(18)	Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)

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,
	2017			2016			2015
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	10,572,453		$	9,462,350		$	8,047,181
Unproved properties		2,644,000			2,923,803			949,155
Total		13,216,453			12,386,153			8,996,336
Accumulated depreciation, depletion and amortization		(3,649,716	)		(3,129,816	)		(2,635,031	)
Net capitalized costs	$	9,566,737		$	9,256,337		$	6,361,305

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

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

	December 31,
	2017		2016			2015
	(in thousands)
Acquisitions
Acreage purchases	$	62,075	$	33,142		$	73,025
Oil and gas properties		18,269		3,098,772			—
Asset retirement obligations and other		—		21,908			—
Development		1,177,526		497,795			708,268
Exploration:
Drilling		2,030		37,680			87,505
Expense		50,920		30,027			18,421
Stock-based compensation expense		2,742		2,298			2,985
Gas gathering facilities:
Development		15,097		3,595			13,337
Subtotal		1,328,659		3,725,217			903,541
Asset retirement obligations		20,245		(24,064	)		22,184
Total costs incurred	$	1,348,904	$	3,701,153		$	925,725

^(a)

Includes cost incurred whether capitalized or expensed.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2017, the following independent petroleum consultants conducted an audit of our reserves: Wright & Company, Inc. (Appalachia) and Netherland, Sewell & Associates, Inc. (North Louisiana). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2017, our consultants collectively audited approximately 98% of our proved reserves. Copies of the summary reserve reports prepared by our independent petroleum consultants are included as exhibits to this Annual Report on Form 10-K. The technical professional at our independent petroleum consulting firms 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 consultants 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 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, 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 basis, 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 Chairman, 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 thirty-five 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.

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, 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, 2017 to estimate reserve information were $45.73 per barrel of oil, $17.84 per barrel of NGLs and $2.60 per mcf for gas using a benchmark (NYMEX) of $51.19 per barrel and $2.98 per Mmbtu. The average realized prices used at December 31, 2016 to estimate reserve information were $37.41 per barrel of oil, $13.44 per barrel of NGLs and $2.07 per mcf for gas using a benchmark (NYMEX) of $42.68 per barrel and $2.48 per Mmbtu. The average realized prices used at December 31, 2015 to estimate reserve information were $35.07 per barrel of oil, $11.74 per barrel of NGLs and $2.07 per mcf for gas, using a benchmark (NYMEX) of $50.13 per barrel and $2.59 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, 2014		6,922,836			515,907			48,658			10,310,229
Revisions		(340,286	)		17,717			3,804			(211,163	)
Extensions, discoveries and additions		1,017,956			36,308			4,924			1,265,348
Property sales		(960,122	)		(441	)		(109	)		(963,423	)
Production		(362,687	)		(20,356	)		(4,084	)		(509,328	)
Balance, December 31, 2015		6,277,697			549,135			53,193			9,891,663
Revisions		(7,441	)		41,402			2,471			255,794
Extensions, discoveries and additions		1,193,154			26,991			6,506			1,394,134
Purchases		943,544			40,724			11,986			1,259,806
Property sales		(160,727	)		(360	)		(295	)		(164,655	)
Production		(375,811	)		(27,826	)		(3,609	)		(564,420	)
Balance, December 31, 2016		7,870,416			630,066			70,252			12,072,322
Revisions		70,222			83,338			(10,555	)		506,919
Extensions, discoveries and additions		2,866,103			87,572			15,997			3,487,519
Purchases		7,738			330			66			10,116
Property sales		(60,278	)		(2,356	)		(1,121	)		(81,133	)
Production		(490,552	)		(35,686	)		(4,785	)		(733,382	)
Balance, December 31, 2017		10,263,649			763,264			69,854			15,262,361
Proved developed reserves:
December 31, 2015		3,376,165			309,306			31,679			5,422,075
December 31, 2016		4,352,141			363,852			39,110			6,769,908
December 31, 2017		5,437,674			448,258			36,808			8,348,074
Proved undeveloped reserves:
December 31, 2015		2,901,533			239,828			21,514			4,469,588
December 31, 2016		3,518,275			266,214			31,143			5,302,414
December 31, 2017		4,825,975			315,006			33,046			6,914,287

^(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 indicative of the relationship of oil and natural gas prices.

During 2017, we added approximately 3.5 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 82% of the 2017 reserve additions are attributable to natural gas. Included in 2017 proved reserves is a total of 360.6 Mmbbls of ethane reserves (1,596 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 507 Bcfe includes positive performance revisions of 532 Bcfe, improved recoveries of 597 Bcfe, positive pricing revisions of 46 Bcfe partially offset by 668 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. Purchases of reserves in 2017 reflects reserves added in North Louisiana.

During 2016, we added approximately 1.4 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 86% of the 2016 reserve additions are attributable to natural gas. Included in 2016 proved reserves is a total of 308.9 Mmbbls of ethane reserves (1,367 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 256 Bcfe includes positive performance revisions of 154 Bcfe and improved recoveries of 393 Bcfe primarily from our Marcellus Shale natural gas properties partially offset by negative price revisions and 269 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. Purchases of reserves in 2016 reflect reserves added in North Louisiana, primarily from the MRD Merger.

During 2015, we added approximately 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 80% of the 2015 reserve additions are attributable to natural gas. Included in 2015 proved reserves is a total of 292.8 Mmbbls of ethane reserves (1,296 Bcfe) in the Marcellus Shale. Revisions of previous estimates of a negative 211 Bcfe includes positive performance revisions and improved recoveries of 781.0 Bcf primarily from our Marcellus Shale natural gas properties more than offset by negative price revisions and 1.2 Tcfe reclassified to unproved because of lower future capital spending in response to lower commodity prices.

The following details the changes in proved undeveloped reserves for 2017 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2016	5,302,414
Undeveloped reserves transferred to developed	(1,861,994	)
Revisions^(a)	308,929
Purchases/(sales)	(8,907	)
Extension and discoveries	3,173,845
Ending proved undeveloped reserves at December 31, 2017	6,914,287

^(a) Includes 668 Bcfe of proved undeveloped reserves dropped due to the five year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.

Approximately $920 million was spent during 2017 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $717 million in 2018, $707 million in 2019 and $567 million in 2020. As of December 31, 2017, we have 64 Bcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for more than five years from their original date of booking, all of which are in the process of being drilled. 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 2022.

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:

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

For the years ended 2017, 2016 and 2015, 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.

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,
	2017			2016
	(in thousands)
Future cash inflows	$	43,500,054		$	27,413,864
Future costs:
Production		(18,958,695	)		(14,465,059	)
Development^(a)		(3,072,688	)		(2,647,801	)
Future net cash flows before income taxes		21,468,671			10,301,004
Future income tax expense		(3,989,459	)		(1,946,259	)
Total future net cash flows before 10% discount		17,479,212			8,354,745
10% annual discount		(10,313,998	)		(4,902,816	)
Standardized measure of discounted future net cash flows	$	7,165,214		$	3,451,929

^(a) 2017 includes $430.6 million of undiscounted future asset retirement costs estimated as of December 31, 2017, using current estimates of future abandonment costs.

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

	December 31,
	2017			2016			2015
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	2,615,825		$	(212,867	)	$	(7,231,629	)
Revisions in quantities		445,667			96,615			(868,886	)
Changes in future development and abandonment costs		(497,400	)		(314,864	)		359,540
Net change in income taxes		(706,531	)		27,842			2,173,904
Accretion of discount		372,743			302,920			1,007,027
Purchases of reserves in place		6,173			488,959			—
Additions to proved reserves from extensions, discoveries and improved recovery		2,128,135			541,095			486,478
Natural gas, NGLs and oil sales, net of production costs		(1,237,970	)		(509,174	)		(522,682	)
Development costs incurred during the period		885,803			435,928			1,033,539
Sales of reserves in place		(32,946	)		(65,538	)		(1,050,237	)
Timing and other		(266,214	)		(64,850	)		(254,218	)
Net change for the year		3,713,285			726,066			(4,867,164	)
Beginning of year		3,451,929			2,725,863			7,593,027
End of year	$	7,165,214		$	3,451,929		$	2,725,863