(19)	SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Our gas natural 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,
	2013			2012			2011
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	8,225,859		$	7,368,308		$	6,035,429
Unproved properties		807,022			743,467			748,598
Total		9,032,881			8,111,775			6,784,027
Accumulated depreciation, depletion and amortization		(2,274,444	)		(2,015,591	)		(1,626,461	)
Net capitalized costs	$	6,758,437		$	6,096,184		$	5,157,566

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

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

	December 31,
	2013		2012		2011
	(in thousands)
Acreage purchases	$	137,538	$	188,843	$	220,576
Development		938,668		1,049,129		1,007,049
Exploration:
Drilling		189,742		309,816		226,920
Expense		60,384		65,758		77,259
Stock-based compensation expense		4,025		4,049		4,108
Gas gathering facilities:
Development		47,086		41,035		53,387
Subtotal		1,377,443		1,658,630		1,589,299
Asset retirement obligations		76,373		57,982		24,061
Total – continuing operations		1,453,816		1,716,612		1,613,360
Discontinued operations		¾		—		3,241
Total costs incurred	$	1,453,816	$	1,716,612	$	1,616,601

^(a)	Includes cost incurred whether capitalized or expensed.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

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 and other economic factors.

Recent SEC and FASB Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the natural gas and oil company reserves reporting requirements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserve estimates for the three years ended December 31, 2013.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2013, the following independent petroleum consultants conducted an audit of our reserves: DeGolyer and MacNaughton (Southwest) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2013, these consultants collectively audited approximately 96% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent petroleum consultants are included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet 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 consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their reserves audit process. Throughout the year, our technical team meets regularly with representatives of each of our independent petroleum consultants 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 consultants for our largest producing properties such as ownership interest; natural gas 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 additional reserve work performed by the technical teams related to any identified reserve differences. The reserve auditor estimates of proved reserves and the pre-tax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area, some of our estimates may be greater than those of the auditors and some may be less than the estimates of the reserve auditors. When such differences do not exceed 10% in the aggregate, our reserve auditors are satisfied that the proved reserves and pre-tax 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 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. 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.

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, 2013 to estimate reserve information were $86.66 per barrel of oil, $25.93 per barrel of NGLs and $3.75 per mcf for gas, using benchmark (NYMEX) of $97.33 per barrel and $3.67 per Mmbtu. The average realized prices used at December 31, 2012 to estimate reserve information were $86.91 per barrel of oil, $32.23 per barrel of NGLs and $2.75 per mcf for gas, using benchmark (NYMEX) of $95.05 per barrel and $2.76 per MMbtu. The average realized prices used at December 31, 2011 to estimate reserve information were $85.59 per barrel of oil, $49.24 per barrel for NGLs and $3.55 per mcf for gas, using benchmark (NYMEX) of $95.61 per barrel and $4.12 per Mmbtu.


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:
Balance, December 31, 2010 ^(b)		3,566,526			122,722			23,239			4,442,290
Revisions		73,643			18,627			6,522			224,542
Extensions, discoveries and additions		1,304,324			26,591			4,915			1,493,357
Purchases		—			—			—			—
Property sales		(777,816	)		(19,852	)		(1,176	)		(903,983	)
Production		(157,001	)		(5,573	)		(1,968	)		(202,245	)
Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961
Revisions		76,925			3,036			2,316			109,036
Extensions, discoveries and additions		996,059			113,392			15,131			1,767,202
Purchases		—			—			—			—
Property sales		(73,429	)		(11,575	)		(1,046	)		(149,153	)
Production		(216,555	)		(6,969	)		(2,851	)		(275,476	)
Balance, December 31, 2012		4,792,676			240,399			45,082			6,505,570
Revisions		384,825			7,743			2,935			448,898
Extensions, discoveries and additions		853,746			135,810			10,723			1,732,944
Purchases		¾			¾			¾			¾
Property sales		(101,074	)		(286	)		(6,553	)		(142,116	)
Production		(264,528	)		(9,254	)		(3,827	)		(343,022	)
Balance, December 31, 2013		5,665,645			374,412			48,360			8,202,274
Proved developed reserves:
December 31, 2011		1,907,209			64,472			17,872			2,401,274
December 31, 2012		2,373,604			154,984			25,667			3,457,502
December 31, 2013		2,797,483			206,477			26,054			4,192,666
Proved undeveloped reserves:
December 31, 2011		2,102,467			78,043			13,660			2,652,687
December 31, 2012		2,419,072			85,415			19,415			3,048,068
December 31, 2013		2,868,162			167,935			22,306			4,009,608

^(a)	Oil and NGLs 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 necessarily indicative of the relationship of oil and natural gas prices.

^(b)	Total proved reserves at December 31, 2010 includes 906,371 Mmcfe related to discontinued operations of which 408,710 Mmcfe is proved undeveloped.

During 2013, we added approximately 1.7 Tcfe of proved reserves from drilling activities and revaluation of proved areas primarily in the Marcellus Shale. Approximately 49% of 2013 reserve additions were attributable to natural gas. Also, included in 2013 proved reserves is a total of 676 Bcfe of ethane reserves (155.8 Mmbbls) in the Marcellus Shale. Revisions of previous estimates of a net 449 Bcfe includes positive performance revisions and improved recovery primarily for our Marcellus Shale natural gas properties and positive pricing revisions, somewhat offset by reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon.

During 2012, we added approximately 1.8 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 56% of the 2012 reserve additions were attributable to natural gas. Also included in 2012 additions is 307 Bcfe of ethane reserves (51.2 Mmbbls) in the Marcellus Shale associated with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of a net 109 Bcfe include positive performance revisions primarily for our Marcellus Shale natural gas properties, partially offset by negative pricing revisions.

During 2011, we added approximately 1.5 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily in the Marcellus Shale. Approximately 87% of the 2011 reserve additions were attributable to natural gas. Revisions of previous estimates of 225 Bcfe were primarily positive performance revisions for natural gas properties, primarily in the Marcellus Shale.

The following details the changes in proved undeveloped reserves for 2013 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2012	3,048,068
Undeveloped reserves transferred to developed	(433,526	)
Revisions	233,763
Purchases/sales	(23,362	)
Extension and discoveries	1,184,665
Ending proved undeveloped reserves at December 31, 2013	4,009,608

Approximately $504.1 million was spent during 2013 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $755.0 million in 2014, $1.3 billion in 2015 and $1.0 billion in 2016. Included in proved undeveloped reserves at December 31, 2013 are approximately 9.3 Bcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for five or more years. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2018.

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:

1.	Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

2.	For the years ended 2013, 2012 and 2011, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

4.	The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

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,
	2013			2012
	(in thousands)
Future cash inflows	$	35,143,097		$	24,851,589
Future costs:
Production		(10,176,140	)		(10,028,359	)
Development		(3,938,296	)		(3,667,672	)
Future net cash flows before income taxes		21,028,661			11,155,558
Future income tax expense		(6,913,196	)		(3,081,918	)
Total future net cash flows before 10% discount		14,115,465			8,073,640
10% annual discount		(8,253,234	)		(4,849,835	)
Standardized measure of discounted future net cash flows	$	5,862,231		$	3,223,805

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

	December 31,
	2013			2012			2011
	(in thousands)
Revisions of previous estimates:
Changes in prices	$	2,172,704		$	(2,498,616	)	$	422,080
Revisions in quantities		513,168			88,190			326,240
Changes in future development costs		(275,468	)		(354,766	)		(346,378	)
Accretion of discount		395,989			608,381			464,735
Net change in income taxes		(1,299,227	)		832,830			(400,690	)
Purchases of reserves in place		¾			—			—
Additions to proved reserves from extensions, discoveries and improved recovery		1,981,054			1,429,340			2,169,706
Production		(1,286,103	)		(976,224	)		(911,873	)
Development costs incurred during the period		462,862			562,329			513,551
Sales of natural gas and oil		(162,463	)		(120,637	)		(1,313,401	)
Timing and other		135,910			(861,919	)		111,801
Net change for the year		2,638,426			(1,291,092	)		1,035,771
Beginning of year		3,223,805			4,514,897			3,479,126
End of year	$	5,862,231		$	3,223,805		$	4,514,897