COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

(Unaudited)


	Years Ended December 31,
(Thousands of dollars)	2022		2021
Development Costs	$	13,598	$	18,678

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

(Unaudited)


	As of December 31,
(Thousands of dollars)	2022			2021
Future cash inflows	$	994,842		$	501,431
Future production costs		(378,160	)		(207,697	)
Future development costs		(95,746	)		(18,507	)
Future income tax expenses		(110,439	)		(57,798	)

Future Net Cash Flows		410,497			217,429
10% annual discount for estimated timing of cash flows		(165,961	)		(81,623	)

Standardized Measure of Discounted Future Net Cash Flows	$	244,536		$	135,806

See accompanying Notes to Supplementary Information

PRIMEENERGY RESOURES CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS AND CHANGES THEREIN

RELATING TO PROVED OIL AND GAS RESERVES

(Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2022 and 2021:


	Years Ended December 31,
(Thousands of dollars)	2022			2021
Sales of oil and gas produced, net of production costs	$	(86,302	)	$	(45,322	)
Net changes in prices and production costs		72,640			143,750
Extensions, discoveries and improved recovery		126,029			6,440
Revisions of previous quantity estimates		(10,902	)		18,991
Net change in development costs		(2,814	)		(12,904	)
Reserves sold		(818	)		(136	)
Reserves purchased		—			—
Accretion of discount		13,581			4,162
Net change in income taxes		(8,435	)		(21,180	)
Changes in production rates (timing) and other		5,751			386

Net change		108,730			94,187
Standardized measure of discounted future net cash flow:
Beginning of year		135,806			41,619

End of year	$	244,536		$	135,806

See accompanying Notes to Supplementary Information

PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2022 and 2021

(Unaudited)


	As of December 31,
	2022									2021
	Oil (MBbls)			NGL’s (MBbls)			Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)
Proved Developed Reserves:
Beginning of year		5,386			2,882			23,902			2,684			2,258			13,633
Extensions, discoveries and improved recovery		99			74			464			69			1			628
Revisions of previous estimates		(375	)		(37	)		1,309			1,639			813			11,836
Converted from undeveloped reserves		—			—			—			1,747			231			1,067
Reserves sold		(28	)		(5	)		(73	)		(15	)		(5	)		(26	)
Reserve purchased		—			—			—			—			—			—
Production		(939	)		(417	)		(3,325	)		(738	)		(416	)		(3,236	)

End of year		4,143			2,497			22,277			5,386			2,882			23,902

Proved Undeveloped Reserves:
Beginning of year		—			—			—			1,784			787			3,897
Extensions, discoveries and improved recovery		3,028			1,833			9,030			(61	)		(557	)		(2,726	)
Revisions of previous estimates		—			—			—			31			4			386
Converted to developed reserves		—			—			—			(1,747	)		(231	)		(1,067	)
Reserves Sold		—			—			—			(7	)		(4	)		(489	)

End of year		3,028			1,833			9,030			—			—			—

Total Proved Reserves at the End of the Year		7,171			4,330			31,307			5,386			2,882			23,902

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2022 and 2021

(Unaudited)


	Years Ended December 31,
(Thousands of dollars)	2022		2021
Revenue:
Oil and gas sales	$	124,118	$	73,126
Costs and Expenses:
Lease operating expenses		37,816		27,804
Depreciation, depletion and accretion		28,068		26,325
Income tax expense		10,329		3,989

Total Costs and Expenses		76,213		58,118

Results of Operations from Producing Activities (excluding corporate overhead and interest costs)	$	47,905	$	15,008

See accompanying Notes to Supplementary Information

PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES

NOTES TO SUPPLEMENTARY INFORMATION

(Unaudited)

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to

non-controlling

interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to

year-end

quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at

year-end,

based on

year-end

costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the U.S. tax rate to future

pre-tax

cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from

year-end

and the use of a 10% discount figure is arbitrary.

5. Changes in Reserves

The 2022 and 2021 extensions and discoveries reflect the drilling activity in the Company’s West Texas and

Mid-Continent

areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. Future development plans are reflective of the current commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility.