agreement, the Businesses expect to receive payment of the lease bonus within a short time frame, but in no case more than one year. As such, the

The Businesses derive revenue from the sale of oil, natural gas and natural gas liquids produced from properties in which they own a royalty or overriding royalty interest, which is recognized based on the Businesses’ pro-rata interest. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil and gas is transferred to the purchaser. The Businesses accrue revenue based on estimated production dates of the wells associated with the Businesses’ mineral and overriding royalty interests, along with estimates of pricing for the production. In certain instances, statements are received from operators which provide information with respect to actual revenues to be received after year end, which are incorporated into the accrued revenue analysis.

The difference between the Businesses' estimates and the actual amounts received for oil and gas sales is recorded in the month that payment is received. For the years ended December 31, 2022 and 2021, revenues recognized relating to performance obligations satisfied in prior periods were immaterial.

The Businesses' oil, natural gas and natural gas liquids receivables are related to revenues due from operators of properties in which the Businesses owns mineral or overriding royalty interests. Although diversified amongst several producers, collectability of receivables is largely dependent upon the general economic conditions of the industry. All receivables are reviewed periodically, and balances are written off when, in the judgement of management, the receivable becomes uncollectible. Historically, the Businesses have not experienced significant issues with collectability and have determined no allowance for uncollectible accounts is necessary at December 31, 2022 and 2021.

Concentrations of Credit Risk - The Businesses regularly have cash in a single financial institution which exceeds federal depository insurance limits. The Businesses place such deposits with high credit quality institutions and have not experienced any credit losses. The Businesses are also subject to credit risk related to oil and gas receivables due from operators related to the sale of hydrocarbons produced from properties in which the Businesses own a mineral or overriding royalty interest. For the years ended December 31, 2022 and 2021, one purchaser accounted for more than 10% of royalty income each year.

Fair Value of Financial Instruments - The Businesses' financial instruments consist of cash, accounts receivable, prepayments, other current assets, accounts payables and accrued expenses. The carrying values of these financial instruments are considered to be representative of their fair market values, due to the short-term maturity of these instruments.

Accounting for Oil and Gas Operations - The Businesses use the full cost method of accounting for oil and gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and gas properties are capitalized to the full cost pool. The Businesses' oil and gas properties are comprised of only mineral and overriding royalty interests. As such, the Businesses have not incurred any exploration or development costs.

All acquisitions of mineral and royalty interests are considered asset acquisitions in accordance with the guidance in Accounting Standards Codification 805 – Business Combinations. For asset acquisitions, the purchase price (which includes costs incurred for the acquisition) is allocated to the individual assets acquired and liabilities assumed based on their relative fair values. In substantially all of the acquisitions completed by the Businesses during the years ended December 31, 2022 and 2021, the fair value of the proved properties acquired exceeded the purchase price. As such, the purchase price for each acquisition was fully allocated to proved properties. Proceeds from the disposition of oil and gas properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Proved reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from a given date forward from known reservoirs and under defined economic conditions, operating methods, and government regulations. Fair values of acquired proved properties were estimated using associated future net cash flows prepared by the Businesses’ internal reservoir engineers, which include significant inputs such as anticipated production of proved reserves and other relevant data.

Depletion of capitalized costs of oil and gas properties is provided for using the units of production method based upon estimates of proved oil and gas reserves. In calculating depletion, the volume of proved oil and gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Depletion expense for the years ended December 31, 2022 and 2021 was $30,126,528 or $12.80 per barrel of oil equivalent and $23,353,101 or $11.65 per barrel of oil equivalent, respectively.

In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are subject to a ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues from proved reserves, discounted at 10% per annum based on the trailing 12-month unweighted arithmetic average of the commodity prices posted on the first day of each month in the respective year, adjusted for existing contract provisions; (b) the cost of properties not being amortized, if any; and (c) the lower of cost or fair market value of unproved properties included in the cost being amortized.

If the net book value exceeds the ceiling, the book balance of the properties is written down to the ceiling via an impairment charge. No ceiling test impairment was recorded for the year ended December 31, 2022 and 2021. The businesses recorded an impairment expense of $164,532,161 as a result of the decline in commodity prices for the year ended December 31, 2020.

Income Taxes - All the Businesses are disregarded for U.S. income tax purposes. As such, they are neither subject to taxation nor required to submit tax returns. All the assets and liabilities of the Businesses are treated as owned directly by the respective limited partners. Further, the Businesses are passive entities for Texas franchise tax purposes, so they are not subject to tax in the state.

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, Leases. The FASB issued the guidance to increase the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This is required for all leases that have a term longer than one year. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. For non-public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2021. Adoption of the accounting standard did not have a material impact on the combined financial statements or related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses. In May 2019, ASU 2016-13 was subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments-Credit Losses and ASU 2019-05, Financial Instruments-Credit Losses (Topic 326): Targeted Transition Relief. ASU 2016-13, as amended, applies to trade receivables, financial assets and certain other instruments that are not measured at fair value through net income. This ASU will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost and is effective for financial statements issued for fiscal years beginning after December 15, 2022, including interim periods in those fiscal years. Adoption of this accounting standard is not expected to have a material impact on the combined financial statements or related disclosures.

There are no other accounting standards applicable to the Businesses that would have a material effect on the Businesses' combined financial statements and disclosures that have been issued but not yet adopted by the Businesses as of December 31, 2022, and through the filing date of this report.

During the year ended December 31, 2022, in individually insignificant transactions, the Businesses acquired, from unrelated third party sellers, mineral and royalty interests representing 1,920 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $47.5 million, including certain customary post-closing adjustments. The Businesses funded the acquisitions through capital contributions from Partners.

During the year ended December 31, 2021, in individually insignificant transactions, the Businesses acquired, from unrelated third party sellers, mineral and royalty interests representing 5,430 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $84.0 million, including certain customary post-closing adjustments. The Businesses funded the acquisitions through capital contributions from Partners.

The Businesses may from time to time be involved in various legal actions arising in the normal course of business or from activities associated with properties prior to their acquisition by the Businesses. In the opinion of management, the Businesses’ liability, if any, in these pending actions would not have a material adverse effect on the financial position, results of operations or cash flows of the Businesses.

Capitalization and Distributions - The General Partners of the Businesses may from time to time call capital, and the limited partners will contribute capital to the Businesses in accordance with their respective Partnership Interests.

The limited partners shall not be entitled to (a) withdraw from the Businesses except upon the assignment by the limited partner of all of the limited partner’s interest in the Businesses, or (b) the return of the limited partner’s capital contributions except to the extent, if any, that distributions made pursuant to the express terms of the limited partnership agreement may be considered as such by law or upon dissolution and liquidation of the Businesses, and then only to the extent expressly provided for in the limited partnership agreement and as permitted by applicable law.

Except upon liquidation, all distributions of cash or property of the Businesses to the Partners is made in accordance with their Partnership Interests. The timing of all distributions of the Businesses’ income and capital is at the sole discretion of the General Partner. No Partner is entitled to withdraw any part of its capital contributions or its capital account or to receive any distribution from the Businesses, except as provided in the limited partnership agreement.

Dissolution, Liquidation, and Terminations - The Businesses shall dissolve upon the happening of one of the following events: (a) any event which, in the opinion of the General Partner, would make it in the best interests of the Businesses to be dissolved; (b) the bankruptcy of the General Partner; or (c) the occurrence of any other event under the agreement that causes the dissolution of a limited partnership (unless the Partners elect to continue the Businesses within 90 days of such event in accordance with the agreement, if permissible under the circumstances).

Upon dissolution, the General Partner shall proceed diligently to wind up the business and affairs of the Businesses, allocate income and loss among the limited partners and distribute its properties and assets, if any. Distributions to limited partners upon the liquidation of the Businesses will be made pro rata in accordance with the Partners’ Partnership Interests. Subject to the preceding sentence, the manner in which the Businesses is liquidated will be within the sole and absolute discretion of the General Partner.

Parties are considered to be related if one party has the ability to control the other party or exercise significant influence over the other party in making financial and operational decisions or if two entities are under common control. Related party transactions in the Partnership are discussed below.

The Manager is entitled to a monthly service fee of $135,000 from each of the Businesses. In addition, the Businesses pay the Manager a quarterly incentive payment (“MIP”) which is calculated by the General Partner as of the end of each calendar quarter during the year in an amount equal to 5% of the net cash flows realized by each Business during the calendar quarter.

Subsequent events have been evaluated through November 13, 2023, the date the combined financial statements were issued. Subsequent to December 31, 2022 and up to November 13, 2023, the Businesses made distributions of $116,949,510. No additional subsequent events of a material nature have been identified that require recognition or disclosure.

Proved oil and natural gas reserve estimates and their associated future net cash flows for the Businesses were estimated by independent reserve engineers, DeGolyer and MacNaughton Corp, as of December 31, 2022 and 2021. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the 12-month period prior to the end of the reporting period.

The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.


	Oil (MBbls)	Natural Gas (MMcf)	Natural Gas Liquids (MBbls)	Total (MBOE)
	(In thousands)
Proved Developed and Undeveloped Reserves:
As of December 31, 2020	13,136	56,735	8,351	30,943
Purchase of reserves in place	1,350	4,124	688	2,725
Extensions and discoveries	235	1,166	153	582
Revisions of previous estimates	(32)	598	69	137

Production	(1,123)	(2,997)	(381)	(2,004)
As of December 31, 2021	13,566	59,626	8,880	32,383
Purchase of reserves in place	263	1,785	303	864
Extensions and discoveries	56	273	34	136
Revisions of previous estimates	52	(776)	(102)	(179)

Production	(1,316)	(3,266)	(494)	(2,354)
As of December 31, 2022	12,621	57,642	8,621	30,850







Proved Developed Reserves:

December 31, 2021	6,146	32,774	4,559	16,167
December 31, 2022	7,126	35,007	4,961	17,922

Proved Undeveloped Reserves:
December 31, 2021	7,420	26,852	4,321	16,216
December 31, 2022	5,495	22,635	3,660	12,928

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

For the year ending December 31, 2021, the Businesses’ positive revisions of 137 MBoe of previously estimated quantities consisted of price and performance revisions of proved developed producing wells. Extensions and discoveries of 582 MBoe resulted primarily from the addition of 67 new wells and from 105 new proved undeveloped locations added.

For the year ending December 31, 2022, the Businesses’ negative revisions of 179 MBoe of previously estimated quantities consisted of performance revisions of proved developed producing wells. Extensions and discoveries of 136 MBoe resulted primarily from the addition of 40 new wells and from 46 new proved undeveloped locations added.

The standardized measure of discounted future net cash flows should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value of proved reserves to the Businesses. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.


	December 31,
	2022		2021
	(In thousands)
Future cash inflows	$	1,739,907	$	1,228,960
Future production taxes	(97,469)		(70,750)
Future income tax expense	(7,691)		(5,491)
Future net cash flows	1,634,747		1,152,719
10% discount to reflect timing of cash flows	(779,108)		(550,980)
Standardized measure of discounted future net cash flows	$	855,639	$	601,739

The following table presents the unweighted arithmetic average first-day-of–the-month prices within the 12-month period prior to the end of the reporting period as adjusted by differentials and other contractual terms for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows.


	December 31,
	2022		2021
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	601,739	$	315,230
Purchase of minerals in place	20,346		60,230

Sales of oil and natural gas, net of production costs	(146,871)		(89,892)
Extensions and discoveries	3,573		10,820
Net changes in prices and production costs	336,617		278,475
Revisions of previous quantity estimates	(2,882)		2,810
Net changes in income taxes	(1,174)		(1,345)
Accretion of discount	60,462		31,677
Net changes in timing of production and other	(16,171)		(6,266)
Standardized measure of discounted future net cash flows at the end of the period	$	855,639	$	601,739


	For the Years Ended December 31,
	2022		2021
Oil sales	$	121,133,976	$	73,051,880
Gas sales	18,626,238		11,620,247
Natural gas liquids sales	17,170,699		11,599,606
Oil and gas sales	$	156,930,913	$	96,271,733


	December 31,
	2022		2021


Oil (per Bbl)	$	94.02	$	66.92
Natural gas (per Mcf)	$	5.63	$	2.88
Natural gas liquids (per Bbl)	$	33.24	$	23.62