Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)


	December 31,
	2021			2020			2019
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,338,236		$	8,891,348		$	9,345,557
Unproved properties		837,334			859,766			868,180
Total		10,175,570			9,751,114			10,213,737
Accumulated depreciation, depletion and amortization		(4,420,914	)		(4,064,305	)		(4,172,702	)
Net capitalized costs	$	5,754,656		$	5,686,809		$	6,041,035


(a)	Includes capitalized asset retirement costs and the associated accumulated amortization.

Costs Incurred for Property Acquisition, Exploration and Development (a)


	December 31,
	2021		2020		2019
	(in thousands)
Acquisitions
Acreage purchases	$	21,942	$	26,166	$	57,324
Development		381,753		369,093		666,984
Exploration:
Drilling		6,329		7,709		—
Expense		22,048		31,376		35,117
Stock-based compensation expense		1,507		1,279		1,566
Gas gathering facilities:
Development		3,402		3,694		3,583
Subtotal		436,981		439,317		764,574
Asset retirement obligations		18,634		2,610		11,193
Total costs incurred	$	455,615	$	441,927	$	775,767


(a)	Includes cost incurred whether capitalized or expensed.

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2021, Netherland, Sewell & Associates, Inc., an independent petroleum consultant, conducted an audit of our 2021 reserves in Appalachia. These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2021, our consultant audited approximately 97% of our proved reserves. A copy of the summary reserve report prepared by our independent petroleum consultant is included as an exhibit to this Annual Report on Form 10-K. The technical professional at our independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultant to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any significant changes to our proved reserves. We provide historical information to our consultant for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-field or area-by-area, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than forty years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, production taxes and other economic factors.

The SEC defines proved reserves as those volumes of natural gas, NGLs, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

The average realized prices used at December 31, 2021 to estimate reserve information were $59.35 per barrel of oil, $28.41 per barrel of NGLs and $3.30 per mcf for gas using a benchmark (NYMEX) of $66.34 per barrel and $3.60 per Mmbtu. The average realized prices used at December 31, 2020 to estimate reserve information were $30.13 per barrel of oil, $16.14 per barrel of NGLs and $1.68 per mcf for gas using a benchmark (NYMEX) of $39.77 per barrel and $1.98 per Mmbtu. The average realized prices used at December 31, 2019 to estimate reserve information were $49.24 per barrel of oil, $17.32 per barrel of NGLs and $2.38 per mcf for gas using a benchmark (NYMEX) of $55.73 per barrel and $2.58 per Mmbtu.


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) (a)
Proved developed and undeveloped reserves:
Balance, December 31, 2018		12,027,702			921,594			85,856			18,072,406
Revisions		33,122			57,311			(12,320	)		303,068
Extensions, discoveries and additions		959,901			26,505			7,057			1,161,274
Property sales		(327,634	)		(28,324	)		(2,371	)		(511,811	)
Production		(578,114	)		(38,850	)		(3,690	)		(833,354	)
Balance, December 31, 2019		12,114,977			938,236			74,532			18,191,583
Revisions		(789,992	)		42,741			(12,444	)		(608,211	)
Extensions, discoveries and additions		1,007,415			38,298			4,512			1,264,282
Property sales		(609,311	)		(30,317	)		(6,145	)		(828,084	)
Production		(574,529	)		(37,492	)		(2,829	)		(816,456	)
Balance, December 31, 2020		11,148,560			951,466			57,626			17,203,114
Revisions		(311,410	)		16,845			(7,089	)		(252,876	)
Extensions, discoveries and additions		1,155,952			69,367			5,103			1,602,769
Production		(541,021	)		(36,373	)		(3,044	)		(777,523	)
Balance, December 31, 2021		11,452,081			1,001,305			52,596			17,775,484
Proved developed reserves:
December 31, 2019		6,486,211			535,007			34,369			9,902,468
December 31, 2020		6,350,057			550,771			22,976			9,792,540
December 31, 2021		6,809,849			577,506			23,833			10,417,887
Proved undeveloped reserves:
December 31, 2019		5,628,766			403,229			40,163			8,289,115
December 31, 2020		4,798,503			400,695			34,650			7,410,574
December 31, 2021		4,642,232			423,798			28,762			7,357,597


(a)	Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

During 2021, we added approximately 1.6 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 72% of the 2021 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 252.9 Bcfe include positive performance revisions of 1.0 Tcfe and positive pricing revisions of 22.6 Bcfe more than offset by 1.3 Tcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon.

During 2020, we added approximately 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 80% of the 2020 reserve additions are attributable to natural gas. Revisions of previous estimates of a negative 608.2 Bcfe include positive performance revisions of 420.9 Bcfe which were more than offset by 961.1 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon and negative pricing revisions of 67.9 Bcfe.

During 2019, we added approximately 1.2 Tcfe of proved reserves from drilling activities and evaluation of proved areas in the Marcellus Shale. Approximately 83% of the 2019 reserve additions are attributable to natural gas. Included in 2019 proved reserves is a total of 475.0 Mmbbls of ethane reserves (2,102 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 303 Bcfe include positive performance revisions of 922.2 Bcfe which were partially offset by 601.3 Bcfe reclassified to unproved and negative pricing revisions of 17.8 Bcfe.

During 2021, we spent approximately $361.3 million in development costs related to proved undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $2.2 billion over the next five years. As of December 31, 2021, we have 21 Bcfe that have been reported for more than five years from their original date of booking, all of which are in the process of being completed and are expected to turn to sales in 2022. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2026.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs, crude oil and condensate reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs, crude oil and condensate, 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 standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third-party transportation, gathering and compression expense.


	As of December 31,
	2021			2020
	(in thousands)
Future cash inflows	$	69,403,611		$	35,820,758
Future costs:
Production		(27,015,321	)		(23,281,268	)
Development (a)		(2,469,028	)		(2,744,539	)
Future net cash flows before income taxes		39,919,262			9,794,951
Future income tax expense		(8,146,832	)		(1,240,011	)
Total future net cash flows before 10% discount		31,772,430			8,554,940
10% annual discount		(19,287,204	)		(5,708,618	)
Standardized measure of discounted future net cash flows	$	12,485,226		$	2,846,322


(a)	2021 includes $308.5 million of undiscounted future asset retirement costs as of December 31, 2021, using current estimates of future abandonment costs.

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	December 31,
	2021			2020			2019
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	11,600,850		$	(4,868,371	)	$	(6,560,107	)
Revisions in quantities		577,737			(345,073	)		(12,741	)
Changes in future development and abandonment costs		(53,818	)		107,899			104,585
Net change in income taxes		(2,248,161	)		797,816			1,125,639
Accretion of discount		298,077			756,083			1,317,349
Additions to proved reserves from extensions, discoveries and improved recovery		1,423,510			280,441			552,710
Natural gas, NGLs and oil sales, net of production costs		(1,934,254	)		(402,450	)		(881,883	)
Actual development costs incurred during the period		399,681			384,530			676,520
Sales of reserves in place		—			(394,125	)		(688,937	)
Timing and other		(424,718	)		(99,001	)		(120,156	)
Net change for the year		9,638,904			(3,782,251	)		(4,487,021	)
Beginning of year		2,846,322			6,628,573			11,115,594
End of year	$	12,485,226		$	2,846,322		$	6,628,573