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Natural gas and oil properties, successful efforts method

1,641,197

1,654,292

^[1]

13,216,453

12,386,153

Accumulated depletion and depreciation

^[1]

(3,649,716)

(3,129,816)

Natural gas and oil properties, successful efforts method, net

^[1]

9,566,737

9,256,337

Other property and equipment

114,361

112,796

Accumulated depreciation and amortization

(99,695)

(95,923)

Other Property and equipment, net

14,666

16,873

Other assets

76,734

72,655

Total assets

11,728,841

11,282,245

Current liabilities:

Accounts payable

343,871

229,190

Asset retirement obligations

6,327

7,271

Accrued liabilities

317,531

265,843

Accrued interest

43,511

35,340

Derivative liabilities

44,233

165,009

Total current liabilities

755,473

702,653

Bank debt

1,208,467

876,428

2,851,754

2,848,591

Deferred compensation liabilities

48,585

48,498

Deferred tax liabilities

693,356

943,343

Derivative liabilities

9,789

24,491

101,102

119,231

Asset retirement obligations and other liabilities

286,043

310,642

Total liabilities

5,954,569

5,873,877

Commitments and contingencies

Stockholders' Equity

Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding

Common stock, $0.01 par 475,000,000 shares authorized, 248,144,397 issued at December 31, 2017 and 247,174,903 issued at December 31, 2016

2,481

2,471

Common stock held in treasury, 14,967 shares at December 31, 2017 and 30,547 shares at December 31, 2016

(599)

(1,209)

Additional paid-in capital

5,577,732

5,524,423

Accumulated other comprehensive loss

(1,332)

Retained earnings (deficit)

195,990

(117,317)

Total stockholders' equity

5,774,272

5,408,368

Total liabilities and stockholders' equity

$ 11,728,841

$ 11,282,245

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 7,111	$ 5,559
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	248,144,397	247,174,903
Common stock held in treasury, shares	14,967	30,547

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Thousands

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2014

Dec. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Revenues and other income:

Natural gas, NGLs and oil sales

$ 603,159

$ 507,541

$ 506,137

$ 559,450

$ 458,645

$ 304,477

$ 224,606

$ 209,487

$ 2,176,287

$ 1,197,215

$ 1,089,644

Derivative fair value income (loss)

25,024

(88,426)

111,195

165,557

(250,057)

64,556

(162,798)

86,908

213,350

(261,391)

416,364

Brokered natural gas, marketing and other

50,849

63,117

55,779

51,648

44,934

44,174

39,989

35,018

221,393

164,115

92,060

Total revenues and other income

679,032

482,232

673,111

776,655

253,522

413,207

101,797

331,413

2,611,030

1,099,939

1,598,068

Costs and expenses:

Direct operating

37,921

36,888

31,420

28,023

30,276

22,387

20,671

24,054

134,252

97,388

136,363

Transportation, gathering, processing and compression

200,300

191,645

191,590

177,648

164,338

138,764

136,844

125,263

761,183

565,209

396,739

Production and ad valorem taxes

11,757

11,993

9,969

9,163

6,790

6,717

6,049

5,887

42,882

25,443

33,860

Brokered natural gas and marketing

51,131

59,773

55,857

53,550

46,471

44,622

40,925

36,558

220,311

168,576

115,866

Exploration

7,893

22,767

14,498

8,504

13,684

6,943

6,785

4,913

53,662

32,325

21,406

Abandonment and impairment of unproved properties

217,544

42,568

5,193

4,420

6,307

6,082

7,059

10,628

269,725

30,076

47,619

General and administrative

80,553

53,035

52,322

47,496

57,027

41,024

46,064

40,657

233,406

184,772

194,015

MRD Merger expenses

813

33,791

2,621

$ 37,200

37,225

Termination costs

(279)

(47)

(96)

4,192

(822)

136

162

$ 8,400

3,770

(519)

15,070

Deferred compensation plan

(14,077)

(9,203)

(14,466)

(13,169)

(11,013)

(11,636)

25,746

16,056

(50,915)

19,153

(77,627)

Interest

51,473

49,179

47,926

47,101

46,749

45,967

37,758

37,739

195,679

168,213

166,439

Loss on early extinguishment of debt

22,495

Depletion, depreciation and amortization

162,918

159,749

152,504

149,821

149,662

131,489

122,390

120,561

624,992

524,102

581,155

Impairment of proved properties

63,679

43,040

63,679

43,040

590,174

(Gain) loss on the sale of assets

(207)

(102)

(807)

(22,600)

(470)

2,597

3,304

1,643

(23,716)

7,074

406,856

Total costs and expenses

806,927

681,924

545,910

494,149

509,812

468,883

456,221

467,161

2,528,910

1,902,077

2,650,430

Income (loss) before income taxes

(127,895)

(199,692)

127,201

282,506

(256,290)

(55,676)

(354,424)

(135,748)

82,120

(802,138)

(1,052,362)

Income tax (benefit) expense:

Current

Deferred

(349,097)

(71,992)

57,651

112,395

(95,679)

(13,705)

(129,488)

(41,976)

(251,043)

(280,848)

(338,706)

Total (benefit) expense for income taxes

(349,080)

(71,992)

57,651

112,395

(95,581)

(13,705)

(129,488)

(41,976)

(251,026)

(280,750)

(338,677)

Net income (loss)

$ 221,185

$ (127,700)

$ 69,550

$ 170,111

$ (160,709)

$ (41,971)

$ (224,936)

$ (93,772)

$ 333,146

$ (521,388)

$ (713,685)

Net income (loss) per common share:

Basic

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ 1.34

$ (2.75)

$ (4.29)

Diluted

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ 1.34

$ (2.75)

$ (4.29)

Weighted average common shares outstanding:

Basic

^[1]

245,091

189,868

166,389

Diluted

245,458

189,868

166,389

[1]	Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net income (loss)	$ 333,146	$ (521,388)	$ (713,685)
Postretirement benefits:
Prior service cost	(1,769)	0	0
Income tax benefit	437	0	0
Total comprehensive income (loss)	$ 331,814	$ (521,388)	$ (713,685)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss)	$ 333,146,000	$ (521,388,000)	$ (713,685,000)
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
Deferred income tax benefit	(251,043,000)	(280,848,000)	(338,706,000)
Depletion, depreciation and amortization and impairment	688,671,000	567,142,000	1,171,329,000
Exploration dry hole and impairment costs	9,172,000	18,000	88,000
Abandonment and impairment of unproved properties	269,725,000	30,076,000	47,619,000
Derivative fair value (income) loss	(213,350,000)	261,391,000	(416,364,000)
Cash settlements on derivative financial instruments	13,117,000	347,336,000	532,122,000
Allowance for bad debt	1,550,000	800,000	2,300,000
Amortization of deferred financing costs, loss on extinguishment of debt and other	5,445,000	7,170,000	29,383,000
Deferred and stock-based compensation	30,706,000	74,685,000	(20,411,000)
(Gain) loss on the sale of assets	(23,716,000)	7,074,000	406,856,000
Changes in working capital:
Accounts receivable	(102,866,000)	(20,586,000)	64,704,000
Inventory and other	(2,979,000)	6,220,000	(14,868,000)
Accounts payable	45,912,000	(27,259,000)	(26,197,000)
Accrued liabilities and other	12,764,000	(64,763,000)	(32,768,000)
Net cash provided from operating activities	816,254,000	387,068,000	691,402,000
Investing activities:
Additions to natural gas and oil properties	(1,148,613,000)	(466,252,000)	(1,030,644,000)
Additions to field service assets	(5,710,000)	(3,052,000)	(4,441,000)
Acreage purchases	(58,213,000)	(43,482,000)	(74,880,000)
MRD Merger, net of cash acquired	0	7,180,000	0
Other	0	0	(75,000)
Proceeds from disposal of assets	72,468,000	193,755,000	890,901,000
Purchases of marketable securities held by the deferred compensation plan	(88,167,000)	(37,019,000)	(28,876,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	89,178,000	40,035,000	29,243,000
Net cash used in investing activities	(1,139,057,000)	(308,835,000)	(218,772,000)
Financing activities:
Borrowings on credit facilities	2,041,000,000	2,274,000,000	2,271,000,000
Repayments on credit facilities	(1,712,000,000)	(1,487,000,000)	(2,899,000,000)
Issuance of senior notes	0	0	750,000,000
Repayment of senior or senior subordinated notes	(500,000)	(273,012,000)	(516,875,000)
Dividends paid	(19,839,000)	(16,682,000)	(27,083,000)
Debt issuance costs	(403,000)	(6,342,000)	(14,156,000)
Taxes paid for shares withheld	(6,983,000)	(3,849,000)	(7,702,000)
Change in cash overdrafts	17,180,000	18,393,000	(37,089,000)
Proceeds from the sales of common stock held by the deferred compensation plan	4,482,000	13,102,000	8,298,000
Net cash provided from (used in) financing activities	322,937,000	(78,390,000)	(472,607,000)
Increase (decrease) in cash and cash equivalents	134,000	(157,000)	23,000
Cash and cash equivalents at beginning of year	314,000	471,000	448,000
Cash and cash equivalents at end of year	448,000	314,000	471,000
MRD
Financing activities:
Repayments on credit facilities	$ 0	$ (597,000,000)	$ 0

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common stock held in treasury	Additional paid-in capital	Retained earnings/(deficit)	Accumulated other comprehensive (loss)
Beginning balance at Dec. 31, 2014	$ 3,457,429	$ 1,687	$ (3,088)	$ 2,400,475	$ 1,058,355	$ 0
Beginning balance Shares at Dec. 31, 2014		168,711,000
Issuance of common stock	10,073	$ 6	0	10,067	0	0
Issuance of common stock, shares		665,000
Stock-based compensation expense	36,496	$ 0	0	36,496	0	0
Tax benefit related to stock-based compensation	(3,572)	0	0	(3,572)	0	0
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017)	(27,083)	0	0	0	(27,083)	0
Treasury stock issuance		0	843	(843)	0	0
Net income (loss)	(713,685)	0	0	0	(713,685)	0
Ending balance at Dec. 31, 2015	2,759,658	$ 1,693	(2,245)	2,442,623	317,587	0
Ending balance Shares at Dec. 31, 2015		169,376,000
Issuance of common stock	3,048,653	$ 778	0	3,047,875	0	0
Issuance of common stock, shares		77,799,000
Stock-based compensation expense	37,023	$ 0	0	37,023	0	0
Tax benefit related to stock-based compensation	(2,062)	0	0	(2,062)	0	0
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017)	(16,682)	0	0	0	(16,682)	0
Cumulative-effect adjustment from adoption of ASU 2016-09	103,166	0	0	0	103,166	0
Treasury stock issuance		0	1,036	(1,036)	0	0
Net income (loss)	(521,388)	0	0	0	(521,388)	0
Ending balance at Dec. 31, 2016	$ 5,408,368	$ 2,471	(1,209)	5,524,423	(117,317)	0
Ending balance Shares at Dec. 31, 2016	247,174,903	247,175,000
Issuance of common stock	$ 2,987	$ 10	0	2,977	0	0
Issuance of common stock, shares		969,000
Stock-based compensation expense	50,942	$ 0	0	50,942	0	0
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017)	(19,839)	0	0	0	(19,839)	0
Treasury stock issuance	0	0	610	(610)	0	0
Other comprehensive loss	(1,332)	0	0	0	0	(1,332)
Net income (loss)	333,146	0	0	0	333,146	0
Ending balance at Dec. 31, 2017	$ 5,774,272	$ 2,481	$ (599)	$ 5,577,732	$ 195,990	$ (1,332)
Ending balance Shares at Dec. 31, 2017	248,144,397	248,144,000

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Stockholders Equity [Abstract]
Common dividends declared per share	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.08	$ 0.08	$ 0.16

Summary of Organization and Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2017
Industry Specific Policies [Abstract]
Summary of Organization and Nature of Business	(1) Summary of Organization and Nature of Business Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas, NGLs and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and North Louisiana regions of the United States. Our objective is to build stockholder value through consistent returns − focused on growth, on a per share debt-adjusted basis, of both reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC”.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2) Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these estimates are recorded when known.

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to optimize returns without regard to individual areas.

Revenue Recognition, Accounts Receivable and Gas Imbalances

Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in accordance with Accounting Standards Code Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we receive from the purchaser. For the sale of our NGLs, in some cases, we receive a price from the purchaser (which is net of processing costs) that is recorded in revenue at the net price we receive. Under the other type of agreement, we sell natural gas, NGLs or oil at a specific delivery point, pay transportation, gathering, processing and compression expenses to a third party and receive proceeds from the purchaser with no deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering, processing and compression expense.

We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby Range or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokered natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $5.7 million in 2017 compared to losses of $2.8 million in 2016 and losses of $2.7 million in 2015.

Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016. We recorded bad debt expense of $1.6 million in the year ended December 31, 2017 compared to $800,000 in the year ended December 31, 2016 and $2.3 million in the year ended 2015.

Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. Imbalances are not significant in the periods presented.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows.

Marketable Securities

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets.

Inventory

Inventories were comprised of $12.1 million of materials and supplies at December 31, 2017 compared to $9.4 million at December 31, 2016. Inventories consist primarily of tubular goods and equipment used in our operations and are stated at the lower of specific cost of each inventory item or net realizable value, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is reviewed periodically for obsolescence or impairment when market conditions indicate. At December 31, 2017, we also had commodity inventory of $508,000, compared to $8.3 million at December 31, 2016, which is carried at lower of weighted average cost or net realizable value, on a first-in, first-out basis. Commodity inventory at December 31, 2017 consists of NGLs held as line fill in pipelines or tanks.

Goodwill

As a result of our merger with Memorial Resource Development Corp. (the “MRD Merger” or “Memorial”) in September 2016, we have goodwill in the amount of $1.6 billion at December 31, 2017, the excess of consideration transferred over the fair value of Memorial. Goodwill is not amortized but tested for impairment annually, as of November 1^st, or more frequently if events or circumstances indicate that impairment may exist. We apply a fair value based impairment test to the carrying value of our business (our reporting unit). We assess the value of our business under either a qualitative or quantitative approach. Under a qualitative approach, we consider various market factors, including applicable key assumptions we have listed below. These factors are analyzed to determine if events and circumstances have affected the fair value of our business. If we determine that it is more likely than not that our business is impaired, the quantitative approach is used to assess our fair value and the amount of the impairment. Under a quantitative approach, the fair value is calculated based on key assumptions we have listed below. If our carrying value exceeds our fair value calculated using the quantitative approach, an impairment charge is recorded for the difference between fair value and carrying value. For more information, see Note 4.

Performing a qualitative impairment assessment of our business requires an examination of relevant events and circumstances that could have a negative impact on our business, such as macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events.

When performing a quantitative impairment assessment of goodwill, fair value is estimated based on a combination of (i) recent market transactions, where available; and (ii) projected discounted cash flows (an income approach). Under the income approach, the fair value is based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestitures or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model include estimated quantities of crude oil, natural gas and NGLs reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer company based weighted average cost of capital. Under the market approach, we would estimate fair value by a comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments including the selection of comparable companies and/or comparable recent company asset transactions, transaction premiums and selected financial metrics. If natural gas, NGLs and oil prices decrease, drilling efforts are unsuccessful or our market capitalization declines further, it is reasonably possible that we would be required to record additional impairments.

Natural Gas and Oil Properties

Property Acquisition Costs. We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 7.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of proved producing properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. In the year ended December 31, 2015, the fair value of our natural gas and oil properties in Northwest Pennsylvania was determined to be zero. As a result, any future adjustments to the asset retirement liability for these properties represents an impairment expense and we have elected to record such expense in depreciation, depletion and amortization. In the year ended December 31, 2017, additional expense of $158,000 was recorded related to these costs compared to $1.9 million in the year ended December 31, 2016.

Impairments. Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. Unproved properties had a net book value of $2.6 billion as of December 31, 2017 compared to $2.9 billion in 2016. We have recorded abandonment and impairment expense related to unproved properties of $269.7 million in the year ended December 31, 2017 compared to $30.1 million in 2016 and $47.6 million in 2015.

Dispositions. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 3.

Acquisitions. Acquisitions of proved properties are accounted for as either a business combination or an asset acquisition and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. In a business combination, purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In an asset acquisition, fair value is assigned to the assets acquired. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. For additional information regarding our acquisitions, see Note 3.

Other Property and Equipment

Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $7.7 million in the year ended December 31, 2017 compared to $8.4 million in the year ended December 31, 2016 and $11.9 million in the year ended December 31, 2015.

Other Assets

Other assets at December 31, 2017 include $67.1 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage. Other assets at December 31, 2016 include $61.7 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage.

Stock-based Compensation Arrangements

We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 13.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. In third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend or double the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 11.

From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2017, we did not modify any existing derivative contracts.

Concentrations of Credit Risk

As of December 31, 2017, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016.

For the years ended December 31, 2017, 2016 and 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production.

We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. The majority of our derivative contracts have no margin requirements or collateral provisions that would require us to fund or post additional collateral prior to the scheduled cash settlement date.

At December 31, 2017, our derivative counterparties included nineteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit facility. At December 31, 2017, our net derivative asset includes a payable to the counterparties not included in our bank credit facility totaling $28.2 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 9 for additional information.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.

Deferred Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term on the balance sheet.

New Accounting Pronouncements

Recently Adopted

In January 2017, an accounting standards update was issued that eliminates the requirements to calculate the implied fair value of goodwill to measure any goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This standard is effective for annual periods beginning after December 15, 2019 and should be applied on a prospective basis. Early adoption is permitted for any goodwill impairment tests performed in first quarter 2017 or later. We elected to adopt this accounting standards update in first quarter 2017. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, this standard did change our policy for our goodwill impairment assessment by eliminating the requirement to calculate the implied fair value of goodwill.

In March 2016, an accounting standards update was issued that simplifies several aspects of the accounting for share-based payment award transactions. Among other things, this new guidance will require all income tax effects of share-based awards to be recognized in the statement of operations when the awards vest or are settled, will allow an employer to repurchase more of an employee’s shares for tax withholding purposes than it can today without triggering liability accounting and will allow a policy election to account for forfeitures as they occur. This new standard will be effective for annual periods beginning after December 15, 2016. Early adoption was permitted. We elected to early adopt this accounting standards update in fourth quarter 2016 which required us to reflect any adjustments as of January 1, 2016, the beginning of the annual period that included the interim period of adoption. The following summarizes the impact of this new standard on our consolidated financial statements:

Income taxes - Upon adoption of this standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) are recognized as income tax expense or benefit in our consolidated statements of operations. The tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur. Adoption of this new standard resulted in the recognition of an excess tax deficiency in our provision for income taxes rather than paid-in capital of $2.1 million for the year ended December 31, 2016 and affected our previously reported first quarter 2016 results as follows (in thousands, except per share data):

		For The Three Months Ended March 31, 2016
		As Reported			As Adjusted
Statements of Operations:
Income tax benefit	$	(44,038	)	$	(41,976	)
Net loss		(91,710	)		(93,772	)
Basic earnings per share		(0.55	)		(0.56	)
Diluted earnings per share		(0.55	)		(0.56	)

In addition, we have recorded a cumulative-effect adjustment to retained earnings (deficit) and reduced our deferred tax liability for $101.1 million for previously unrecognized tax benefits due to our NOL position.

Forfeitures - Prior to adoption, share-based compensation expense was recognized on a straight line basis, net of estimated forfeitures, such that expense was recognized only for share-based awards that are expected to vest. We have elected to continue to estimate forfeitures.

Statements of cash flows - The presentation requirements for cash flows related to employee taxes paid for withheld shares will be adjusted retrospectively. These cash flows have historically been presented as an operating activity. Upon adoption of this new standard, these cash outflows will be classified as a financing activity. Prior periods have been adjusted as follows (in thousands):

		As Reported		As Adjusted
		Net cash provided from operating activities		Net cash provided from operating activities
Year ended 2015	$	683,700	$	691,402
Year ended 2014		954,135		974,353
Year ended 2013		743,538		757,373
Three months ended March 31, 2016		87,424		90,785
Six months ended June 30, 2016		169,604		173,201
Nine months ended September 30, 2016		202,037		205,837

		As Reported			As Adjusted
		Net cash (used in) provided from financing activities			Net cash (used in) provided from financing activities
Year ended 2015	$	(464,905	)	$	(472,607	)
Year ended 2014		291,421			271,203
Year ended 2013		239,994			226,159
Three months ended March 31, 2016		(72,473	)		(75,834	)
Six months ended June 30, 2016		(95,411	)		(99,008	)
Nine months ended September 30, 2016		(35,229	)		(39,029	)

In July 2015, an accounting standards update was issued that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in first quarter 2017 and was applied prospectively. Adoption of this standard did not have an impact on our consolidated results of operations, financial position or cash flows.

In August 2016, an accounting standards update was issued that clarifies how entities classify certain cash receipts and cash payments on the statement of cash flows. The guidance is effective for us in first quarter 2018 and should be applied retrospectively with early adoption permitted. We adopted this new standard in the fourth quarter 2017 on a retrospective basis. Adoption of this standard did not have an impact on our consolidated cash flow statement presentation.

In January 2017, an accounting standards update was issued which clarifies the definition of a business. This new standard is effective for us in first quarter 2018 with early adoption permitted. We adopted this new standard in the fourth quarter 2017. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Accounting Pronouncements Not Yet Adopted

In May 2014, an accounting standards update was issued that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in first quarter 2018 and we expect to adopt the new standard using the modified retrospective method of adoption. We have utilized a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts and the impact of adopting this standards update on our total revenues, operating income (loss) and our consolidated balance sheet. As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures, in addition to developing and implementing any process or control changes necessary. We do not expect to record a cumulative effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts will change. Based on current accounting guidance, certain of our gas processing contracts are reported in revenue at the net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts will be reported as a gross price received at a delivery point and additional transportation, marketing and processing expense.

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use asset and lease liability for all leases with terms of more than twelve months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standards update is effective for us in first quarter 2019 and should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, with early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows but based on our preliminary review of the update, we expect that we will have operating leases with durations greater than twelve months on the balance sheet. As we continue to evaluate and implement the standards update, we will provide additional information about the expected financial impact at a future date.

In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis though a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers will present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs rising from services rendered during the period. This new standards update will be effective for us for annual reporting periods in first quarter 2018, with early adoption permitted. We anticipate this standard will not have a material impact on our financial statements and related disclosures.

In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update is intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. This standards update will be effective for us in first quarter 2018 and we do not anticipate it will have a material impact on our financial position or consolidated results of operations.

Dispositions and Acquisitions

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Dispositions and Acquisitions

(3)	Dispositions and Acquisitions

We recognized a pretax net gain on the sale of assets of $23.7 million in the year ended December 31, 2017 compared to a loss of $7.1 million in 2016 and a loss of $406.9 million in 2015. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2017, 2016 and 2015.

2017 Dispositions

Texas Panhandle. In fourth quarter 2017, we sold various properties in the Texas Panhandle for proceeds of $40.4 million and we recorded a loss of $989,000 related to this sale, after closing adjustments.

Western Oklahoma. In the year ended December 31, 2017, we sold certain properties in Oklahoma for proceeds of $30.8 million and we recorded a gain of $23.8 million related to this sale, after closing adjustments and transaction fees.

Other. In 2017, we sold miscellaneous unproved property, inventory and surface property for proceeds of $1.3 million resulting in a gain of $870,000.

2016 Dispositions

Western Oklahoma. In first nine months 2016, we sold various properties in Western Oklahoma for proceeds of $78.6 million and we recorded a loss of $5.3 million related to these sales, after closing adjustments and transaction fees.

Pennsylvania. In first quarter 2016, we sold our non-operated interest in certain wells and gathering facilities in northeast Pennsylvania for proceeds of $111.5 million. After closing adjustments, we recorded a loss of $2.1 million related to this sale.

Other. In 2016, we sold miscellaneous proved and unproved property, inventory and surface property for proceeds of $3.7 million resulting in a gain of $302,000. Included in the $3.7 million of proceeds is $1.2 million received from the sale of proved properties in Mississippi and South Texas.

2015 Dispositions

Virginia and West Virginia. In December 2015, we sold the majority of our producing properties and gathering assets in Virginia and West Virginia for cash proceeds of $876.0 million, before closing adjustments. We recorded a pretax loss of $407.7 million related to this sale. We recognized $52.3 million of field net operating income (defined as natural gas, oil and NGLs sales plus net brokered margin less direct operating expenses, production and ad valorem taxes, transportation expense, exploration expense and divisional office general and administrative expense) for these assets for the period from January 1, 2015 to December 30, 2015.

West Texas. In February 2015, we sold certain of our West Texas properties for cash proceeds of $10.5 million and we recognized a pretax loss of $101,000 related to this sale.

Other. During 2015, we also sold miscellaneous inventory, surface acreage and unproved property for proceeds of $4.4 million which resulted in a pretax gain of $943,000.

Memorial Merger

On September 16, 2016, we completed the MRD Merger which was accomplished through the merger of Medina Merger Sub, Inc., a Delaware corporation and a direct, wholly-owned subsidiary of Range, with and into Memorial, with Memorial surviving as a wholly-owned subsidiary of Range. The results of Memorial’s operations since the effective time of the merger are included in our consolidated statement of operations. The merger was effected through the issuance of approximately 77.0 million shares of Range common stock in exchange for all outstanding shares of Memorial using an exchange ratio of 0.375 of a share of Range common stock for each share of Memorial common stock. At the effective time of the merger, Memorial’s liabilities, which are reflected in Range’s consolidated financial statements, included approximately $1.2 billion fair value of outstanding debt. In connection with the MRD Merger, we incurred merger-related expenses of approximately $37.2 million including consulting, investment banking, advisory, legal and other merger-related fees.

Allocation of Purchase Price. The MRD Merger has been accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of the MRD Merger to the assets acquired and the liabilities assumed based on the fair value at the effective time of the merger, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (in thousands, except shares and stock price):

Purchase price:
Shares of Range common stock issued to Memorial stockholders		77,042,749
Range common stock price per share at September 15, 2016 (close)	$	39.37
Total purchase price	$	3,033,173

Plus fair value of liabilities assumed by Range:
Accounts payable	$	55,624
Other current liabilities		108,367
Long-term debt		1,204,449
Deferred taxes		547,706
Other long-term liabilities		77,223
Total purchase price plus liabilities assumed	$	5,026,542

Fair value of Memorial assets:
Cash and equivalents	$	7,180
Other current assets		99,969
Derivative instruments		152,994
Natural gas and oil properties:
Proved property		1,122,311
Unproved property		1,999,187
Other property and equipment		3,579
Goodwill ^(a)		1,641,197
Other		125
Total asset value	$	5,026,542

^(a)Goodwill will not be deductible for income tax purposes.

The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the MRD Merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.

The fair value measurements of natural gas and oil properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of natural gas and oil properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of natural gas and oil properties include estimates of: (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices and (v) a market-based weighted average costs of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and may be subject to change. Management utilized the assistance of a third party valuation expert to estimate the value of natural gas and oil properties acquired. In some cases, certain amounts allocated to unproved properties are based on a market approach using third party published data which provides lease pricing information based on certain geographic areas and represent Level 2 inputs.

Goodwill is attributed to net deferred tax liabilities arising from the differences between the purchase price allocated to Memorial’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the total consideration for the merger included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the merger creates including additional potential for exploration and development opportunities, additional scale and efficiencies in other basins in which we operate and substantial operating and administrative synergies.

The results of operations attributable to Memorial are included in our consolidated statements of operations beginning on September 16, 2016. We recognized $477.4 million of natural gas, oil and NGLs revenue and $278.8 million of field net operating income from these assets from January 1, 2017 to December 31, 2017. We recognized $146.6 million of natural gas, oil and NGLs revenues and $94.9 million of field net operating income from these assets from September 16, 2016 to December 31, 2016.

Pro forma Financial Information. The following pro forma condensed combined financial information was derived from the historical financial statements of Range and Memorial and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments for the issuance of Range common stock in exchange for Memorial’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of Memorial’s fair-valued proved natural gas and oil properties and (ii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016 were adjusted to exclude $37.2 million of merger-related costs incurred by Range and $7.1 million incurred by Memorial. The pro forma results of operations do not include any cost savings or other synergies that may result from the MRD Merger or any estimated costs that have been or will be incurred by us to integrate the Memorial assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the MRD Merger taken place on January 1, 2015. In addition, the pro forma financial information below is not intended to be a projection of future results (in thousands, except per share amounts).

		Year Ended December 31,
		2016			2015
Revenues	$	1,334,290		$	2,253,368
Net loss	$	(591,121	)	$	(556,164	)

Loss per share:
Basic	$	(2.42	)	$	(2.28	)
Diluted	$	(2.42	)	$	(2.28	)

Goodwill

12 Months Ended

Dec. 31, 2017

Goodwill And Intangible Assets Disclosure [Abstract]

Net Income (Loss) Per Common Share

(4)

Goodwill

Our goodwill relates to the excess of purchase price over amounts assigned to assets and liabilities from the MRD Merger which is equal to $1.6 billion at December 31, 2017. We performed a quantitative impairment test during third quarter 2017 due to a sustained decline in our market capitalization. Management utilized the assistance of a third-party valuation expert to determine the fair value of our business (our reporting unit). The fair value was determined based on a combination of a market and an income approach. As a result of this measurement, the fair value of our business exceeded the carrying value of net assets and no impairment was recorded. As of this date, our fair value exceeded book value by $1.4 billion or 24%. After considering the impact of the new tax law, our fair value exceeded our book value by $2.4 billion or 42%. For additional information regarding the new tax law, see Note 5.

During fourth quarter 2017, we conducted a qualitative impairment assessment, by examining relevant events and circumstances which could have a negative impact on our business such as: macroeconomic conditions, industry and market conditions, including the downturn in the oil and gas industry, cost factors that could have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and other relevant entity-specific events. We identified various factors to consider including commodity prices, our year-end proved reserves evaluation and the market value of our common stock. Our analysis indicated that the fair value of our business was not below book value. Although we based the fair value estimate on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain.

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

(5)	Income Taxes

Our income tax benefit was $251.0 million for the year ended December 31, 2017 compared to $280.8 million in 2016 and $338.7 million in 2015. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2017		2016			2015
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
Federal rate change	(406.7	)		—			—
State	(0.7	)		3.0			4.3
State rate and law change	(1.3	)		1.0			(0.2	)
Non-deductible executive compensation	0.7			(0.2	)		(0.1	)
Non-deductible MRD transaction costs	—			(0.6	)		—
Valuation allowances	36.8			(2.5	)		(6.8	)
Equity compensation	30.2			(0.7	)		—
Other	0.3			—			—
Consolidated effective tax rate	(305.7	%)		35.0	%		32.2	%

Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands):

		2017								2016										2015
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred			Total
U.S. federal	$	—	$	(302,507	)	$	(302,507	)	$	—	$	(266,105	)		$	(266,105	)		$		—	$		(328,257	)		$	(328,257	)
U.S. state and local		17		51,464			51,481			98		(14,743	)			(14,645	)				29			(10,449	)			(10,420	)
Total	$	17	$	(251,043	)	$	(251,026	)	$	98	$	(280,848	)		$	(280,750	)		$		29	$		(338,706	)		$	(338,677	)

Significant components of deferred tax assets and liabilities are as follows:

	December 31,
	2017			2016
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	413,672		$	478,203
Deferred compensation		24,704			50,808
Equity compensation		5,269			29,528
AMT credits and other credits		7,264			13,644
Asset retirement obligation		69,398			99,000
Cumulative mark-to-market loss		—			73,404
Other		18,806			39,922
Valuation allowances:
Federal		(31,308	)		(48,750	)
State, net of federal benefit		(93,826	)		(58,424	)
Total deferred tax assets		413,979			677,335
Deferred tax liabilities:
Depreciation, depletion and investments		(1,105,494	)		(1,619,922	)
Cumulative mark-to-market gain		(1,841	)		—
Other		—			(756	)
Total deferred tax liabilities		(1,107,335	)		(1,620,678	)
Net deferred tax liability	$	(693,356	)	$	(943,343	)

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. The law significantly reforms the Internal Revenue Code of 1986, as amended. The reduction in the corporate tax rate required a one-time revaluation of certain tax related assets and liabilities to reflect their value at the lower corporate tax rate of 21%. We reviewed all of the valuation allowances previously established at the corporate rate of 35% to reflect the appropriate new balances after the enactment of the new law. A one-time tax benefit was recorded related to the tax law changes in the amount of $334.0 million. Due to the complexities involved in accounting for the enactment of the new law, the SEC Staff Accounting Bulletin (“SAB”) 118 allows us to provide a provisional estimate for the year ending December 31, 2017. As of December 31, 2017, we have not completed our accounting for the tax effects of the new law and its impact on our deferred tax balances. We have made a reasonable estimate of the effect on our deferred tax balances. We will continue to analyze the impact of the new law and additional impacts will be recorded as they are identified during the measurement period as provided for in SAB 118.

At December 31, 2017, deferred tax liabilities exceeded deferred tax assets by $693.4 million. As of December 31, 2017, we have a valuation allowance of $1.9 million on the deferred tax asset related to our deferred compensation plan for planned future distributions to certain executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). As of December 31, 2017, we have a state valuation allowance of $36.3 million related to state tax attributes in Oklahoma, Texas and West Virginia. During 2017, we adjusted our valuation allowance related to our Pennsylvania state tax attributes to be $57.5 million due to the low commodity price environment and the limitation Pennsylvania places on future utilization of net operating loss carryforwards.

On October 18, 2017, the Supreme Court of Pennsylvania issued a decision on a case related to limiting net operating loss deductions to the greater of $3.0 million or 30 percent of taxable income. The Supreme Court ruled that the net operating loss deduction limitation violated the Uniformity Clause of the Pennsylvania Constitution and struck the $3.0 million flat cap limitation but not the percentage of taxable income limitation.

The changes in our deferred tax asset valuation allowances are as follows (in thousands):

		2017			2016			2015
Balance at the beginning of the year	$	(107,174	)	$	(87,623	)	$	(16,599	)
Charged to provision for income taxes:
State net operating loss carryforwards		(11,612	)		(17,374	)		(30,457	)
Federal net operating carryforwards		15,385			(1,100	)		(42,500	)
Other state valuation allowances		(23,790	)		500			(1,050	)
Other federal valuation allowances		(247	)		(477	)		(511	)
Rabbi trust valuation allowance		2,304			(1,066	)		3,494
Other		—			(34	)		—
Balance at the end of the year	$	(125,134	)	$	(107,174	)	$	(87,623	)

At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of $1.5 billion that expire between 2018 and 2035 and an NOL in Pennsylvania of $872.6 million that expire between 2025 and 2036. We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years 2013 and after and we are subject to various state tax examinations for years 2012 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense on interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2017. Throughout 2017, our unrecognized tax benefits were not material.

Net Income (Loss) Per Common Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

(6)	Net Income (Loss) per Common Share

Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts):


	Year Ended December 31,
	2017			2016			2015
Net income (loss), as reported	$	333,146		$	(521,388	)	$	(713,685	)
Participating basic earnings ^(a)		(3,751	)		(223	)		(450	)
Basic net income (loss) attributed to common stockholders		329,395			(521,611	)		(714,135	)
Reallocation of participating earnings ^(a)		5			—			—
Diluted net income (loss) attributed to common stockholders	$	329,400		$	(521,611	)	$	(714,135	)
Net income (loss) per common share:
Basic	$	1.34		$	(2.75	)	$	(4.29	)
Diluted	$	1.34		$	(2.75	)	$	(4.29	)

^(a)

Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):

	Year Ended December 31,
	2017	2016		2015
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	245,091		189,868		166,389
Effect of dilutive securities:
Director and employee restricted stock and performance-based equity awards	367		—		—
Weighted average common shares outstanding – diluted	245,458		189,868		166,389

⁽¹⁾

Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016.

Weighted average common shares – basic excludes 2.8 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for each of the periods ending December 31, 2017, 2016 and 2015. Due to our net loss for the years ended December 31, 2016 and 2015, we excluded all outstanding equity grants from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. Equity grants of 702,000 for the year ended December 31, 2017 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations. For purposes of calculating diluted weighted average common shares for the year ended December 31, 2017, nonvested restricted stock and performance – based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2017

Suspended Exploratory Well Costs

(7)	Suspended Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2017, 2016 and 2015 (in thousands, except for number of projects):

	2017			2016			2015
Balance at beginning of period	$	7,412		$	4,161		$	2,996
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,388			9,128			1,165
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—			(5,877	)		—
Capitalized exploratory well costs charged to expense		(8,800	)		—			—
Balance at end of period		—			7,412			4,161
Less exploratory well costs that have been capitalized for a period of one year or less		—			(7,412	)		(1,165	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	—		$	—		$	2,996
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		—			—			1

Indebtedness

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Indebtedness

(8) Indebtedness

We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at December 31, 2017 is shown parenthetically). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2017, 2016, and 2015.


		December 31, 2017			December 31, 2016
Bank debt (3.0%)	$	1,211,000		$	882,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,531			741,531
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022 ^(a)		329,244			329,244
Other senior notes due 2022 ^(b)		590			1,090
Total senior notes		2,877,349			2,877,849
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		4,137,329			3,808,829
Unamortized premium		6,027			7,241
Unamortized debt issuance costs		(34,550	)		(42,553	)
Total debt net of debt issuance costs	$	4,108,806		$	3,773,517

^(a) Represents senior notes assumed in the MRD Merger that were not purchased for cash but were exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below.

^(b) Represents the remaining Memorial 5.875% senior notes assumed in the MRD Merger that were not purchased for cash or were not exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below.

Bank Debt

In October 2014, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility has a maximum facility amount of $4.0 billion. As of December 31, 2017, the facility had a borrowing base of $3.0 billion and bank commitments of $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by each May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 21, 2017, our borrowing base was reaffirmed at $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. Our current bank group is comprised of twenty-nine financial institutions, with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. The commitment matures on October 16, 2019. As of December 31, 2017, the outstanding balance under the bank credit facility was $1.2 billion with $281.4 million of undrawn letters of credit leaving $507.6 million of borrowing capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility can either be at the alternate base rate (“ABR,” as defined in the bank credit agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to ABR loans or to convert all or any part of our ABR loans to LIBOR loans. The weighted average interest rate was 2.7% for the year ended December 31, 2017 compared to 2.2% for the year ended December 31, 2016 and 1.7% for the year ended December 31, 2015. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2017, the commitment fee was 0.3%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our ABR.

At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants will cease to apply, certain other restrictive covenants will become less restrictive and an additional financial covenant (as defined in the bank credit facility) will be temporarily imposed. During the investment grade period, borrowings under the bank credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance ranges from 0.15% to 0.30%. We currently do not have an investment grade rating.

Senior Notes

In September 2016, in conjunction with MRD Merger, we issued $329.2 million senior unsecured 5.875% notes due 2022 (the “5.875% Notes”) (See also Senior Notes Exchange and Cash Tender Offer below). In addition, we also completed a debt exchange offer to exchange senior subordinated notes for the following senior notes. (See also Senior Subordinated Notes Exchange below) (in thousands):

		Principal Amount
5.00% senior notes due 2023	$	741,531
5.00% senior notes due 2022	$	580,032
5.75% senior notes due 2021	$	475,952

All of the notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). On October 5, 2017, the 5.875% Notes, the 5.00% senior notes due 2023, the 5.00% senior notes due 2022 and the 5.75% senior notes due 2021 (collectively, the “Old Notes”) were exchanged for an equal principal amount of registered notes pursuant to an effective registration statement on Form S-4 filed with the SEC on August 9, 2017 under the Securities Act (the “New Notes”). The New Notes are identical to the Old Notes except the New Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any.

In May 2015, we issued $750.0 million aggregate principal amount of 4.875% senior notes due 2025 (the “Outstanding Notes”) for net proceeds of $737.4 million after underwriting discounts and commissions of $12.6 million. The notes were issued at par and were offered to qualified institutional buyers and non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. On April 8, 2016, all of the Outstanding Notes were exchanged for an equal principal amount of registered 4.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4 filed with the SEC on February 29, 2016 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Outstanding Notes except the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any.

Senior Notes Exchange and Cash Tender Offer

On September 16, 2016, we completed a debt exchange offer to exchange all validly tendered and accepted Memorial senior notes assumed in the MRD Merger. We exchanged 54.9% of the outstanding Memorial senior notes, whereby we issued the 5.875% Notes. The 5.875% Notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. Interest on the 5.875% Notes is payable in January and July. The 5.875% Notes will mature on July 1, 2022 and are unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. On or after April 1, 2022, we may redeem the 5.875% Notes in whole or in part and from time to time, at 100% of the principal amount, plus accrued and unpaid interest. The 5.875% Notes are unsecured and are subordinated to all of our existing and future secured debt, rank equally with all of our existing and future senior unsecured debt and rank senior to all of our existing and future subordinated debt. The deferred financing cost for this exchange was $6.3 million. The early cash tender premium paid was $4.1 million, which was paid to note holders who tendered their notes within the ten business day early offer period.

Also on September 16, 2016, we completed our concurrent offer to purchase for cash the Memorial senior notes assumed in the MRD Merger. We acquired 44.9% of the outstanding Memorial senior notes, or $269.7 million principal amount of the senior notes assumed in the MRD Merger, which we purchased for cash. The early cash tender premium paid was $3.3 million which was paid to note holders who tendered their notes within the ten business day early offer period. The cash tender offer and early cash tender premium were financed with borrowings under our bank credit facility. Concurrently with the Memorial senior note exchange offer and cash tender offer, we also solicited consents from the eligible holders to amend the indenture that governed the existing Memorial senior notes. The amendments included eliminating certain of the covenants, restrictive provisions, reporting requirements and events of default. Once a majority of consents were received, the amendments were accepted for all existing Memorial senior note holders, even if the senior notes were not tendered in either the exchange offer or cash tender offer.

Senior Subordinated Notes Exchange

On September 16, 2016, we also completed our debt exchange offer to exchange all validly tendered and accepted Range senior subordinated notes as detailed below (in thousands):


Existing Note	New Note	Principal Amount of Notes Validly Tendered ⁽¹⁾	Approximate Percentage Validly Tendered
5.00% senior subordinated notes due 2023	5.00% senior notes due 2023	$742,291	99.0%

5.00% senior subordinated notes due 2022	5.00% senior notes due 2022	$580,946	96.8%

5.75% senior subordinated notes due 2021	5.75% senior notes due 2021	$477,786	95.6%
⁽¹⁾Prior to exchange premium

We recorded $6.6 million of third party costs in interest expense in third quarter 2016 related to this exchange. The new senior notes were issued at par and were offered to qualified institutional buyers and non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. A $3.5 million premium was recorded in connection with the exchange for certain holders that participated in the exchange after the early tender period and received 95% of face amount tendered in exchange consideration. Interest on the new 5.00% senior notes due 2023 is payable in March and September with a maturity date of March 15, 2023. Interest on the new 5.00% senior notes due 2022 is payable in February and August with a maturity date of August 15, 2022. Interest on the new 5.75% senior notes due 2021 is payable in June and December with a maturity date of June 1, 2021. All of the new senior notes are unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. The new senior notes are unsecured and are subordinated to all of our existing and future senior secured debt and rank senior to all of our existing and future subordinated debt. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. Concurrently with the senior subordinated notes exchange offer, we also solicited consents from the eligible holders to amend the indentures that governed each of the existing senior subordinated notes. The amendments included eliminating certain of the covenants, restrictive provisions, reporting requirements and events of default. Once a majority of consents were received, the amendments were accepted for all senior subordinated note holders, even if the remaining senior subordinated notes were not exchanged.

Senior Subordinated Notes

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and to existing and future senior debt that we or our subsidiary guarantors are permitted to incur.

Early Extinguishment of Debt

In July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In the year ended 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly-owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes, our senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

•

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants and Maturity

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2017.

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2017 (in thousands):

	Year Ended December 31,
2018	$	—
2019		1,211,000
2020		—
2021		498,166
2022		928,920
Thereafter		1,499,243
	$	4,137,329

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(9)	Asset Retirement Obligations

Our asset retirement obligations primarily represent the present value of the estimated amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2017 and 2016 (in thousands):


	2017			2016
Beginning of period	$	257,943		$	264,137
Liabilities incurred		7,724			2,694
Acquisitions		—			21,900
Liabilities settled		(7,965	)		(11,511	)
Disposition of wells		(8,078	)		(10,540	)
Accretion expense		14,711			18,021
Change in estimate		12,520			(26,758	)
End of period		276,855			257,943
Less current portion		(6,327	)		(7,271	)
Long-term asset retirement obligations	$	270,528		$	250,672

Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

Capital Stock

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Capital Stock

(10)	Capital Stock

We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2015:


	Year Ended December 31,
	2017		2016			2015
Beginning balance		247,144,356		169,316,460			168,628,177
MRD Merger		—		77,042,749			—
Stock options/SARs exercised		—		—			77,002
Restricted stock grants		539,096		490,609			335,103
Restricted stock units vested		344,937		266,541			252,507
Performance stock units issued		85,461		—			—
Shares retired		—		(739	)		—
Treasury shares		15,580		28,736			23,671
Ending balance		248,129,430		247,144,356			169,316,460

Common Stock Dividends

The board of directors declared quarterly dividends of $0.02 per common share for each of the four quarters of 2017 and 2016. The board of directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2015. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations.

Derivative Activities

12 Months Ended

Dec. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Activities

(11)	Derivative Activities

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swap, swaptions or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Their fair value, which is represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price (generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs), approximated a net derivative asset of $13.6 million at December 31, 2017. These contracts expire monthly through December 2019. The following table sets forth the derivative volumes by year as of December 31, 2017, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2018	Swaps	794,822 Mmbtu/day	$ 3.13
2019	Swaps	12,329 Mmbtu/day	$ 3.01
January − March 2018	Collars	60,000 Mmbtu/day	$ 3.40-$ 3.76
April – December 2018	Swaptions	307,500 Mmbtu/day	$ 2.98 ⁽¹⁾
2019	Swaptions	85,000 Mmbtu/day	$ 2.97 ⁽¹⁾

Crude Oil
2018	Swaps	8,995 bbls/day	$ 53.30
2019	Swaps	4,746 bbls/day	$ 52.81

NGLs (C2-Ethane)
2018	Swaps	250 bbls/day	$ 0.29/gallon

NGLs (C3-Propane)
2018	Swaps	10,362 bbls/day	$ 0.68/gallon
2018	Collars	2,000 bbls/day	$ 0.90-$ 1.05/gallon

NGLs (NC4-Normal Butane)
2018	Swaps	4,621 bbls/day	$ 0.81/gallon

NGLs (C5-Natural Gasoline)
2018	Swaps	4,713 bbls/day	$ 1.19/gallon
2019	Swaps	1,000 bbls/day	$ 1.24/gallon

⁽¹⁾ Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volume. For April through December 2018, we have swaps in place for 147,500 Mmbtu per day on which the counterparty can elect to double the volume at a weighted average price of $2.89. We also have swaps in place for 160,000 Mmbtu per day on which the counterparty can elect to extend the contract through December 2019 at a weighted average price of $3.07. In 2019, if the counterparty elects to double the volume, we would have additional swaps covering 85,000 Mmbtu per day at a weighted average price of $2.97.

Basis Swap Contracts

In addition to the swaps, collars and swaptions above, at December 31, 2017, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through October 2019 and include a total volume of 120,892,500 Mmbtu. The fair value of these contracts was a net derivative liability of $7.8 million on December 31, 2017.

At December 31, 2017, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly through December 2018 and include a total volume of 1,362,000 barrels. The fair value of these contracts was a net derivative liability of $1.2 million on December 31, 2017.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2017, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly through December 2018 and cover 5,000 metric tons per month with a fair value net derivative asset of $276,000 on December 31, 2017. These contracts use observable third-party pricing inputs that we consider to be Level 2 fair value classification.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2017 and 2016 is summarized below (in thousands). As of December 31, 2017, we are conducting derivative activities with nineteen counterparties, of which all but five are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements.

		December 31, 2017
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	87,794	$	(4,106	)	$	83,688
	–swaptions		18,817		(8,103	)		10,714
	–basis swaps		1,815		(6,673	)		(4,858	)
	–collars		3,039		(500	)		2,539
Crude oil	–swaps		2		(7,928	)		(7,926	)
NGLs	–C2 ethane swaps		57		—			57
	–C3 propane swaps		—		(12,556	)		(12,556	)
	–C3 propane collars		85		(85	)		—
	–C3 propane spread swaps		12,762		(12,762	)		—
	–NC4 butane swaps		—		(6,051	)		(6,051	)
	–C5 natural gasoline swaps		—		(6,727	)		(6,727	)
Freight	–swaps		276		(276	)		—
		$	124,647	$	(65,767	)	$	58,880

		December 31, 2017
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(216	)	$	4,106	$	3,890
	–swaptions		(12,283	)		8,103		(4,180	)
	–basis swaps		(9,580	)		6,673		(2,907	)
	–collars		—			500		500
Crude oil	–swaps		(24,726	)		7,928		(16,798	)
NGLs	–C3 propane swaps		(34,325	)		12,556		(21,769	)
	–C3 propane collars		—			85		85
	–C3 propane spread swaps		(13,983	)		12,762		(1,221	)
	–NC4 butane swaps		(11,188	)		6,051		(5,137	)
	–C5 natural gasoline swaps		(13,488	)		6,727		(6,761	)
Freight	–swaps		—			276		276
		$	(119,789	)	$	65,767	$	(54,022	)

		December 31, 2016
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	13,213	$	(11,425	)	$	1,788
	–basis swaps		12,535		(9,437	)		3,098
	–collars		6,298		(6,298	)		—
	–puts		18,159		(15,429	)		2,730
Crude oil	–swaps		9,356		(3,489	)		5,867
NGLs	–C2 ethane swaps		53		(53	)		—
	–C3 propane spread swaps		17,396		(17,396	)		—
	–NC4 butane swaps		4		(4	)		—
Freight	–swaps		65		(65	)		—
		$	77,079	$	(63,596	)	$	13,483

		December 31, 2016
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(158,359	)	$	11,425	$	(146,934	)
	–basis swaps		(687	)		9,437		8,750
	–collars		(2,625	)		6,298		3,673
	–puts		—			15,429		15,429
	–calls		(1,041	)		—		(1,041	)
Crude oil	–swaps		(13,206	)		3,489		(9,717	)
NGLs	–C2 ethane swaps		(1,008	)		53		(955	)
	–C3 propane swaps		(32,437	)		—		(32,437	)
	–C3 propane spread swaps		(18,138	)		17,396		(742	)
	–NC4 butane swaps		(13,419	)		4		(13,415	)
	–C5 natural gasoline swaps		(12,176	)		—		(12,176	)
Freight	–swaps		—			65		65
		$	(253,096	)	$	63,596	$	(189,500	)

The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands).

	Year Ended December 31,
	Derivative Fair Value Income (Loss)
	2017			2016			2015
Commodity Swaps	$	181,095		$	(265,466	)	$	398,020
Swaptions		6,534			—			—
Re-purchased swaps		—			—			851
Collars		18,132			(6,926	)		16,539
Basis swaps		(4,647	)		29,154			954
Puts		10,929			(18,201	)		—
Calls		987			(18	)		—
Freight swaps		320			66			—
Total	$	213,350		$	(261,391	)	$	416,364

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

(12)	Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•

Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair Values-Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

		Fair Value Measurements at December 31, 2017 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2017
Trading securities held in the deferred compensation plans		$	67,117	$	—		$	—	$	67,117
Derivatives	–swaps		—		3,910			—		3,910
	–collars		—		3,039			85		3,124
	–basis swaps		—		(9,025	)		39		(8,986	)
	–freight swaps		—		276			—		276
	–swaptions		—		—			6,534		6,534

		Fair Value Measurements at December 31, 2016 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2016
Trading securities held in the deferred compensation plans		$	61,717	$	—		$	—	$	61,717
Derivatives	–swaps		—		(207,979	)		—		(207,979	)
	–collars		—		3,673			—		3,673
	–puts		—		18,159			—		18,159
	–calls		—		(1,041	)		—		(1,041	)
	–basis swaps		—		11,106			—		11,106
	–freight swaps		—		65			—		65

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2017 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. As of December 31, 2017, a portion of our natural gas derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a predetermined date. Derivatives in Level 3 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

		Year Ended December 31, 2017
Balance at the beginning of period	$	—
Total gains (losses):
Included in earnings		6,658
Settlements received		—
Transfers in and/or out of Level 3		—
Balance at end of period	$	6,658

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For the year ended December 31, 2017, interest and dividends were $4.1 million and mark-to-market was a gain of $4.2 million. For the year ended December 31, 2016, interest and dividends were $972,000 and mark-to-market was a gain of $3.1 million. For the year ended December 31, 2015, interest and dividends were $908,000 and mark-to-market was a loss of $5.9 million.

Fair Values-Non recurring

Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of certain natural gas and oil properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. In some cases, we also considered the potential sale of certain of these properties. We recorded non-cash charges during the year ended 2017 of $63.7 million related to certain of our oil and gas properties in Oklahoma and the Texas Panhandle. We recorded non-cash charges during the year ended 2016 of $43.0 million related to certain of our natural gas and oil properties in Western Oklahoma. We recorded non-cash charges of $306.6 million during the year ended 2015 related to natural gas and oil properties in Northern Oklahoma, $195.6 million related to our shallow legacy oil and natural gas assets in Northwest Pennsylvania, $86.9 million related to our assets in the Texas Panhandle and $1.1 million related to our onshore Gulf Coast properties. The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands):

	Year Ended December 31,
	2017				2016				2015
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	85,597	$	63,679	$	90,150	$	43,040	$	152,230	$	590,174

Fair Values - Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2017 and 2016 (in thousands):

	December 31, 2017						December 31, 2016
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	58,880		$	58,880		$	13,483		$	13,483
Marketable securities ^(a)		67,117			67,117			61,717			61,717
(Liabilities):
Commodity swaps, options and basis swaps		(54,022	)		(54,022	)		(189,500	)		(189,500	)
Bank credit facility ^(b)		(1,211,000	)		(1,211,000	)		(882,000	)		(882,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(493,872	)		(475,952	)		(496,180	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(578,727	)		(580,032	)		(577,132	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(339,200	)		(329,244	)		(343,648	)
Other senior notes due 2022 ^(b)		(590	)		(591	)		(1,090	)		(1,104	)
5.00% senior notes due 2023 ^(b)		(741,531	)		(735,614	)		(741,531	)		(735,043	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(733,755	)		(750,000	)		(724,688	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,192	)		(22,214	)		(22,325	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,741	)		(19,054	)		(18,387	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,614	)		(7,712	)		(7,645	)
Deferred compensation plan ^(c)		(114,414	)		(114,414	)		(139,580	)		(139,580	)

^(a)	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

^(c)	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Stock-based Compensation Plans

12 Months Ended

Dec. 31, 2017

Stock-based Compensation Plans

(13)	Stock-Based Compensation Plans

Description of the Plans

The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the compensation committee of the board of directors to grant, among other things, stock options, SARs, PSUs and restricted stock awards to employees. The 2005 Plan also allows us to provide equity compensation to our non-employee directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares plus (ii) the number of shares subject to the 1999 Stock Option Plan awards outstanding at May 18, 2005 that subsequently lapse or terminate without the underlying shares being issued plus (iii) subsequent shares approved by the stockholders. Shares issued as a result of awards granted are generally new common shares.

After the approval of the 2005 Plan, no new grants have been made from the 1999 Stock Option Plan. In addition, our 2004 Non-Employee Director Stock Option Plan expired at the end of 2014. Any awards previously granted under the 1999 Stock Option Plan or the 2004 Non-Employee Director Stock Option Plan continue to be exercisable in accordance with their original terms and conditions.

Total Stock-Based Compensation Expense

Stock-based compensation expense represents amortization of restricted stock and performance units. The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2017 (in thousands):

	2017 ⁽¹⁾		2016			2015
Direct operating expense	$	2,060		$	2,302		$	2,780
Brokered natural gas and marketing expense		1,437			1,725			2,132
Exploration expense		2,742			2,298			2,985
General and administrative expense		74,873			49,293			49,687
Termination costs		1,664			—			217
Total	$	82,776		$	55,618		$	57,801

⁽¹⁾

Includes $30.8 million accelerated vesting of equity grants.

In fourth quarter 2017, the compensation committee approved a new post-retirement benefit plan (See Other Post Retirement Benefits below). Along with establishing the new health care benefit plan for certain officers that have met the required age and service requirements and with the intention of improving our management succession plan, those officers who qualify for the new post-retirement health care plan were fully vested in all equity grants. The one-time impact of the acceleration of these equity grants was $30.8 million in fourth quarter 2017.

Unlike the other forms of stock-based compensation expense mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses. Therefore, the liability related to the vested restricted stock held in our deferred compensation plans is not allocated to the functional categories and is reported as deferred compensation plan expense in the accompanying consolidated statements of operations.

In 2017, we recorded $5.3 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested during 2017. In 2016, we recorded $5.7 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested during 2016. In 2015, the tax deduction for stock-based compensation was less than the book stock-based compensation expense for equity compensation grants vested or exercised during the year. The tax effect of the 2015 deduction was recorded as a reduction to additional paid-in capital.

Stock-Based Awards

Restricted Stock Awards. We grant restricted stock units under our equity-based stock compensation plan. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three year period, contingent on the recipient’s continued employment. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant.

The compensation committee also grants restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock (by the trustee) and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also utilize treasury shares when available.

Stock-Based Performance Units. We grant three types of performance share awards: two based on performance conditions measured against internal performance metrics (Production Growth Awards or “PG-PSUs” and Reserve Growth Awards or “RG-PSUs” and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Award or “TSR-PSUs”).

At grant date, each unit represents the value of one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can be from zero to 150% based on performance achieved and (2) the value of our common stock on the date vesting is determined by the Compensation Committee. Dividend equivalent may accrue during the performance period and would be paid in stock at the end of the performance period. The performance period is a three year period.

SARs. At December 31, 2017, there were 383,000 SARs outstanding.

Restricted Stock – Equity Awards

In 2017, we granted 888,000 restricted stock Equity Awards to employees which generally vest over a three-year period compared to 973,000 in 2016 and 588,000 in 2015. We recorded compensation expense for these awards of $23.4 million in the year ended December 31, 2017 compared to $22.8 million in 2016 and $23.8 million in 2015. As of December 31, 2017, there was $24.4 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 years. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash.

Restricted Stock – Liability Awards

In 2017, we granted 543,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $25.91. This grant included 90,000 issued to non-employee directors which vest immediately and 453,000 to employees with vesting generally over a three year period. In 2016, we granted 540,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $35.92. This grant included 59,000 issued to non-employee directors which vest immediately and 481,000 to employees with vesting generally over a three-year period. In 2015, we granted 343,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $55.92. This grant included 48,000 issued to non-employee directors, which vest immediately and 295,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $30.4 million in the year ended December 31, 2017 compared to $18.6 million in 2016 and $20.8 million in 2015. Accelerated vesting compensation expense of $15.4 million is included in the year ended December 31, 2017. As of December 31, 2017, there was $1.7 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.6 years. The majority of all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $4.5 million in 2017 compared to $13.1 million in 2016 and $8.3 million in 2015. The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2017:

	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014		360,415		$	79.60		304,504		$	80.33
Granted		587,711			52.29		343,397			55.92
Vested		(480,253	)		65.21		(330,870	)		68.71
Forfeited		(31,109	)		64.73		(8,294	)		74.22
Outstanding at December 31, 2015		436,764			59.74		308,737			65.80
Granted		973,491			28.51		540,128			35.92
Vested		(525,617	)		43.83		(374,328	)		51.40
Forfeited		(118,667	)		42.60		(49,519	)		40.33
Outstanding at December 31, 2016		765,971			33.62		425,018			43.48
Granted		888,326			32.61		543,438			25.91
Vested		(698,563	)		34.82		(908,912	)		33.71
Forfeited		(122,676	)		32.91		(4,342	)		31.10
Outstanding at December 31, 2017		833,058		$	31.64		55,202		$	32.26

Stock-Based Performance Units

Production Growth and Reserve Growth Awards. The PG-PSUs and RG-PSUs vest at the end of the three-year performance period. The performance metrics for each year are set by the Compensation Committee no later than March 31 of such year. Based on our probability assessment at December 31, 2017, it is considered not probable that the criteria for the 2017 PG-PSUs will be met but it is considered probable that the criteria for the 2017 RG-PSUs will be met. If the performance metric for the applicable period is not met, then the portion is considered forfeited. The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December 31, 2017:


	Number of Units		Weighted Average Grant Date Fair Value of Range Stock
Outstanding at December 31, 2016	—		—
Units granted ^(a)	122,921	$	25.53
Outstanding at December 30, 2017	122,921	$	25.53

^(a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 150% depending on achievement of specifically identified performance targets.

We recorded PG/RG-PSUs compensation expense of $1.8 million in the year ended December 31, 2017, which includes $1.5 million accelerated vesting compensation expense.

TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31, 2017
	2017			2016			2015
Risk-free interest rate		1.49	%		0.94	%		1.02	%
Expected annual volatility		44	%		49	%		33	%
Grant date fair value per unit	$	26.26		$	36.64		$	56.78

The following is a summary of our non-vested TSR – PSUs award activities:

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014		226,418		$	86.16
Granted ^(a)		276,204			56.78
Forfeited		(2,679	)		82.60
Outstanding at December 31, 2015		499,943			69.95
Granted ^(a)		413,959			36.64
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		871,299			55.29
Granted ^(a)		358,519			26.26
Vested and issued ^(b)		(85,461	)		86.23
Forfeited		(134,515	)		85.24
Outstanding at December 31, 2017		1,009,842		$	38.38

^(a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 150% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

^(b⁾ Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67^th percentile for the February 2014 grant and 56^th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited.

We recorded TSR-PSU compensation expense of $24.8 million in the year ended December 31, 2017 compared to $12.4 million in the year ended December 31, 2016 and $8.7 million in the year ended December 31, 2015. Accelerated vesting compensation expense of $13.0 million is included in the year ended December 31, 2017. As of December 31, 2017, there was $1.2 million of unrecognized compensation related to PSU awards to be recognized over a weighted average period of 2.0 years.

SARs

Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2014		1,966,549		$	59.80
Exercised		(427,598	)		45.67
Expired/forfeited		(27,974	)		63.10
Outstanding at December 31, 2015		1,510,977			63.73
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600			69.08
Expired/forfeited		(620,821	)		62.29
Outstanding at December 31, 2017		382,779		$	76.54

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2017:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 70.00–$ 79.99		380,879		0.36	$	76.51		380,879	$	76.51
80.00–81.15		1,900		0.69		81.15		1,900		81.15
Total		382,779		0.36	$	76.54		382,779	$	76.54

The expected dividend yield is based on the current annual dividend at the time of grant. The expected life is based on the historical exercise activity. The expected volatility factors are based on a combination of both the historical volatilities of the stock and implied volatility of traded options on our common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options.

The total intrinsic value (the difference in value between exercise and market price at the time of grant) of SARs exercised during the year ended December 31, 2015 was $5.4 million. There were no SARs exercised in 2017 or 2016. As of December 31, 2017, there was no aggregate intrinsic value for any of the awards exercisable or awards outstanding. The weighted average remaining contractual life of awards exercisable was less than one year. As of December 31, 2017, the number of fully vested awards and the awards expected to vest was 383,000 shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $76.54 and 0.4 years. As of December 31, 2017, there was no unrecognized compensation cost related to the awards.

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. We match up to 6% of salary in cash and vesting of those contributions is immediate. In 2017, we contributed $5.1 million to the 401(k) Plan compared to $4.7 million in 2016 and $6.1 million in 2015. Employees have a variety of investment options in the 401(k) benefit plan.

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market gain of $50.9 million in 2017 compared to a loss of $19.2 million in 2016 and a gain of $77.6 million in 2015. The Rabbi Trust held 2.9 million shares (2.8 million of vested shares) of Range stock at December 31, 2017 compared to 2.7 million (2.3 million of vested shares) at December 31, 2016.

Other Post Retirement Benefits

Effective fourth quarter 2017, we implemented a post-retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features (in thousands).

	December 31, 2017
Accumulated benefit obligation	$	1,769

Change in benefit obligations (recognized in comprehensive income – pretax)
Beginning balance at December 31, 2016	$	—
Prior service cost		1,769
Total other comprehensive income (loss) at December 31, 2017	$	1,769

Amounts recognized in the consolidated balance sheets:
Noncurrent liability-accrued benefit cost	$	1,769

The following summarizes the assumptions used to determine the benefit obligation at December 31, 2017.

	December 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate		3.3	%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate		7.00	%
Ultimate trend rate		5.00	%
Year ultimate trend rate reached		2028

The expected future benefit payments under our post-retirement medical plan for the next ten years is $675,000 for the five year period 2018 through 2022 and $638,000 for the five year period 2023 through 2027. The estimated prior service cost that will be amortized from accumulated other comprehensive income into our statement of operations in 2018 is $369,000.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

(14)	Supplemental Cash Flow Information

	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(1,024	)	$	(102	)	$	100
Interest paid		179,431			159,875			168,826
Non-cash investing and financing activities included ^(a):
Asset retirement costs capitalized, net	$	20,245		$	(24,064	)	$	22,184
Increase (decrease) in accrued capital expenditures		71,739			61,419			(225,455	)

^(a)

For additional information on non-cash investing activities associated with the MRD Merger, see Note 3.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

(15)	Commitments and Contingencies

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

Lease Commitments

We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $19.1 million in 2017 compared to $14.0 million in 2016 and $15.9 million in 2015. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):

	Operating Lease Obligations		Sublease Rental Receipts
2018	$	18,498	$	3,472
2019		17,803		3,472
2020		16,945		3,174
2021		14,249		2,578
2022		8,058		215
Thereafter		32,909		—
	$	108,462	$	12,911

Transportation, Gathering and Processing Contracts

We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As part of our purchase price allocation of liabilities that existed at the time of the MRD Merger, we have a remaining liability of $25.1 million for certain expected volume deficiency payments related to our properties in North Louisiana. As of December 31, 2017, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands):

	Transportation, Gathering and Processing Contracts ^(a)
2018	$	805,161
2019		825,231
2020		767,090
2021		733,133
2022		691,968
Thereafter		4,689,133
	$	8,511,716

^(a) The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

In addition to the amounts included in the above table, we have entered into an additional agreement which is contingent on certain pipeline modifications and/or construction. This agreement has a twenty year term and may begin in 2018. Based on this contract, we will have additional transportation obligations for natural gas volumes of 400,000 mcf per day until 2038.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2017, our delivery commitments through 2031 were as follows:

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2018		382,534	71,000
2019		364,356	55,932
2020		252,878	48,625
2021		116,189	48,000
2022		68,712	43,000
2023		—	35,000
2024—2028		—	35,000
2029—2031		—	20,000

In addition to the amounts included in the above table, we have contracted with a pipeline company through 2020 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon pipeline construction and/or modification, are for 13,000 bbls per day starting in 2018. In addition, we have agreements in place to deliver natural gas volumes from our Marcellus Shale wells, which are also contingent upon pipeline construction and/or modification, for 15,000 mcf per day starting in late 2018, increasing to 65,000 mcf per day in early 2019 and 180,000 mcf per day in late 2019.

Other

We also have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Office Closing and Exit Costs

12 Months Ended

Dec. 31, 2017

Restructuring And Related Activities [Abstract]

Office Closing and Exit Costs

(16)	Office Closing and Exit Costs

In first quarter 2015, we announced the closing of our Oklahoma City administrative and operational office in order to lower our general and administrative expenses, due in part to the impact of lower commodity prices on our operations. In fourth quarter 2014, we initially accrued an estimated $8.4 million of termination costs relating to the closure of this office as it had become probable of occurring. In early 2015, the plans to close the Oklahoma City office were finalized which resulted in additional accruals in 2015 for severance and other personnel costs of $275,000, additional accelerated vesting of stock-based compensation of $948,000 and $3.1 million of building lease costs. In the year ended December 31, 2015 additional accruals for severance of $11.4 million and a gain of $731,000 of accelerated vesting of stock-based compensation related to the sale of our Virginia and West Virginia properties which closed on December 30, 2015 and additional reductions in our work force due to the lower commodity price environment. There are no office closing or termination costs associated with the MRD Merger in 2016. As part of a continuing effort to reduce our general and administrative expenses due to the lower commodity price environment, additional accruals for severance of $2.2 million and accelerated vesting of stock-based compensation of $1.7 million were recorded in the year ended December 31, 2017. The following table details the accrued liability as of December 31, 2017 and December 31, 2016 (in thousands):

		2017			2016
Beginning balance	$	2,460		$	11,630
Accrued severance costs		2,176			(822	)
Accrued building rent		(70	)		303
Payments		(2,711	)		(8,651	)
Ending balance	$	1,855		$	2,460

The following summarizes our termination costs for three years ended December 31, 2017, 2016 and 2015 (in thousands):

		2017			2016			2015
Severance costs	$	2,176		$	(822	)	$	11,706
Building lease		(70	)		303			3,147
Stock-based compensation		1,664			—			217
Total termination costs	$	3,770		$	(519	)	$	15,070

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data (Unaudited)

(17)	Selected Quarterly Financial Data (Unaudited)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Third quarter 2017 includes impairment expense of $63.7 million related to oil and gas properties in Oklahoma and Texas. Fourth quarter 2017 deferred income tax benefit includes the impact of the Tax Cuts and Jobs Act of 2017 which was signed into law on December 22, 2017. First quarter 2016 includes impairment expense of $43.0 million related to oil and gas properties in Western Oklahoma. Second quarter, third quarter and fourth quarter 2016 include a total of $37.2 million of expenses related to the MRD Merger (in thousands, except per share data):

	2017
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	559,450		$	506,137		$	507,541		$	603,159		$	2,176,287
Derivative fair value income (loss)		165,557			111,195			(88,426	)		25,024			213,350
Brokered natural gas, marketing and other		51,648			55,779			63,117			50,849			221,393
Total revenue and other income		776,655			673,111			482,232			679,032			2,611,030
Costs and expenses:
Direct operating		28,023			31,420			36,888			37,921			134,252
Transportation, gathering, processing and compression		177,648			191,590			191,645			200,300			761,183
Production and ad valorem taxes		9,163			9,969			11,993			11,757			42,882
Brokered natural gas and marketing		53,550			55,857			59,773			51,131			220,311
Exploration		8,504			14,498			22,767			7,893			53,662
Abandonment and impairment of unproved properties		4,420			5,193			42,568			217,544			269,725
General and administrative		47,496			52,322			53,035			80,553			233,406
Termination costs		4,192			(96	)		(47	)		(279	)		3,770
Deferred compensation plan		(13,169	)		(14,466	)		(9,203	)		(14,077	)		(50,915	)
Interest		47,101			47,926			49,179			51,473			195,679
Depletion, depreciation and amortization		149,821			152,504			159,749			162,918			624,992
Impairment of proved properties and other		—			—			63,679			—			63,679
(Gain) loss on sale of assets		(22,600	)		(807	)		(102	)		(207	)		(23,716	)
Total costs and expenses		494,149			545,910			681,924			806,927			2,528,910

Income (loss) before income taxes		282,506			127,201			(199,692	)		(127,895	)		82,120
Income tax expense (benefit):
Current		—			—			—			17			17
Deferred		112,395			57,651			(71,992	)		(349,097	)		(251,043	)
		112,395			57,651			(71,992	)		(349,080	)		(251,026	)
Net income (loss)	$	170,111		$	69,550		$	(127,700	)	$	221,185		$	333,146
Net income (loss) per common share:
Basic	$	0.69		$	0.28		$	(0.52	)	$	0.89		$	1.34
Diluted	$	0.69		$	0.28		$	(0.52	)	$	0.89		$	1.34

	2016
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	209,487		$	224,606		$	304,477		$	458,645		$	1,197,215
Derivative fair value income (loss)		86,908			(162,798	)		64,556			(250,057	)		(261,391	)
Brokered natural gas, marketing and other		35,018			39,989			44,174			44,934			164,115
Total revenue and other income		331,413			101,797			413,207			253,522			1,099,939
Costs and expenses:
Direct operating		24,054			20,671			22,387			30,276			97,388
Transportation, gathering, processing and compression		125,263			136,844			138,764			164,338			565,209
Production and ad valorem taxes		5,887			6,049			6,717			6,790			25,443
Brokered natural gas and marketing		36,558			40,925			44,622			46,471			168,576
Exploration		4,913			6,785			6,943			13,684			32,325
Abandonment and impairment of unproved properties		10,628			7,059			6,082			6,307			30,076
General and administrative		40,657			46,064			41,024			57,027			184,772
MRD Merger expenses		—			2,621			33,791			813			37,225
Termination costs		162			5			136			(822	)		(519	)
Deferred compensation plan		16,056			25,746			(11,636	)		(11,013	)		19,153
Interest		37,739			37,758			45,967			46,749			168,213
Depletion, depreciation and amortization		120,561			122,390			131,489			149,662			524,102
Impairment of proved properties and other		43,040			—			—			—			43,040
Loss (gain) on sale of assets		1,643			3,304			2,597			(470	)		7,074
Total costs and expenses		467,161			456,221			468,883			509,812			1,902,077

Loss before income taxes		(135,748	)		(354,424	)		(55,676	)		(256,290	)		(802,138	)
Income tax expense (benefit):
Current		—			—			—			98			98
Deferred		(41,976	)		(129,488	)		(13,705	)		(95,679	)		(280,848	)
		(41,976	)		(129,488	)		(13,705	)		(95,581	)		(280,750	)
Net loss	$	(93,772	)	$	(224,936	)	$	(41,971	)	$	(160,709	)	$	(521,388	)
Net loss per common share:
Basic	$	(0.56	)	$	(1.35	)	$	(0.23	)	$	(0.66	)	$	(2.75	)
Diluted	$	(0.56	)	$	(1.35	)	$	(0.23	)	$	(0.66	)	$	(2.75	)

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

12 Months Ended

Dec. 31, 2017

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

(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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated.

Use of Estimates

Business Segment Information

Revenue Recognition, Accounts Receivable and Gas Imbalances

Cash and Cash Equivalents

Marketable Securities

Inventory

Natural Gas and Oil Properties

Other Property and Equipment

Other Assets

Stock-based Compensation Arrangements

Derivative Financial Instruments and Hedging

Concentrations of Credit Risk

Asset Retirement Obligations

Environmental Costs

Deferred Taxes

New Accounting Pronouncements

Recently Adopted

		For The Three Months Ended March 31, 2016
		As Reported			As Adjusted
Statements of Operations:
Income tax benefit	$	(44,038	)	$	(41,976	)
Net loss		(91,710	)		(93,772	)
Basic earnings per share		(0.55	)		(0.56	)
Diluted earnings per share		(0.55	)		(0.56	)

		As Reported		As Adjusted
		Net cash provided from operating activities		Net cash provided from operating activities
Year ended 2015	$	683,700	$	691,402
Year ended 2014		954,135		974,353
Year ended 2013		743,538		757,373
Three months ended March 31, 2016		87,424		90,785
Six months ended June 30, 2016		169,604		173,201
Nine months ended September 30, 2016		202,037		205,837

		As Reported			As Adjusted
		Net cash (used in) provided from financing activities			Net cash (used in) provided from financing activities
Year ended 2015	$	(464,905	)	$	(472,607	)
Year ended 2014		291,421			271,203
Year ended 2013		239,994			226,159
Three months ended March 31, 2016		(72,473	)		(75,834	)
Six months ended June 30, 2016		(95,411	)		(99,008	)
Nine months ended September 30, 2016		(35,229	)		(39,029	)

Accounting Pronouncements Not Yet Adopted

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard

		For The Three Months Ended March 31, 2016
		As Reported			As Adjusted
Statements of Operations:
Income tax benefit	$	(44,038	)	$	(41,976	)
Net loss		(91,710	)		(93,772	)
Basic earnings per share		(0.55	)		(0.56	)
Diluted earnings per share		(0.55	)		(0.56	)

		As Reported		As Adjusted
		Net cash provided from operating activities		Net cash provided from operating activities
Year ended 2015	$	683,700	$	691,402
Year ended 2014		954,135		974,353
Year ended 2013		743,538		757,373
Three months ended March 31, 2016		87,424		90,785
Six months ended June 30, 2016		169,604		173,201
Nine months ended September 30, 2016		202,037		205,837

		As Reported			As Adjusted
		Net cash (used in) provided from financing activities			Net cash (used in) provided from financing activities
Year ended 2015	$	(464,905	)	$	(472,607	)
Year ended 2014		291,421			271,203
Year ended 2013		239,994			226,159
Three months ended March 31, 2016		(72,473	)		(75,834	)
Six months ended June 30, 2016		(95,411	)		(99,008	)
Nine months ended September 30, 2016		(35,229	)		(39,029	)

Dispositions and Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Summary of Final Allocation of Total Purchase Price

Purchase price:
Shares of Range common stock issued to Memorial stockholders		77,042,749
Range common stock price per share at September 15, 2016 (close)	$	39.37
Total purchase price	$	3,033,173

Plus fair value of liabilities assumed by Range:
Accounts payable	$	55,624
Other current liabilities		108,367
Long-term debt		1,204,449
Deferred taxes		547,706
Other long-term liabilities		77,223
Total purchase price plus liabilities assumed	$	5,026,542

Fair value of Memorial assets:
Cash and equivalents	$	7,180
Other current assets		99,969
Derivative instruments		152,994
Natural gas and oil properties:
Proved property		1,122,311
Unproved property		1,999,187
Other property and equipment		3,579
Goodwill ^(a)		1,641,197
Other		125
Total asset value	$	5,026,542

^(a)Goodwill will not be deductible for income tax purposes.

Summary of Pro Forma Financial Information

The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the MRD Merger taken place on January 1, 2015. In addition, the pro forma financial information below is not intended to be a projection of future results (in thousands, except per share amounts).

		Year Ended December 31,
		2016			2015
Revenues	$	1,334,290		$	2,253,368
Net loss	$	(591,121	)	$	(556,164	)

Loss per share:
Basic	$	(2.42	)	$	(2.28	)
Diluted	$	(2.42	)	$	(2.28	)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax


	Year Ended December 31,
	2017		2016			2015
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
Federal rate change	(406.7	)		—			—
State	(0.7	)		3.0			4.3
State rate and law change	(1.3	)		1.0			(0.2	)
Non-deductible executive compensation	0.7			(0.2	)		(0.1	)
Non-deductible MRD transaction costs	—			(0.6	)		—
Valuation allowances	36.8			(2.5	)		(6.8	)
Equity compensation	30.2			(0.7	)		—
Other	0.3			—			—
Consolidated effective tax rate	(305.7	%)		35.0	%		32.2	%

Income Tax (Benefit) Expense Attributable to Income Before Income Taxes

Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands):

		2017								2016										2015
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred			Total
U.S. federal	$	—	$	(302,507	)	$	(302,507	)	$	—	$	(266,105	)		$	(266,105	)		$		—	$		(328,257	)		$	(328,257	)
U.S. state and local		17		51,464			51,481			98		(14,743	)			(14,645	)				29			(10,449	)			(10,420	)
Total	$	17	$	(251,043	)	$	(251,026	)	$	98	$	(280,848	)		$	(280,750	)		$		29	$		(338,706	)		$	(338,677	)

Significant Components of Deferred Tax Assets and Liabilities

Significant components of deferred tax assets and liabilities are as follows:

	December 31,
	2017			2016
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	413,672		$	478,203
Deferred compensation		24,704			50,808
Equity compensation		5,269			29,528
AMT credits and other credits		7,264			13,644
Asset retirement obligation		69,398			99,000
Cumulative mark-to-market loss		—			73,404
Other		18,806			39,922
Valuation allowances:
Federal		(31,308	)		(48,750	)
State, net of federal benefit		(93,826	)		(58,424	)
Total deferred tax assets		413,979			677,335
Deferred tax liabilities:
Depreciation, depletion and investments		(1,105,494	)		(1,619,922	)
Cumulative mark-to-market gain		(1,841	)		—
Other		—			(756	)
Total deferred tax liabilities		(1,107,335	)		(1,620,678	)
Net deferred tax liability	$	(693,356	)	$	(943,343	)

Changes in Deferred Tax Asset Valuation Allowances

The changes in our deferred tax asset valuation allowances are as follows (in thousands):

		2017			2016			2015
Balance at the beginning of the year	$	(107,174	)	$	(87,623	)	$	(16,599	)
Charged to provision for income taxes:
State net operating loss carryforwards		(11,612	)		(17,374	)		(30,457	)
Federal net operating carryforwards		15,385			(1,100	)		(42,500	)
Other state valuation allowances		(23,790	)		500			(1,050	)
Other federal valuation allowances		(247	)		(477	)		(511	)
Rabbi trust valuation allowance		2,304			(1,066	)		3,494
Other		—			(34	)		—
Balance at the end of the year	$	(125,134	)	$	(107,174	)	$	(87,623	)

Net Income (Loss) Per Common Share (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Computations of Basic and Diluted Income (Loss ) Per Common Share


	Year Ended December 31,
	2017			2016			2015
Net income (loss), as reported	$	333,146		$	(521,388	)	$	(713,685	)
Participating basic earnings ^(a)		(3,751	)		(223	)		(450	)
Basic net income (loss) attributed to common stockholders		329,395			(521,611	)		(714,135	)
Reallocation of participating earnings ^(a)		5			—			—
Diluted net income (loss) attributed to common stockholders	$	329,400		$	(521,611	)	$	(714,135	)
Net income (loss) per common share:
Basic	$	1.34		$	(2.75	)	$	(4.29	)
Diluted	$	1.34		$	(2.75	)	$	(4.29	)

^(a)

Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):

	Year Ended December 31,
	2017	2016		2015
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	245,091		189,868		166,389
Effect of dilutive securities:
Director and employee restricted stock and performance-based equity awards	367		—		—
Weighted average common shares outstanding – diluted	245,458		189,868		166,389

⁽¹⁾

Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016.

Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2017

Suspended Exploratory Well Costs

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2017, 2016 and 2015 (in thousands, except for number of projects):

	2017			2016			2015
Balance at beginning of period	$	7,412		$	4,161		$	2,996
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,388			9,128			1,165
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—			(5,877	)		—
Capitalized exploratory well costs charged to expense		(8,800	)		—			—
Balance at end of period		—			7,412			4,161
Less exploratory well costs that have been capitalized for a period of one year or less		—			(7,412	)		(1,165	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	—		$	—		$	2,996
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		—			—			1

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt Outstanding


		December 31, 2017			December 31, 2016
Bank debt (3.0%)	$	1,211,000		$	882,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,531			741,531
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022 ^(a)		329,244			329,244
Other senior notes due 2022 ^(b)		590			1,090
Total senior notes		2,877,349			2,877,849
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		4,137,329			3,808,829
Unamortized premium		6,027			7,241
Unamortized debt issuance costs		(34,550	)		(42,553	)
Total debt net of debt issuance costs	$	4,108,806		$	3,773,517

Summary of Senior Notes Principal Subsequent to Debt Exchange

		Principal Amount
5.00% senior notes due 2023	$	741,531
5.00% senior notes due 2022	$	580,032
5.75% senior notes due 2021	$	475,952

Summary of Debt Exchange Offer to Exchange Validly Tendered and Accepted Range Senior Subordinated Notes

On September 16, 2016, we also completed our debt exchange offer to exchange all validly tendered and accepted Range senior subordinated notes as detailed below (in thousands):


Existing Note	New Note	Principal Amount of Notes Validly Tendered ⁽¹⁾	Approximate Percentage Validly Tendered
5.00% senior subordinated notes due 2023	5.00% senior notes due 2023	$742,291	99.0%

5.00% senior subordinated notes due 2022	5.00% senior notes due 2022	$580,946	96.8%

5.75% senior subordinated notes due 2021	5.75% senior notes due 2021	$477,786	95.6%
⁽¹⁾Prior to exchange premium

Schedule for Long-Term Debt Outstanding

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2017 (in thousands):

	Year Ended December 31,
2018	$	—
2019		1,211,000
2020		—
2021		498,166
2022		928,920
Thereafter		1,499,243
	$	4,137,329

Asset Retirement Obligation Disclosure [Abstract]

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation

The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2017 and 2016 (in thousands):


	2017			2016
Beginning of period	$	257,943		$	264,137
Liabilities incurred		7,724			2,694
Acquisitions		—			21,900
Liabilities settled		(7,965	)		(11,511	)
Disposition of wells		(8,078	)		(10,540	)
Accretion expense		14,711			18,021
Change in estimate		12,520			(26,758	)
End of period		276,855			257,943
Less current portion		(6,327	)		(7,271	)
Long-term asset retirement obligations	$	270,528		$	250,672

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Capital Stock

The following is a schedule of changes in the number of common shares outstanding since the beginning of 2015:


	Year Ended December 31,
	2017		2016			2015
Beginning balance		247,144,356		169,316,460			168,628,177
MRD Merger		—		77,042,749			—
Stock options/SARs exercised		—		—			77,002
Restricted stock grants		539,096		490,609			335,103
Restricted stock units vested		344,937		266,541			252,507
Performance stock units issued		85,461		—			—
Shares retired		—		(739	)		—
Treasury shares		15,580		28,736			23,671
Ending balance		248,129,430		247,144,356			169,316,460

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Volumes Hedged and Average Hedge Prices

The following table sets forth the derivative volumes by year as of December 31, 2017, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2018	Swaps	794,822 Mmbtu/day	$ 3.13
2019	Swaps	12,329 Mmbtu/day	$ 3.01
January − March 2018	Collars	60,000 Mmbtu/day	$ 3.40-$ 3.76
April – December 2018	Swaptions	307,500 Mmbtu/day	$ 2.98 ⁽¹⁾
2019	Swaptions	85,000 Mmbtu/day	$ 2.97 ⁽¹⁾

Crude Oil
2018	Swaps	8,995 bbls/day	$ 53.30
2019	Swaps	4,746 bbls/day	$ 52.81

NGLs (C2-Ethane)
2018	Swaps	250 bbls/day	$ 0.29/gallon

NGLs (C3-Propane)
2018	Swaps	10,362 bbls/day	$ 0.68/gallon
2018	Collars	2,000 bbls/day	$ 0.90-$ 1.05/gallon

NGLs (NC4-Normal Butane)
2018	Swaps	4,621 bbls/day	$ 0.81/gallon

NGLs (C5-Natural Gasoline)
2018	Swaps	4,713 bbls/day	$ 1.19/gallon
2019	Swaps	1,000 bbls/day	$ 1.24/gallon

Combined Fair Value of Derivatives, by Consolidated Balance Sheets

		December 31, 2017
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	87,794	$	(4,106	)	$	83,688
	–swaptions		18,817		(8,103	)		10,714
	–basis swaps		1,815		(6,673	)		(4,858	)
	–collars		3,039		(500	)		2,539
Crude oil	–swaps		2		(7,928	)		(7,926	)
NGLs	–C2 ethane swaps		57		—			57
	–C3 propane swaps		—		(12,556	)		(12,556	)
	–C3 propane collars		85		(85	)		—
	–C3 propane spread swaps		12,762		(12,762	)		—
	–NC4 butane swaps		—		(6,051	)		(6,051	)
	–C5 natural gasoline swaps		—		(6,727	)		(6,727	)
Freight	–swaps		276		(276	)		—
		$	124,647	$	(65,767	)	$	58,880

		December 31, 2017
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(216	)	$	4,106	$	3,890
	–swaptions		(12,283	)		8,103		(4,180	)
	–basis swaps		(9,580	)		6,673		(2,907	)
	–collars		—			500		500
Crude oil	–swaps		(24,726	)		7,928		(16,798	)
NGLs	–C3 propane swaps		(34,325	)		12,556		(21,769	)
	–C3 propane collars		—			85		85
	–C3 propane spread swaps		(13,983	)		12,762		(1,221	)
	–NC4 butane swaps		(11,188	)		6,051		(5,137	)
	–C5 natural gasoline swaps		(13,488	)		6,727		(6,761	)
Freight	–swaps		—			276		276
		$	(119,789	)	$	65,767	$	(54,022	)

		December 31, 2016
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	13,213	$	(11,425	)	$	1,788
	–basis swaps		12,535		(9,437	)		3,098
	–collars		6,298		(6,298	)		—
	–puts		18,159		(15,429	)		2,730
Crude oil	–swaps		9,356		(3,489	)		5,867
NGLs	–C2 ethane swaps		53		(53	)		—
	–C3 propane spread swaps		17,396		(17,396	)		—
	–NC4 butane swaps		4		(4	)		—
Freight	–swaps		65		(65	)		—
		$	77,079	$	(63,596	)	$	13,483

		December 31, 2016
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(158,359	)	$	11,425	$	(146,934	)
	–basis swaps		(687	)		9,437		8,750
	–collars		(2,625	)		6,298		3,673
	–puts		—			15,429		15,429
	–calls		(1,041	)		—		(1,041	)
Crude oil	–swaps		(13,206	)		3,489		(9,717	)
NGLs	–C2 ethane swaps		(1,008	)		53		(955	)
	–C3 propane swaps		(32,437	)		—		(32,437	)
	–C3 propane spread swaps		(18,138	)		17,396		(742	)
	–NC4 butane swaps		(13,419	)		4		(13,415	)
	–C5 natural gasoline swaps		(12,176	)		—		(12,176	)
Freight	–swaps		—			65		65
		$	(253,096	)	$	63,596	$	(189,500	)

Effects of Derivatives on Consolidated Statements of Operations

The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands).

	Year Ended December 31,
	Derivative Fair Value Income (Loss)
	2017			2016			2015
Commodity Swaps	$	181,095		$	(265,466	)	$	398,020
Swaptions		6,534			—			—
Re-purchased swaps		—			—			851
Collars		18,132			(6,926	)		16,539
Basis swaps		(4,647	)		29,154			954
Puts		10,929			(18,201	)		—
Calls		987			(18	)		—
Freight swaps		320			66			—
Total	$	213,350		$	(261,391	)	$	416,364

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

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-Name Accounting Standards Codification
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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

		Fair Value Measurements at December 31, 2017 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2017
Trading securities held in the deferred compensation plans		$	67,117	$	—		$	—	$	67,117
Derivatives	–swaps		—		3,910			—		3,910
	–collars		—		3,039			85		3,124
	–basis swaps		—		(9,025	)		39		(8,986	)
	–freight swaps		—		276			—		276
	–swaptions		—		—			6,534		6,534

		Fair Value Measurements at December 31, 2016 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2016
Trading securities held in the deferred compensation plans		$	61,717	$	—		$	—	$	61,717
Derivatives	–swaps		—		(207,979	)		—		(207,979	)
	–collars		—		3,673			—		3,673
	–puts		—		18,159			—		18,159
	–calls		—		(1,041	)		—		(1,041	)
	–basis swaps		—		11,106			—		11,106
	–freight swaps		—		65			—		65

Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy

The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

		Year Ended December 31, 2017
Balance at the beginning of period	$	—
Total gains (losses):
Included in earnings		6,658
Settlements received		—
Transfers in and/or out of Level 3		—
Balance at end of period	$	6,658

Value of Assets Measured at Fair Value on Nonrecurring Basis

The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands):

	Year Ended December 31,
	2017				2016				2015
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	85,597	$	63,679	$	90,150	$	43,040	$	152,230	$	590,174

Carrying Amounts and Fair Values of Financial Instruments

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2017 and 2016 (in thousands):

	December 31, 2017						December 31, 2016
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	58,880		$	58,880		$	13,483		$	13,483
Marketable securities ^(a)		67,117			67,117			61,717			61,717
(Liabilities):
Commodity swaps, options and basis swaps		(54,022	)		(54,022	)		(189,500	)		(189,500	)
Bank credit facility ^(b)		(1,211,000	)		(1,211,000	)		(882,000	)		(882,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(493,872	)		(475,952	)		(496,180	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(578,727	)		(580,032	)		(577,132	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(339,200	)		(329,244	)		(343,648	)
Other senior notes due 2022 ^(b)		(590	)		(591	)		(1,090	)		(1,104	)
5.00% senior notes due 2023 ^(b)		(741,531	)		(735,614	)		(741,531	)		(735,043	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(733,755	)		(750,000	)		(724,688	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,192	)		(22,214	)		(22,325	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,741	)		(19,054	)		(18,387	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,614	)		(7,712	)		(7,645	)
Deferred compensation plan ^(c)		(114,414	)		(114,414	)		(139,580	)		(139,580	)

^(a)	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

^(c)	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Stock-based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2017

Allocation of Stock-Based Compensation by Functional Category

The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2017 (in thousands):

	2017 ⁽¹⁾		2016			2015
Direct operating expense	$	2,060		$	2,302		$	2,780
Brokered natural gas and marketing expense		1,437			1,725			2,132
Exploration expense		2,742			2,298			2,985
General and administrative expense		74,873			49,293			49,687
Termination costs		1,664			—			217
Total	$	82,776		$	55,618		$	57,801

⁽¹⁾

Includes $30.8 million accelerated vesting of equity grants.

Restricted Stock and Restricted Stock Units Outstanding

The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2017:

	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014		360,415		$	79.60		304,504		$	80.33
Granted		587,711			52.29		343,397			55.92
Vested		(480,253	)		65.21		(330,870	)		68.71
Forfeited		(31,109	)		64.73		(8,294	)		74.22
Outstanding at December 31, 2015		436,764			59.74		308,737			65.80
Granted		973,491			28.51		540,128			35.92
Vested		(525,617	)		43.83		(374,328	)		51.40
Forfeited		(118,667	)		42.60		(49,519	)		40.33
Outstanding at December 31, 2016		765,971			33.62		425,018			43.48
Granted		888,326			32.61		543,438			25.91
Vested		(698,563	)		34.82		(908,912	)		33.71
Forfeited		(122,676	)		32.91		(4,342	)		31.10
Outstanding at December 31, 2017		833,058		$	31.64		55,202		$	32.26

Schedule of Share Based Payment Award Performance Stock Awards Valuation Assumptions

The following assumptions were used to estimate the fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31, 2017
	2017			2016			2015
Risk-free interest rate		1.49	%		0.94	%		1.02	%
Expected annual volatility		44	%		49	%		33	%
Grant date fair value per unit	$	26.26		$	36.64		$	56.78

Summary of SARs Outstanding and Exercisable

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2017:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 70.00–$ 79.99		380,879		0.36	$	76.51		380,879	$	76.51
80.00–81.15		1,900		0.69		81.15		1,900		81.15
Total		382,779		0.36	$	76.54		382,779	$	76.54

Summary of Change in Benefit Obligations Recognized in Comprehensive Income on Pre-tax Basis and Amounts Recognized in Consolidated Balance Sheets

	December 31, 2017
Accumulated benefit obligation	$	1,769

Change in benefit obligations (recognized in comprehensive income – pretax)
Beginning balance at December 31, 2016	$	—
Prior service cost		1,769
Total other comprehensive income (loss) at December 31, 2017	$	1,769

Amounts recognized in the consolidated balance sheets:
Noncurrent liability-accrued benefit cost	$	1,769

Summary of Assumptions Used to Determine Benefit Obligation

The following summarizes the assumptions used to determine the benefit obligation at December 31, 2017.

	December 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate		3.3	%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate		7.00	%
Ultimate trend rate		5.00	%
Year ultimate trend rate reached		2028

Stock Option and SARs Activities

Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2014		1,966,549		$	59.80
Exercised		(427,598	)		45.67
Expired/forfeited		(27,974	)		63.10
Outstanding at December 31, 2015		1,510,977			63.73
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600			69.08
Expired/forfeited		(620,821	)		62.29
Outstanding at December 31, 2017		382,779		$	76.54

Performance-based PG-PSUs and RG-PSUs

Summary of Non-Vested Awards Activities

The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December 31, 2017:


	Number of Units		Weighted Average Grant Date Fair Value of Range Stock
Outstanding at December 31, 2016	—		—
Units granted ^(a)	122,921	$	25.53
Outstanding at December 30, 2017	122,921	$	25.53

Performance Based TSR - PSUs

Summary of Non-Vested Awards Activities

The following is a summary of our non-vested TSR – PSUs award activities:

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014		226,418		$	86.16
Granted ^(a)		276,204			56.78
Forfeited		(2,679	)		82.60
Outstanding at December 31, 2015		499,943			69.95
Granted ^(a)		413,959			36.64
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		871,299			55.29
Granted ^(a)		358,519			26.26
Vested and issued ^(b)		(85,461	)		86.23
Forfeited		(134,515	)		85.24
Outstanding at December 31, 2017		1,009,842		$	38.38

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(1,024	)	$	(102	)	$	100
Interest paid		179,431			159,875			168,826
Non-cash investing and financing activities included ^(a):
Asset retirement costs capitalized, net	$	20,245		$	(24,064	)	$	22,184
Increase (decrease) in accrued capital expenditures		71,739			61,419			(225,455	)

^(a)

For additional information on non-cash investing activities associated with the MRD Merger, see Note 3.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies Disclosure [Abstract]

Future Minimum Rental Commitments

	Operating Lease Obligations		Sublease Rental Receipts
2018	$	18,498	$	3,472
2019		17,803		3,472
2020		16,945		3,174
2021		14,249		2,578
2022		8,058		215
Thereafter		32,909		—
	$	108,462	$	12,911

Schedule of Future Minimum Transportation Fees Due

	Transportation, Gathering and Processing Contracts ^(a)
2018	$	805,161
2019		825,231
2020		767,090
2021		733,133
2022		691,968
Thereafter		4,689,133
	$	8,511,716

Future Delivery Commitments

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2018		382,534	71,000
2019		364,356	55,932
2020		252,878	48,625
2021		116,189	48,000
2022		68,712	43,000
2023		—	35,000
2024—2028		—	35,000
2029—2031		—	20,000

Office Closing and Exit Costs (Tables)

12 Months Ended

Dec. 31, 2017

Restructuring And Related Activities [Abstract]

Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet

The following table details the accrued liability as of December 31, 2017 and December 31, 2016 (in thousands):

		2017			2016
Beginning balance	$	2,460		$	11,630
Accrued severance costs		2,176			(822	)
Accrued building rent		(70	)		303
Payments		(2,711	)		(8,651	)
Ending balance	$	1,855		$	2,460

Summary of Termination Costs

The following summarizes our termination costs for three years ended December 31, 2017, 2016 and 2015 (in thousands):

		2017			2016			2015
Severance costs	$	2,176		$	(822	)	$	11,706
Building lease		(70	)		303			3,147
Stock-based compensation		1,664			—			217
Total termination costs	$	3,770		$	(519	)	$	15,070

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

	2017
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	559,450		$	506,137		$	507,541		$	603,159		$	2,176,287
Derivative fair value income (loss)		165,557			111,195			(88,426	)		25,024			213,350
Brokered natural gas, marketing and other		51,648			55,779			63,117			50,849			221,393
Total revenue and other income		776,655			673,111			482,232			679,032			2,611,030
Costs and expenses:
Direct operating		28,023			31,420			36,888			37,921			134,252
Transportation, gathering, processing and compression		177,648			191,590			191,645			200,300			761,183
Production and ad valorem taxes		9,163			9,969			11,993			11,757			42,882
Brokered natural gas and marketing		53,550			55,857			59,773			51,131			220,311
Exploration		8,504			14,498			22,767			7,893			53,662
Abandonment and impairment of unproved properties		4,420			5,193			42,568			217,544			269,725
General and administrative		47,496			52,322			53,035			80,553			233,406
Termination costs		4,192			(96	)		(47	)		(279	)		3,770
Deferred compensation plan		(13,169	)		(14,466	)		(9,203	)		(14,077	)		(50,915	)
Interest		47,101			47,926			49,179			51,473			195,679
Depletion, depreciation and amortization		149,821			152,504			159,749			162,918			624,992
Impairment of proved properties and other		—			—			63,679			—			63,679
(Gain) loss on sale of assets		(22,600	)		(807	)		(102	)		(207	)		(23,716	)
Total costs and expenses		494,149			545,910			681,924			806,927			2,528,910

Income (loss) before income taxes		282,506			127,201			(199,692	)		(127,895	)		82,120
Income tax expense (benefit):
Current		—			—			—			17			17
Deferred		112,395			57,651			(71,992	)		(349,097	)		(251,043	)
		112,395			57,651			(71,992	)		(349,080	)		(251,026	)
Net income (loss)	$	170,111		$	69,550		$	(127,700	)	$	221,185		$	333,146
Net income (loss) per common share:
Basic	$	0.69		$	0.28		$	(0.52	)	$	0.89		$	1.34
Diluted	$	0.69		$	0.28		$	(0.52	)	$	0.89		$	1.34

	2016
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	209,487		$	224,606		$	304,477		$	458,645		$	1,197,215
Derivative fair value income (loss)		86,908			(162,798	)		64,556			(250,057	)		(261,391	)
Brokered natural gas, marketing and other		35,018			39,989			44,174			44,934			164,115
Total revenue and other income		331,413			101,797			413,207			253,522			1,099,939
Costs and expenses:
Direct operating		24,054			20,671			22,387			30,276			97,388
Transportation, gathering, processing and compression		125,263			136,844			138,764			164,338			565,209
Production and ad valorem taxes		5,887			6,049			6,717			6,790			25,443
Brokered natural gas and marketing		36,558			40,925			44,622			46,471			168,576
Exploration		4,913			6,785			6,943			13,684			32,325
Abandonment and impairment of unproved properties		10,628			7,059			6,082			6,307			30,076
General and administrative		40,657			46,064			41,024			57,027			184,772
MRD Merger expenses		—			2,621			33,791			813			37,225
Termination costs		162			5			136			(822	)		(519	)
Deferred compensation plan		16,056			25,746			(11,636	)		(11,013	)		19,153
Interest		37,739			37,758			45,967			46,749			168,213
Depletion, depreciation and amortization		120,561			122,390			131,489			149,662			524,102
Impairment of proved properties and other		43,040			—			—			—			43,040
Loss (gain) on sale of assets		1,643			3,304			2,597			(470	)		7,074
Total costs and expenses		467,161			456,221			468,883			509,812			1,902,077

Loss before income taxes		(135,748	)		(354,424	)		(55,676	)		(256,290	)		(802,138	)
Income tax expense (benefit):
Current		—			—			—			98			98
Deferred		(41,976	)		(129,488	)		(13,705	)		(95,679	)		(280,848	)
		(41,976	)		(129,488	)		(13,705	)		(95,581	)		(280,750	)
Net loss	$	(93,772	)	$	(224,936	)	$	(41,971	)	$	(160,709	)	$	(521,388	)
Net loss per common share:
Basic	$	(0.56	)	$	(1.35	)	$	(0.23	)	$	(0.66	)	$	(2.75	)
Diluted	$	(0.56	)	$	(1.35	)	$	(0.23	)	$	(0.66	)	$	(2.75	)

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

12 Months Ended

Dec. 31, 2017

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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

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.

Proved Developed and Undeveloped Reserves


	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.

Changes in Proved Undeveloped Reserves

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

Standardized Measure of Discounted Future Net Cash Flows

	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.

Changes in Discounted Future Net Cash Flows

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

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

Summary Of Significant Accounting Policies [Line Items]

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (losses)	$ (5,700,000)	$ (2,800,000)	$ (2,700,000)
Allowance for doubtful accounts on accounts receivable	7,111,000	5,559,000
Bad debt expense	1,550,000	800,000	$ 2,300,000
Inventory and other	21,346,000	26,573,000
Goodwill	1,641,197,000	1,654,292,000
Materials and supplies inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory and other	12,100,000	9,400,000
Commodity inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory and other	$ 508,000	$ 8,300,000

Summary of Significant Accounting Policies - Additional Information 1 (Detail) - USD ($)

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net book value of unproved properties

^[1]

$ 2,644,000,000

$ 2,923,803,000

$ 2,644,000,000

$ 2,923,803,000

$ 949,155,000

Abandonment and impairment of unproved properties

217,544,000

$ 42,568,000

$ 5,193,000

$ 4,420,000

6,307,000

$ 6,082,000

$ 7,059,000

$ 10,628,000

269,725,000

30,076,000

47,619,000

Depreciation expense

7,700,000

8,400,000

11,900,000

Marketable securities held in deferred compensation plans

67,100,000

61,700,000

67,100,000

61,700,000

Surface acreage

$ 9,600,000

$ 10,600,000

9,600,000

10,600,000

Natural Gas and Oil Properties | Northwest Pennsylvania

Summary Of Significant Accounting Policies [Line Items]

Fair Value

$ 0

Adjustments of the asset retirement liability additional expense

$ 158,000

$ 1,900,000

Other property and equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

3 years

Other property and equipment | Maximum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

10 years

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Summary of Significant Accounting Policies - Additional Information 2 (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) Customer Counterparty	Dec. 31, 2016 USD ($) Customer	Dec. 31, 2015 Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts on accounts receivable	$ 7,111	$ 5,559
Number of customers accounted more than 10% of total oil and gas revenues \| Customer	1	1	1
Net derivative asset	$ 28,200
Number of counterparties \| Counterparty	5
Number of financial institutions included in counter parties \| Counterparty	19
Accounting Standards Update 2016-09
Summary Of Significant Accounting Policies [Line Items]
Recognition of an excess tax deficiency in provision for income taxes rather than paid-in capital		$ 2,100
Cumulative-effect adjustments to retained earnings (deficit) and reduced deferred tax liability		$ 101,100

Summary of Significant Accounting Policies - Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard in Statements of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncement Early Adoption [Line Items]
Income tax benefit	$ (349,080)	$ (71,992)	$ 57,651	$ 112,395	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	$ (251,026)	$ (280,750)	$ (338,677)
Net loss	$ 221,185	$ (127,700)	$ 69,550	$ 170,111	$ (160,709)	$ (41,971)	$ (224,936)	$ (93,772)	$ 333,146	$ (521,388)	$ (713,685)
Basic earnings per share	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ 1.34	$ (2.75)	$ (4.29)
Diluted earnings per share	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ 1.34	$ (2.75)	$ (4.29)
Accounting Standards Update 2016-09
New Accounting Pronouncement Early Adoption [Line Items]
Income tax benefit								$ (41,976)
Net loss								$ (93,772)
Basic earnings per share								$ (0.56)
Diluted earnings per share								$ (0.56)
Accounting Standards Update 2016-09 \| As Reported
New Accounting Pronouncement Early Adoption [Line Items]
Income tax benefit								$ (44,038)
Net loss								$ (91,710)
Basic earnings per share								$ (0.55)
Diluted earnings per share								$ (0.55)

Summary of Significant Accounting Policies - Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard in Statements of Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2016	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
New Accounting Pronouncement Early Adoption [Line Items]
Net cash provided from operating activities				$ 816,254	$ 387,068	$ 691,402
Net cash (used in) provided from financing activities				$ 322,937	$ (78,390)	(472,607)
Accounting Standards Update 2016-09
New Accounting Pronouncement Early Adoption [Line Items]
Net cash provided from operating activities	$ 90,785	$ 173,201	$ 205,837			691,402	$ 974,353	$ 757,373
Net cash (used in) provided from financing activities	(75,834)	(99,008)	(39,029)			(472,607)	271,203	226,159
As Reported \| Accounting Standards Update 2016-09
New Accounting Pronouncement Early Adoption [Line Items]
Net cash provided from operating activities	87,424	169,604	202,037			683,700	954,135	743,538
Net cash (used in) provided from financing activities	$ (72,473)	$ (95,411)	$ (35,229)			$ (464,905)	$ 291,421	$ 239,994

Dispositions and Acquisitions - Dispositions - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended								9 Months Ended	12 Months Ended
	Feb. 28, 2015	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 30, 2015
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets		$ 207,000	$ 102,000	$ 807,000	$ 22,600,000	$ 470,000	$ (2,597,000)	$ (3,304,000)	$ (1,643,000)		$ 23,716,000	$ (7,074,000)	$ (406,856,000)
Texas Panhandle Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets		(989,000)
Proceeds from sale of oil and gas properties		$ 40,400,000
Western Oklahoma Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets										$ (5,300,000)	23,800,000
Proceeds from sale of oil and gas properties										$ 78,600,000	30,800,000
Miscellaneous Proved, Unproved Properties and Surface Acreage
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets											870,000	302,000	943,000
Proceeds from sale of oil and gas properties											$ 1,300,000	3,700,000	4,400,000
Northeast Pennsylvania Non-operated Interest
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets									(2,100,000)
Proceeds from sale of oil and gas properties									$ 111,500,000
Mississippi and South Texas properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties												$ 1,200,000
Virginia And West Virginia Property
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets													(407,700,000)
Cash proceeds from sale of assets													$ 876,000,000
Net operating income prior to disposition														$ 52,300,000
West Texas Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets	$ (101,000)
Proceeds from sale of oil and gas properties	$ 10,500,000

Dispositions and Acquisitions - Acquisitions - Additional Information (Detail) $ in Thousands		3 Months Ended				4 Months Ended	9 Months Ended	12 Months Ended
	Sep. 16, 2016 USD ($) shares	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Merger-related expenses		$ 813	$ 33,791	$ 2,621	$ 0		$ 37,200	$ 0	$ 37,225	$ 0
Pro Forma Adjusted for Merger Expenses Incurred
Business Acquisition [Line Items]
Merger-related expenses									37,200
MRD
Business Acquisition [Line Items]
Business merger date								Sep. 16, 2016
Common stock issued in connection with exchange of outstanding shares \| shares	77,042,749
Exchange ratio of common shares for acquired company	0.375
Fair value of outstanding debt	$ 1,204,449
Revenues						$ 146,600		$ 477,400
Net operating income						$ 94,900		$ 278,800
MRD \| Pro Forma Adjustment
Business Acquisition [Line Items]
Merger-related expenses									$ 7,100

Dispositions and Acquisitions - Summary of Final Allocation of Total Purchase Price (Details) - USD ($)
$ / shares in Units, $ in Thousands

Sep. 16, 2016

Dec. 31, 2017

Dec. 31, 2016

Natural gas and oil properties:

Shares of Range common stock issued to Memorial stockholders

$ 1,641,197

$ 1,654,292

MRD

Purchase price:

77,042,749

Range common stock price per share at September 15, 2016 (close)

$ 39.37

Total purchase price

$ 3,033,173

Plus fair value of liabilities assumed by Range:

Accounts payable

55,624

Other current liabilities

108,367

Long-term debt

1,204,449

Deferred taxes

547,706

Other long-term liabilities

77,223

Total purchase price plus liabilities assumed

5,026,542

Fair value of Memorial assets:

Cash and equivalents

7,180

Other current assets

99,969

Derivative instruments

152,994

Natural gas and oil properties:

Proved property

1,122,311

Unproved property

1,999,187

Other property and equipment

3,579

Earnings Per Share Reconciliation [Abstract]

^[1]

1,641,197

Other

125

Total asset value

$ 5,026,542

[1]	Goodwill will not be deductible for income tax purposes.

Dispositions and Acquisitions - Summary of Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition Pro Forma Information [Abstract]
Revenues	$ 1,334,290	$ 2,253,368
Net loss	$ (591,121)	$ (556,164)
Loss per share:
Basic	$ (2.42)	$ (2.28)
Diluted	$ (2.42)	$ (2.28)

Goodwill - Additional Information (Detail) - USD ($)	12 Months Ended
Goodwill - Additional Information (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	$ 1,641,197,000	$ 1,654,292,000
Impairment charge	0
Fair value exceeded book value, amount	1,400,000,000
Fair value exceeded book value impact after effect of new tax law, amount	$ 2,400,000,000
Fair value exceeded book value, percentage	24.00%
Fair value exceeded book value impact after effect of new tax law, percentage	42.00%

Income Taxes - Additional Information (Detail) - USD ($)			3 Months Ended								12 Months Ended
	Dec. 22, 2017	Oct. 18, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Income tax benefit			$ (349,080,000)	$ (71,992,000)	$ 57,651,000	$ 112,395,000	$ (95,581,000)	$ (13,705,000)	$ (129,488,000)	$ (41,976,000)		$ (251,026,000)	$ (280,750,000)	$ (338,677,000)
Corporate tax rate												35.00%	35.00%	35.00%
Deferred tax liabilities			693,356,000				$ 943,343,000					$ 693,356,000	$ 943,343,000
Deductible limit			1,000,000									1,000,000
Accrued interest or penalties related to tax amounts			0									$ 0
Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire												Dec. 31, 2018
Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire												Dec. 31, 2035
Deferred compensation plan
Income Taxes [Line Items]
Valuation allowances			1,900,000									$ 1,900,000
Amendment on Internal Revenue Code of 1986
Income Taxes [Line Items]
Corporate tax rate												35.00%
One-time tax benefit related to tax law changes	$ 334,000,000
Amendment on Internal Revenue Code of 1986 \| Scenario, Forecast
Income Taxes [Line Items]
Corporate tax rate											21.00%
Oklahoma, Texas and West Virginia
Income Taxes [Line Items]
State valuation allowance			36,300,000									$ 36,300,000
Pennsylvania
Income Taxes [Line Items]
State valuation allowance			57,500,000									$ 57,500,000
Minimum net operating loss deduction amount		$ 3,000,000
Percentage of taxable income		30.00%
Net operating loss deduction, description												The Supreme Court ruled that the net operating loss deduction limitation violated the Uniformity Clause of the Pennsylvania Constitution and struck the $3.0 million flat cap limitation but not the percentage of taxable income limitation.
Net operating loss carryforwards			872,600,000									$ 872,600,000
Pennsylvania \| Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire												Dec. 31, 2025
Pennsylvania \| Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire												Dec. 31, 2036
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards			$ 1,500,000,000									$ 1,500,000,000

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Federal statutory tax rate	35.00%	35.00%	35.00%
Federal rate change	(406.70%)	0.00%	0.00%
State	(0.70%)	3.00%	4.30%
State rate and law change	(1.30%)	1.00%	(0.20%)
Non-deductible executive compensation	0.70%	(0.20%)	(0.10%)
Valuation allowances	36.80%	(2.50%)	(6.80%)
Equity compensation	30.20%	(0.70%)	0.00%
Other	0.30%	0.00%	0.00%
Consolidated effective tax rate	(305.70%)	35.00%	32.20%
MRD
Income Taxes [Line Items]
Non-deductible MRD transaction costs	0.00%	(0.60%)	0.00%

Income Taxes - Income Tax (Benefit) Expense Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current									$ 0	$ 0	$ 0
U.S. state and local, Current									17	98	29
Total, Current	$ 17	$ 0	$ 0	$ 0	$ 98	$ 0	$ 0	$ 0	17	98	29
U.S. federal, Deferred									(302,507)	(266,105)	(328,257)
U.S. state and local, Deferred									51,464	(14,743)	(10,449)
Total, Deferred	(349,097)	(71,992)	57,651	112,395	(95,679)	(13,705)	(129,488)	(41,976)	(251,043)	(280,848)	(338,706)
U.S. federal, Total									(302,507)	(266,105)	(328,257)
U.S. state and local, Total									51,481	(14,645)	(10,420)
Total (benefit) expense for income taxes	$ (349,080)	$ (71,992)	$ 57,651	$ 112,395	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	$ (251,026)	$ (280,750)	$ (338,677)

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Net operating loss carryforward	$ 413,672	$ 478,203
Deferred compensation	24,704	50,808
Equity compensation	5,269	29,528
AMT credits and other credits	7,264	13,644
Asset retirement obligation	69,398	99,000
Cumulative mark-to-market loss	0	73,404
Other	18,806	39,922
Valuation allowances:
Total deferred tax assets	413,979	677,335
Deferred tax liabilities:
Depreciation, depletion and investments	(1,105,494)	(1,619,922)
Cumulative mark-to-market gain	(1,841)	0
Other	0	(756)
Total deferred tax liabilities	(1,107,335)	(1,620,678)
Net deferred tax liability	(693,356)	(943,343)
Federal
Valuation allowances:
Valuation allowances	(31,308)	(48,750)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (93,826)	$ (58,424)

Income Taxes - Changes in Deferred Tax Asset Valuation Allowances (Detail) - Valuation Allowance of Deferred Tax Assets - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Balance at the beginning of the year	$ (107,174)	$ (87,623)	$ (16,599)
Charged to provision for income taxes:
Other state valuation allowances	(23,790)	500	(1,050)
Other federal valuation allowances	(247)	(477)	(511)
Rabbi trust valuation allowance	2,304	(1,066)	3,494
Other	0	(34)	0
Balance at the end of the year	(125,134)	(107,174)	(87,623)
State
Charged to provision for income taxes:
Net operating loss carryforwards	(11,612)	(17,374)	(30,457)
Federal
Charged to provision for income taxes:
Net operating loss carryforwards	$ 15,385	$ (1,100)	$ (42,500)

Net Income (Loss) Per Common Share - Computations of Basic and Diluted Income (Loss) Per Common Share (Detail) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net income (loss)

$ 221,185

$ (127,700)

$ 69,550

$ 170,111

$ (160,709)

$ (41,971)

$ (224,936)

$ (93,772)

$ 333,146

$ (521,388)

$ (713,685)

Participating basic earnings

^[1]

(3,751)

(223)

(450)

Basic net income (loss) attributed to common stockholders

329,395

(521,611)

(714,135)

Reallocation of participating earnings

^[1]

Diluted net income (loss) attributed to common stockholders

$ 329,400

$ (521,611)

$ (714,135)

Net income (loss) per common share:

Basic

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ 1.34

$ (2.75)

$ (4.29)

Diluted

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ 1.34

$ (2.75)

$ (4.29)

[1]

Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Detail) - shares
shares in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Denominator:

Weighted average common shares outstanding – basic

^[1]

245,091

189,868

166,389

Effect of dilutive securities:

Director and employee restricted stock and performance-based equity awards

367

Weighted average common shares outstanding – diluted

245,458

189,868

166,389

[1]	Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016.

Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Parenthetical) (Detail)	Sep. 16, 2016 shares
MRD
Earnings Per Share Basic [Line Items]
Common stock issued in connection with exchange of outstanding shares	77,042,749

Net Income (Loss) Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	2,800,000	2,800,000	2,800,000
Equity Grants
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	702,000

Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) Project	Dec. 31, 2016 USD ($) Project	Dec. 31, 2015 USD ($) Project
Extractive Industries [Abstract]
Balance at beginning of period	$ 7,412	$ 4,161	$ 2,996
Additions to capitalized exploratory well costs pending the determination of proved reserves	1,388	9,128	1,165
Reclassifications to wells, facilities and equipment based on determination of proved reserves	0	(5,877)	0
Capitalized exploratory well costs charged to expense	(8,800)	0	0
Balance at end of period	0	7,412	4,161
Less exploratory well costs that have been capitalized for a period of one year or less	0	(7,412)	(1,165)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 0	$ 0	$ 2,996
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| Project	0	0	1

Indebtedness - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

Indebtedness - Debt Outstanding (Detail) - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

May 31, 2015

$ 2,877,349

$ 2,877,849

Unamortized debt issuance costs

48,980

Total debt

4,137,329

3,808,829

Unamortized premium

6,027

7,241

(34,550)

(42,553)

Total debt net of debt issuance costs

4,108,806

3,773,517

3.0% Bank Debt | Notes Payable to Banks

4.875% Senior Notes Due 2025

Bank debt (3.0%)

1,211,000

882,000

5.00% Senior Notes Due 2023

750,000

$ 750,000

5.00% Senior Notes Due 2022

741,531

5.75% Senior Notes Due 2021

580,032

5.875% Senior Notes Due 2022

475,952

Other Senior Notes Due 2022

^[1]

329,244

5.00% Senior Subordinated Notes Due 2023

^[2]

590

1,090

5.00% Senior Subordinated Notes Due 2022

7,712

5.75% Senior Subordinated Notes Due 2021

19,054

$ 22,214

[1]	Represents senior notes assumed in the MRD Merger that were not purchased for cash but were exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below.
[2]	Represents the remaining Memorial 5.875% senior notes assumed in the MRD Merger that were not purchased for cash or were not exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below.

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 16, 2016	May 31, 2015
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%		4.875%			4.875%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%	5.75%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%		5.75%		5.75%
Other Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes			5.875%
Notes Payable to Banks \| 3.0% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage			3.00%

Indebtedness - Bank Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017 USD ($) CommercialBank	Dec. 31, 2016 USD ($)	Dec. 31, 2015	Mar. 21, 2017 USD ($)
Debt Instrument [Line Items]
Bank debt	$ 1,208,467,000	$ 876,428,000
Bank Credit Facility
Debt Instrument [Line Items]
Bank Credit facility, maximum amount	4,000,000,000
Bank Credit facility, borrowing base	3,000,000,000			$ 3,000,000,000
Bank commitments	$ 2,000,000,000			$ 2,000,000,000
Percentage holding of commercial banks, Maximum	5.80%
Number of commercial banks included in current bank group \| CommercialBank	29
Maturity date of loan	Oct. 16, 2019
Bank debt	$ 1,200,000,000
Undrawn letters of credit	281,400,000
Borrowing capacity available under the commitment amount	$ 507,600,000
Weighted average interest rate on the bank credit facility	2.70%	2.20%	1.70%
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.50%
Bank Credit Facility \| LIBOR Rate
Debt Instrument [Line Items]
Interest rate margin	1.50%
Bank Credit Facility \| Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Minimum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.15%
Bank Credit Facility \| Minimum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	0.25%
Bank Credit Facility \| Minimum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.125%
Bank Credit Facility \| Minimum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility \| Minimum \| LIBOR Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.125%
Bank Credit Facility \| Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Bank Credit Facility \| Maximum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Maximum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility \| Maximum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.75%
Bank Credit Facility \| Maximum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	2.25%
Bank Credit Facility \| Maximum \| LIBOR Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.75%

Indebtedness - Senior Notes - Additional Information (Detail) - USD ($)
$ in Thousands

1 Months Ended

12 Months Ended

Sep. 30, 2016

May 31, 2015

Dec. 31, 2017

Oct. 05, 2017

Dec. 31, 2016

Sep. 16, 2016

$ 2,877,349

$ 2,877,849

Senior Notes

Maximum redemption price of notes as percentage of principal amount

101.00%

5.875% Senior Notes Due 2022

5.875%

5.875% Senior Notes Due 2022 | Senior Notes Exchange Offer | Unsecured Debt

^[1]

$ 329,244

$ 329,200

Maximum redemption price of notes as percentage of principal amount

5.875%

100.00%

5.00% Senior Notes Due 2023

$ 741,531

5.00%

5.00% Senior Notes Due 2022

$ 741,531

$ 580,032

5.00%

5.75% Senior Notes Due 2021

$ 580,032

$ 475,952

5.75%

4.875% Senior Notes Due 2025

$ 475,952

Maximum redemption price of notes as percentage of principal amount

4.875%

101.00%

Net proceeds after underwriting discounts and commissions

$ 750,000

737,400

Underwriting discounts and commissions

$ 12,600

[1]	Represents senior notes assumed in the MRD Merger that were not purchased for cash but were exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below.

Indebtedness - Summary of Debt Exchange Offer to Exchange Senior Subordinated Notes (Detail) $ in Thousands	1 Months Ended
	Sep. 30, 2016 USD ($)
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	$ 741,531
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	580,032
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes	$ 475,952

Indebtedness - Summary of Debt Exchange Offer to Exchange Senior Subordinated Notes (Parenthetical) (Detail)	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 16, 2016
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%	5.75%

Indebtedness - Senior Notes Exchange and Cash Tender Offer - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
	Sep. 16, 2016	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 30, 2016
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes		5.875%	5.875%	5.875%
Senior Notes Cash Tender Offer \| 5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Early cash tender premium paid	$ 3.3
Senior Notes Cash Tender Offer \| 5.875% Senior Notes Due 2022 \| MRD
Debt Instrument [Line Items]
Percentage of outstanding notes acquired	44.90%
Principal amount purchased	$ 269.7
Senior Notes
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount		101.00%
Senior Notes \| Senior Notes Exchange Offer \| MRD
Debt Instrument [Line Items]
Percentage of outstanding notes exchanged	54.90%
Unsecured Debt \| Senior Notes Exchange Offer \| 5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%				5.875%
Maturity date of loan		Jul. 01, 2022
Maximum redemption price of notes as percentage of principal amount		100.00%
Deferred financing costs	$ 6.3
Early cash tender premium paid	$ 4.1

Indebtedness - Summary of Debt Exchange Offer to Exchange All Validly Tendered and Accepted Range Senior Subordinated Notes (Detail)
$ in Thousands

Sep. 16, 2016

USD ($)

5.00% Senior Subordinated Notes Due 2023

Principal Amount of Notes Validly Tendered

$ 742,291

^[1]

Approximate Percentage Validly Tendered

99.00%

5.00% Senior Subordinated Notes Due 2022

Principal Amount of Notes Validly Tendered

$ 580,946

^[1]

Approximate Percentage Validly Tendered

96.80%

5.75% Senior Subordinated Notes Due 2021

Principal Amount of Notes Validly Tendered

$ 477,786

^[1]

Approximate Percentage Validly Tendered

95.60%

[1]	(1) Prior to exchange premium

Indebtedness - Summary of Debt Exchange Offer to Exchange All Validly Tendered and Accepted Range Senior Subordinated Notes (Parenthetical) (Detail)	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 16, 2016
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%		5.75%		5.75%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%	5.75%

Indebtedness - Senior Subordinated Notes Exchange- Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 16, 2016
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
Maturity date of loan		Mar. 15, 2023
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
Maturity date of loan		Aug. 15, 2022
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%	5.75%
Maturity date of loan		Jun. 01, 2021
Senior Notes
Debt Instrument [Line Items]
Additional interest expense on senior subordinated notes exchange	$ 6.6
Premium recorded in connection with debt exchange		$ 3.5
Percentage of premium received on face amount tendered in exchange of debt		95.00%
Maximum redemption price of notes as percentage of principal amount		101.00%

Indebtedness - Senior Subordinated Notes and Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jul. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Loss on early extinguishment of debt		$ 0	$ 0	$ 22,495
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount		101.00%
Senior Subordinated Notes \| 6.75% Senior Subordinated Notes Due 2020
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount	103.375%
Announced call for redemption amount of debt	$ 500,000
Interest rate on notes	6.75%
Debt instrument, redemption description		In July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In the year ended 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2017
Debt Instrument [Line Items]
Debt instrument, Covenant compliance	Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2017.
Maximum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	250.00%
Present value of proved reserves to total debt	150.00%
Minimum
Debt Instrument [Line Items]
Current ratio	100.00%

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) $ in Thousands	Dec. 31, 2016 USD ($)
Debt Disclosure [Abstract]
2018	$ 0
2019	1,211,000
2020	0
2021	498,166
2022	928,920
Thereafter	1,499,243
Total debt	$ 4,137,329

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Beginning of period	$ 257,943	$ 264,137
Liabilities incurred	7,724	2,694
Acquisitions	0	21,900
Liabilities settled	(7,965)	(11,511)
Disposition of wells	(8,078)	(10,540)
Accretion expense	14,711	18,021
Change in estimate	12,520	(26,758)
End of period	276,855	257,943
Less current portion	(6,327)	(7,271)
Long-term asset retirement obligations	$ 270,528	$ 250,672

Capital Stock - Additional Information (Detail) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class Of Stock Disclosures [Abstract]
Authorized capital stock	485,000,000				485,000,000								485,000,000	485,000,000
Common stock, shares authorized	475,000,000				475,000,000								475,000,000	475,000,000
Preferred stock, shares authorized	10,000,000				10,000,000								10,000,000	10,000,000
Common dividends declared per share	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.08	$ 0.08	$ 0.16

Capital Stock (Detail) - shares	12 Months Ended
Capital Stock (Detail) - shares	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class Of Stock [Line Items]
Beginning balance	247,144,356	169,316,460	168,628,177
Stock options/SARs exercised	0	0	77,002
Restricted stock grants	539,096	490,609	335,103
Shares retired	0	(739)	0
Treasury shares	15,580	28,736	23,671
Ending balance	248,129,430	247,144,356	169,316,460
MRD
Class Of Stock [Line Items]
MRD Merger	0	77,042,749	0
Restricted Stock
Class Of Stock [Line Items]
Restricted stock units vested	344,937	266,541	252,507
Performance Share
Class Of Stock [Line Items]
Performance stock units issued	85,461	0	0

Derivative Activities - Additional Information (Detail)	12 Months Ended
Derivative Activities - Additional Information (Detail)	Dec. 31, 2017 USD ($) t_per_M MMBTU Counterparty Institution bbl
Derivative [Line Items]
Number of financial institutions with whom we conduct derivative activities \| Institution	19
Number of secured lenders not in banking credit facility \| Counterparty	5
Derivatives Excluding Basis Swaps and Freight Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 13,600,000
Commodity \| Basis Swaps \| Natural Gas
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ (7,800,000)
Volume Hedged \| MMBTU	120,892,500
Commodity \| Basis Swaps \| Propane
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ (1,200,000)
Commodity \| Swaps \| Freight \| Level 2
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 276,000
Volume Hedged \| t_per_M	5,000
2018 Commodity Contract \| Basis Swaps \| Propane
Derivative [Line Items]
Volume Hedged \| bbl	1,362,000

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)

Dec. 31, 2017

MMBTU / d

bbl / d

$ / MMBTU

$ / bbl

$ / gal

2018 Commodity Contract | Swaps | Natural Gas

794,822

2018 Commodity Contract | Swaps | Crude Oil

3.13

Weighted Average Hedge Price | $ / bbl

8,995

53.30

2018 Commodity Contract | Swaps | NGLs (C2-Ethane)

250

2018 Commodity Contract | Swaps | NGLs (C3-Propane)

0.29

10,362

2018 Commodity Contract | Swaps | NGLs (NC4-Normal Butane)

0.68

4,621

2018 Commodity Contract | Swaps | NGLs (C5-Natural Gasoline)

0.81

4,713

2018 Commodity Contract | Collars | NGLs (C3-Propane)

1.19

Weighted Average Floor Price | $ / gal

2,000

0.90

Weighted Average Cap Price | $ / gal

1.05

2019 Commodity Contract | Swaps | Natural Gas

12,329

2019 Commodity Contract | Swaps | Crude Oil

3.01

Weighted Average Hedge Price | $ / bbl

4,746

52.81

2019 Commodity Contract | Swaps | NGLs (C5-Natural Gasoline)

1,000

2019 Commodity Contract | Swaptions | Natural Gas

1.24

85,000

January−March 2018 Commodity Contract | Collars | Natural Gas

2.97

^[1]

Weighted Average Floor Price | $ / MMBTU

60,000

3.40

Weighted Average Cap Price | $ / MMBTU

3.76

April-December 2018 Commodity Contract | Swaptions | Natural Gas

307,500

2.98

^[1]

[1]

Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volume. For April through December 2018, we have swaps in place for 147,500 Mmbtu per day on which the counterparty can elect to double the volume at a weighted average price of $2.89. We also have swaps in place for 160,000 Mmbtu per day on which the counterparty can elect to extend the contract through December 2019 at a weighted average price of $3.07. In 2019, if the counterparty elects to double the volume, we would have additional swaps covering 85,000 Mmbtu per day at a weighted average price of $2.97.

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Swaps - Natural Gas	Dec. 31, 2017 MMBTU / d $ / shares $ / MMBTU
April-December 2018 Commodity Contract \| Counterparty Can Elect to Double The Volume
Derivative [Line Items]
Volume Hedged	147,500
Weighted average price of hedge \| $ / shares	2.89
April-December 2018 Commodity Contract \| Counterparty Can Elect to Extend Contract
Derivative [Line Items]
Volume Hedged	160,000
Weighted average price of hedge \| $ / shares	3.07
2019 Commodity Contract
Derivative [Line Items]
Volume Hedged	12,329
Weighted average price of hedge \| $ / MMBTU	3.01
2019 Commodity Contract \| Counterparty Can Elect to Double The Volume
Derivative [Line Items]
Volume Hedged	85,000
Weighted average price of hedge \| $ / shares	2.97

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 124,647	$ 77,079
Gross Amounts Offset in the Balance Sheet	(65,767)	(63,596)
Net Amounts of Assets Presented in the Balance Sheet	58,880	13,483
Gross Amounts of Recognized (Liabilities)	(119,789)	(253,096)
Gross Amounts Offset in the Balance Sheet	65,767	63,596
Net Amounts of (Liabilities) Presented in the Balance Sheet	(54,022)	(189,500)
Commodity \| Swaps \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	87,794	13,213
Gross Amounts Offset in the Balance Sheet	(4,106)	(11,425)
Net Amounts of Assets Presented in the Balance Sheet	83,688	1,788
Gross Amounts of Recognized (Liabilities)	(216)	(158,359)
Gross Amounts Offset in the Balance Sheet	4,106	11,425
Net Amounts of (Liabilities) Presented in the Balance Sheet	3,890	(146,934)
Commodity \| Swaps \| Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	2	9,356
Gross Amounts Offset in the Balance Sheet	(7,928)	(3,489)
Net Amounts of Assets Presented in the Balance Sheet	(7,926)	5,867
Gross Amounts of Recognized (Liabilities)	(24,726)	(13,206)
Gross Amounts Offset in the Balance Sheet	7,928	3,489
Net Amounts of (Liabilities) Presented in the Balance Sheet	(16,798)	(9,717)
Commodity \| Swaps \| NGLs (C2-Ethane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	57	53
Gross Amounts Offset in the Balance Sheet	0	(53)
Net Amounts of Assets Presented in the Balance Sheet	57	0
Gross Amounts of Recognized (Liabilities)		(1,008)
Gross Amounts Offset in the Balance Sheet		53
Net Amounts of (Liabilities) Presented in the Balance Sheet		(955)
Commodity \| Swaps \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	0
Gross Amounts Offset in the Balance Sheet	(12,556)
Net Amounts of Assets Presented in the Balance Sheet	(12,556)
Gross Amounts of Recognized (Liabilities)	(34,325)	(32,437)
Gross Amounts Offset in the Balance Sheet	12,556	0
Net Amounts of (Liabilities) Presented in the Balance Sheet	(21,769)	(32,437)
Commodity \| Swaps \| NGLs (NC4-Normal Butane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	0	4
Gross Amounts Offset in the Balance Sheet	(6,051)	(4)
Net Amounts of Assets Presented in the Balance Sheet	(6,051)	0
Gross Amounts of Recognized (Liabilities)	(11,188)	(13,419)
Gross Amounts Offset in the Balance Sheet	6,051	4
Net Amounts of (Liabilities) Presented in the Balance Sheet	(5,137)	(13,415)
Commodity \| Swaps \| NGLs (C5-Natural Gasoline)
Derivative [Line Items]
Gross Amounts of Recognized Assets	0
Gross Amounts Offset in the Balance Sheet	(6,727)
Net Amounts of Assets Presented in the Balance Sheet	(6,727)
Gross Amounts of Recognized (Liabilities)	(13,488)	(12,176)
Gross Amounts Offset in the Balance Sheet	6,727	0
Net Amounts of (Liabilities) Presented in the Balance Sheet	(6,761)	(12,176)
Commodity \| Swaps \| Freight
Derivative [Line Items]
Gross Amounts of Recognized Assets	276	65
Gross Amounts Offset in the Balance Sheet	(276)	(65)
Net Amounts of Assets Presented in the Balance Sheet	0	0
Gross Amounts of Recognized (Liabilities)	0	0
Gross Amounts Offset in the Balance Sheet	276	65
Net Amounts of (Liabilities) Presented in the Balance Sheet	276	65
Commodity \| Swaptions \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	18,817
Gross Amounts Offset in the Balance Sheet	(8,103)
Net Amounts of Assets Presented in the Balance Sheet	10,714
Gross Amounts of Recognized (Liabilities)	(12,283)
Gross Amounts Offset in the Balance Sheet	8,103
Net Amounts of (Liabilities) Presented in the Balance Sheet	(4,180)
Commodity \| Basis Swaps \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,815	12,535
Gross Amounts Offset in the Balance Sheet	(6,673)	(9,437)
Net Amounts of Assets Presented in the Balance Sheet	(4,858)	3,098
Gross Amounts of Recognized (Liabilities)	(9,580)	(687)
Gross Amounts Offset in the Balance Sheet	6,673	9,437
Net Amounts of (Liabilities) Presented in the Balance Sheet	(2,907)	8,750
Commodity \| Collars \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	3,039	6,298
Gross Amounts Offset in the Balance Sheet	(500)	(6,298)
Net Amounts of Assets Presented in the Balance Sheet	2,539	0
Gross Amounts of Recognized (Liabilities)	0	(2,625)
Gross Amounts Offset in the Balance Sheet	500	6,298
Net Amounts of (Liabilities) Presented in the Balance Sheet	500	3,673
Commodity \| Collars \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	85
Gross Amounts Offset in the Balance Sheet	(85)
Net Amounts of Assets Presented in the Balance Sheet	0
Gross Amounts of Recognized (Liabilities)	0
Gross Amounts Offset in the Balance Sheet	85
Net Amounts of (Liabilities) Presented in the Balance Sheet	85
Commodity \| Spread Swaps \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,762	17,396
Gross Amounts Offset in the Balance Sheet	(12,762)	(17,396)
Net Amounts of Assets Presented in the Balance Sheet	0	0
Gross Amounts of Recognized (Liabilities)	(13,983)	(18,138)
Gross Amounts Offset in the Balance Sheet	12,762	17,396
Net Amounts of (Liabilities) Presented in the Balance Sheet	$ (1,221)	(742)
Commodity \| Puts \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets		18,159
Gross Amounts Offset in the Balance Sheet		(15,429)
Net Amounts of Assets Presented in the Balance Sheet		2,730
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		15,429
Net Amounts of (Liabilities) Presented in the Balance Sheet		15,429
Commodity \| Calls \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(1,041)
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of (Liabilities) Presented in the Balance Sheet		$ (1,041)

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 25,024	$ (88,426)	$ 111,195	$ 165,557	$ (250,057)	$ 64,556	$ (162,798)	$ 86,908	$ 213,350	$ (261,391)	$ 416,364
Swaptions
Derivative [Line Items]
Derivative Fair Value Income (Loss)									6,534	0	0
Re-purchased Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									0	0	851
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)									18,132	(6,926)	16,539
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									(4,647)	29,154	954
Puts
Derivative [Line Items]
Derivative Fair Value Income (Loss)									10,929	(18,201)	0
Calls
Derivative [Line Items]
Derivative Fair Value Income (Loss)									987	(18)	0
Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									181,095	(265,466)	398,020
Freight \| Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									$ 320	$ 66	$ 0

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 67,117	$ 61,717
Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	3,910	(207,979)
Swaps \| Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		65
Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	3,124	3,673
Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(8,986)	18,159
Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	276	(1,041)
Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	6,534	11,106
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	67,117	61,717
Fair Value, Inputs, Level 3 \| Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	85
Fair Value, Inputs, Level 3 \| Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	39
Fair Value, Inputs, Level 3 \| Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	6,534
Level 2 \| Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	3,910	(207,979)
Level 2 \| Swaps \| Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		65
Level 2 \| Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	3,039	3,673
Level 2 \| Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(9,025)	18,159
Level 2 \| Calls
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	$ 276	(1,041)
Level 2 \| Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		$ 11,106

Fair Value Measurements - Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy (Detail) - Fair Value, Inputs, Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at the beginning of period	$ 0
Total gains (losses) included in earnings	6,658
Balance at end of period	$ 6,658

Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends									$ 4,100,000	$ 972,000	$ 908,000
Mark-to-market gain (loss)									4,200,000	3,100,000	(5,900,000)
Impairment on natural gas and oil properties	$ 0	$ 63,679,000	$ 0	$ 0	$ 0	$ 0	$ 0	$ 43,040,000	63,679,000	43,040,000	590,174,000
Oklahoma and Texas Panhandle
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties									$ 63,700,000
Western Oklahoma
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties										$ 43,000,000
Northwest Pennsylvania
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											195,600,000
Northern Oklahoma
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											306,600,000
Texas Panhandle
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											86,900,000
Gulf Coast
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											$ 1,100,000

Fair Value Measurements - Value of Assets Measured at Fair Value on Nonrecurring Basis (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties	$ 0	$ 63,679	$ 0	$ 0	$ 0	$ 0	$ 0	$ 43,040	$ 63,679	$ 43,040	$ 590,174
Fair Value, Measurements, Nonrecurring \| Natural Gas and Oil Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value	$ 85,597				$ 90,150				85,597	90,150	152,230
Impairment of proved properties									$ 63,679	$ 43,040	$ 590,174

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

Carrying Value

Assets:

$ 58,880

$ 13,483

Marketable securities

^[1]

67,117

61,717

Deferred compensation plan

(54,022)

(189,500)

Bank credit facility

^[2]

(1,211,000)

(882,000)

^[3]

(114,414)

(139,580)

Carrying Value | 5.75% Senior Notes Due 2021

Carrying Value | 5.00% Senior Notes Due 2022

^[2]

(475,952)

Carrying Value | 5.875% Senior Notes Due 2022

^[2]

(580,032)

Carrying Value | 5.00% Senior Notes Due 2023

^[2]

(329,244)

Carrying Value | Other Senior Notes Due 2022

^[2]

(741,531)

Carrying Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(590)

(1,090)

Carrying Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(22,214)

Carrying Value | 4.875% Senior Notes Due 2025

^[2]

(7,712)

Carrying Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(750,000)

^[2]

(19,054)

Fair Value

Assets:

58,880

13,483

Marketable securities

^[1]

67,117

61,717

Deferred compensation plan

(54,022)

(189,500)

Bank credit facility

^[2]

(1,211,000)

(882,000)

^[3]

(114,414)

(139,580)

Fair Value | 5.75% Senior Notes Due 2021

Fair Value | 5.00% Senior Notes Due 2022

^[2]

(493,872)

(496,180)

Fair Value | 5.875% Senior Notes Due 2022

^[2]

(578,727)

(577,132)

Fair Value | 5.00% Senior Notes Due 2023

^[2]

(339,200)

(343,648)

Fair Value | Other Senior Notes Due 2022

^[2]

(735,614)

(735,043)

Fair Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(591)

(1,104)

Fair Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(22,192)

(22,325)

Fair Value | 4.875% Senior Notes Due 2025

^[2]

(7,614)

(7,645)

Fair Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(733,755)

(724,688)

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

^[2]

$ (18,741)

$ (18,387)

[1]	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.
[2]	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.
[3]	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail)	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 16, 2016	May 31, 2015
5.75% Senior Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%	5.75%
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
5.875% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%	5.00%
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	4.875%		4.875%			4.875%
5.75% Senior Subordinated Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%		5.75%		5.75%
5.00% Senior Subordinated Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%
5.00% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%		5.00%		5.00%

Stock-based Compensation Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Accelerated vesting of equity grants	$ 30,800								$ 30,800
Income tax benefit	$ (349,080)	$ (71,992)	$ 57,651	$ 112,395	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	(251,026)	$ (280,750)	$ (338,677)
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax benefit									$ 5,300	$ 5,700
2005 Equity Based Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares issued under the plans									5,600,000
1999 Stock Option Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted									0

Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

^[1]

Dec. 31, 2016

Dec. 31, 2015

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

$ 82,776

$ 55,618

$ 57,801

Direct Operating Expense

Brokered Natural Gas and Marketing Expense

2,060

2,302

2,780

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

1,437

1,725

2,132

Exploration Expense

General and Administrative Expense

^[2]

2,742

2,298

2,985

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]

74,873

49,293

49,687

Termination Costs

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

$ 1,664

$ 0

$ 217

[1]	Includes $30.8 million accelerated vesting of equity grants.
[2]	Includes cost incurred whether capitalized or expensed.

Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Accelerated vesting of equity grants	$ 30.8	$ 30.8

Stock-based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2017 Award shares	Dec. 31, 2016 shares	Dec. 31, 2015 shares	Dec. 31, 2014 shares
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	3
Performance Share \| Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share value each unit represents at grant date \| shares	1
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	2
Performance-based PG-PSUs and RG-PSUs \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Performance-based PG-PSUs and RG-PSUs \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	150.00%
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	1
Performance Based TSR - PSUs \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%	0.00%	0.00%
Performance Based TSR - PSUs \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	150.00%	150.00%	150.00%
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of stock option outstanding \| shares	382,779	1,003,600	1,510,977	1,966,549

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 82,776

^[1]

$ 55,618

$ 57,801

Proceeds from the sales of common stock held by the deferred compensation plan

$ 30,800

30,800

$ 4,482

$ 13,102

$ 8,298

Restricted Stock Equity Awards

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

888,326

973,491

587,711

3 years

$ 23,400

$ 22,800

$ 23,800

Granted, weighted average grant date fair value

24,400

$ 24,400

Weighted average period

1 year 8 months 12 days

$ 32.61

$ 28.51

$ 52.29

Restricted Stock Liability Awards

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

543,438

540,128

343,397

$ 30,400

$ 18,600

$ 20,800

Granted, weighted average grant date fair value

$ 1,700

Weighted average period

1 year 7 months 6 days

$ 25.91

$ 35.92

$ 55.92

Restricted Stock Liability Awards | Non Employee Director

$ 15,400

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Restricted Stock Liability Awards | Employees

90,000

59,000

48,000

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

453,000

481,000

295,000

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

3 years

[1]	Includes $30.8 million accelerated vesting of equity grants.

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	765,971	436,764	360,415
Granted	888,326	973,491	587,711
Vested	(698,563)	(525,617)	(480,253)
Forfeited	(122,676)	(118,667)	(31,109)
Outstanding, Ending Balance	833,058	765,971	436,764
Outstanding, Beginning Balance, weighted average grant date fair value	$ 33.62	$ 59.74	$ 79.60
Granted, weighted average grant date fair value	32.61	28.51	52.29
Vested, weighted average grant date fair value	34.82	43.83	65.21
Forfeited, weighted average grant date fair value	32.91	42.60	64.73
Outstanding, Ending Balance, weighted average grant date fair value	$ 31.64	$ 33.62	$ 59.74
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	425,018	308,737	304,504
Granted	543,438	540,128	343,397
Vested	(908,912)	(374,328)	(330,870)
Forfeited	(4,342)	(49,519)	(8,294)
Outstanding, Ending Balance	55,202	425,018	308,737
Outstanding, Beginning Balance, weighted average grant date fair value	$ 43.48	$ 65.80	$ 80.33
Granted, weighted average grant date fair value	25.91	35.92	55.92
Vested, weighted average grant date fair value	33.71	51.40	68.71
Forfeited, weighted average grant date fair value	31.10	40.33	74.22
Outstanding, Ending Balance, weighted average grant date fair value	$ 32.26	$ 43.48	$ 65.80

Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($)

3 Months Ended

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 82,776,000

^[1]

$ 55,618,000

$ 57,801,000

Total intrinsic value of stock options and SARs exercised

$ 30,800,000

30,800,000

5,400,000

Aggregate intrinsic value of the awards outstanding

Aggregate intrinsic value of the awards exercisable

$ 0

Maximum

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Weighted average remaining contractual life of awards exercisable

1 year

Performance-based PG-PSUs and RG-PSUs

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

3 years

$ 1,800,000

Performance Based TSR - PSUs

$ 1,500,000

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

3 years

$ 24,800,000

$ 12,400,000

$ 8,700,000

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

$ 13,000,000

Performance Share

3 years

Stock Appreciation Rights (SARs)

1,200,000

$ 1,200,000

Weighted average period

2 years

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Number of fully vested awards and awards expected to vest

$ 0

383,000

Weighted average exercise price of fully vested awards and awards expected to vest

$ 76.54

Weighted average exercise price of fully vested awards and awards expected to vest in years

4 months 24 days

[1]	Includes $30.8 million accelerated vesting of equity grants.

Stock-based Compensation Plans - PG/RG-PSUs Activities (Detail) - Performance-based PG-PSUs and RG-PSUs

12 Months Ended

Dec. 31, 2017

$ / shares

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Outstanding, Beginning Balance | shares

Granted | shares

122,921

^[1]

Outstanding, Ending Balance | shares

122,921

Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares

$ 0

Granted, weighted average grant date fair value | $ / shares

25.53

^[1]

Outstanding, Ending Balance, weighted average grant date fair value | $ / shares

$ 25.53

[1]	Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 150% depending on achievement of specifically identified performance targets.

Stock-based Compensation Plans - PG/RG-PSUs Activities (Parenthetical) (Detail) - Performance-based PG-PSUs and RG-PSUs	12 Months Ended
	Dec. 31, 2017
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	150.00%

Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	1.49%	0.94%	1.02%
Expected annual volatility	44.00%	49.00%	33.00%
Grant date fair value per unit	$ 26.26	$ 36.64	$ 56.78

Stock-based Compensation Plans - TSR - PSUs Activities (Detail) - Performance Based TSR - PSUs - $ / shares

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Summary of Performance Share Unit Awards outstanding, Number of Units

Outstanding, Beginning Balance

871,299

499,943

226,418

Outstanding, Ending Balance

^[1]

358,519

413,959

276,204

Vested and issued

^[2]

(85,461)

Forfeited

(134,515)

(42,603)

(2,679)

1,009,842

871,299

499,943

Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value

Outstanding, Beginning Balance, weighted average grant date fair value

$ 55.29

$ 69.95

$ 86.16

Granted, weighted average grant date fair value

^[1]

26.26

36.64

56.78

Vested, weighted average grant date fair value

^[2]

86.23

Forfeited, weighted average grant date fair value

85.24

46.09

82.60

Outstanding, Ending Balance, weighted average grant date fair value

$ 38.38

$ 55.29

$ 69.95

[1]	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 150% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.
[2]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited.

Stock-based Compensation Plans - TSR - PSUs Activities (Parenthetical) (Detail) - Performance Based TSR - PSUs - shares

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Shares vested and issued related to performance period number of common stock

^[1]

85,461

February 2014 Grant

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Return on common stock percentile

67.00%

May 2014 Grant

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Return on common stock percentile

56.00%

Minimum

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Potential payout of shares on performance units granted

0.00%

Maximum

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Potential payout of shares on performance units granted

150.00%

[1]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited.

Stock-based Compensation Plans - Stock Option and SARs Activities (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Exercised, Shares	0	0	(77,002)
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Beginning Balance, Shares	1,003,600	1,510,977	1,966,549
Exercised, Shares			(427,598)
Expired/forfeited, Shares	(620,821)	(507,377)	(27,974)
Ending Balance, Shares	382,779	1,003,600	1,510,977
Beginning Balance, Weighted Average Exercise Price	$ 69.08	$ 63.73	$ 59.80
Exercised, Weighted Average Exercise Price			45.67
Expired/forfeited, Weighted Average Exercise Price	62.29	53.16	63.10
Ending Balance, Weighted Average Exercise Price	$ 76.54	$ 69.08	$ 63.73

Stock-based Compensation Plans - Summary of SARs Outstanding and Exercisable (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number of outstanding Number of exercisable, Shares	382,779
Weighted Average Remaining Contractual Life (in years)	4 months 9 days
Weighted Average Exercise Price, Outstanding	$ 76.54	$ 69.08	$ 63.73	$ 59.80
Number of exercisable, Shares	382,779
Weighted Average Exercise Price, Exercisable	$ 76.54
Range of Exercise Prices One
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	70.00
Exercise Price, Maximum	$ 79.99
Number of outstanding Number of exercisable, Shares	380,879
Weighted Average Remaining Contractual Life (in years)	4 months 9 days
Weighted Average Exercise Price, Outstanding	$ 76.51
Number of exercisable, Shares	380,879
Weighted Average Exercise Price, Exercisable	$ 76.51
Range of Exercise Prices Two
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	80.00
Exercise Price, Maximum	$ 81.15
Number of outstanding Number of exercisable, Shares	1,900
Weighted Average Remaining Contractual Life (in years)	8 months 8 days
Weighted Average Exercise Price, Outstanding	$ 81.15
Number of exercisable, Shares	1,900
Weighted Average Exercise Price, Exercisable	$ 81.15

Stock-based Compensation Plans - Additional Information 4 (Detail) - USD ($) shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Maximum percentage of employees contribution									75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer contribution									$ 5,100,000	$ 4,700,000	$ 6,100,000
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ 14,077,000	$ 9,203,000	$ 14,466,000	$ 13,169,000	$ 11,013,000	$ 11,636,000	$ (25,746,000)	$ (16,056,000)	$ 50,915,000	$ (19,153,000)	$ 77,627,000
Shares held in rabbi trust total	2.9				2.7				2.9	2.7
Vested shares held in rabbi trust	2.8				2.3				2.8	2.3
Post-Retirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments for the five year period 2018 through 2022	$ 675,000								$ 675,000
Expected future benefit payments for the five year period 2023 through 2027	638,000								638,000
Estimated prior service cost amortized from accumulated other comprehensive income into statement of operation in 2018	$ 369,000								$ 369,000

Stock-based Compensation Plans - Summary of Change in Benefit Obligations Recognized in Comprehensive Income on Pre-tax Basis and Amounts Recognized in Consolidated Balance Sheets (Detail) - Other Post Retirement Benefits $ in Thousands	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 1,769
Change in benefit obligations (recognized in comprehensive income – pretax)
Prior service cost	1,769
Total other comprehensive income (loss) at December 31, 2017	1,769
Amounts recognized in the consolidated balance sheets:
Noncurrent liability-accrued benefit cost	$ 1,769

Stock-based Compensation Plans - Summary of Assumptions Used to Determine Benefit Obligation (Detail) - Other Post Retirement Benefits	12 Months Ended
	Dec. 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.30%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate	7.00%
Ultimate trend rate	5.00%
Year ultimate trend rate reached	2028

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net cash provided from operating activities included:

Income taxes (refunded from) paid to taxing authorities

$ (1,024)

$ (102)

$ 100

Interest paid

179,431

159,875

168,826

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net

^[1],[2]

20,245

(24,064)

22,184

Increase (decrease) in accrued capital expenditures

^[1]

$ 71,739

$ 61,419

$ (225,455)

[1]	For additional information on non-cash investing activities associated with the MRD Merger, see Note 3
[2]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) bbl / d Mcf / d	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Commitments And Contingencies Disclosure [Line Items]
Rent expense under operating leases \| $	$ 19.1	$ 14.0	$ 15.9
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	20 years
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
2018
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day \| bbl / d	13,000
Natural Gas \| 2038
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	400,000
Natural Gas \| Late 2018
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	15,000
Natural Gas \| Early 2019
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	65,000
Natural Gas \| Late 2019
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	180,000
North Louisiana
Commitments And Contingencies Disclosure [Line Items]
Remaining liability for expected volume deficiency payments \| $	$ 25.1

Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands	Dec. 31, 2017 USD ($)
Commitments And Contingencies Disclosure [Abstract]
2018	$ 18,498
2019	17,803
2020	16,945
2021	14,249
2022	8,058
Thereafter	32,909
Operating Lease Obligations	108,462
2018	3,472
2019	3,472
2020	3,174
2021	2,578
2022	215
Sublease Rental Receipts	$ 12,911

Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail)
$ in Thousands

Dec. 31, 2017

USD ($)

^[1]

Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]

$ 805,161

825,231

767,090

733,133

691,968

4,689,133

Transportation, Gathering and Processing Contracts

$ 8,511,716

[1]	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

Office Closing and Exit Costs - Additional Information (Detail) - USD ($)	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restructuring Cost And Reserve [Line Items]
Termination costs	$ (279,000)	$ (47,000)	$ (96,000)	$ 4,192,000	$ (822,000)	$ 136,000	$ 5,000	$ 162,000	$ 8,400,000	$ 3,770,000	$ (519,000)	$ 15,070,000
Stock-based compensation expense (gain)										1,664,000	0	217,000
Building lease										(70,000)	303,000	3,147,000
Accrued severance costs										$ 2,176,000	(822,000)	11,706,000
MRD
Restructuring Cost And Reserve [Line Items]
Termination costs											0
Office closing costs											$ 0
Oklahoma City Restructuring
Restructuring Cost And Reserve [Line Items]
Additional accruals for severance costs												275,000
Stock-based compensation expense (gain)												948,000
Virginia and West Virginia Properties and Other
Restructuring Cost And Reserve [Line Items]
Additional accruals for severance costs												11,400,000
Stock-based compensation expense (gain)												$ (731,000)

Office Closing and Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	$ 2,460	$ 11,630
Accrued severance costs	2,176	(822)	$ 11,706
Accrued building rent	(70)	303
Payments	(2,711)	(8,651)
Ending balance	$ 1,855	$ 2,460	$ 11,630

Office Closing and Exit Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Severance costs										$ 2,176	$ (822)	$ 11,706
Building lease										(70)	303	3,147
Stock-based compensation										1,664	0	217
Total termination costs	$ (279)	$ (47)	$ (96)	$ 4,192	$ (822)	$ 136	$ 5	$ 162	$ 8,400	$ 3,770	$ (519)	$ 15,070

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other	$ 0	$ 63,679	$ 0	$ 0	$ 0	$ 0	$ 0	$ 43,040		$ 63,679	$ 43,040	$ 590,174
MRD Merger expenses					$ 813	$ 33,791	$ 2,621	0	$ 37,200	$ 0	$ 37,225	$ 0
Oklahoma and Texas Properties
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other		$ 63,700
Western Oklahoma Properties
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other								$ 43,000

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Natural gas, NGLs and oil sales	$ 603,159	$ 507,541	$ 506,137	$ 559,450	$ 458,645	$ 304,477	$ 224,606	$ 209,487			$ 2,176,287	$ 1,197,215	$ 1,089,644
Derivative fair value income (loss)	25,024	(88,426)	111,195	165,557	(250,057)	64,556	(162,798)	86,908			213,350	(261,391)	416,364
Brokered natural gas, marketing and other	50,849	63,117	55,779	51,648	44,934	44,174	39,989	35,018			221,393	164,115	92,060
Total revenues and other income	679,032	482,232	673,111	776,655	253,522	413,207	101,797	331,413			2,611,030	1,099,939	1,598,068
Costs and expenses:
Direct operating	37,921	36,888	31,420	28,023	30,276	22,387	20,671	24,054			134,252	97,388	136,363
Transportation, gathering, processing and compression	200,300	191,645	191,590	177,648	164,338	138,764	136,844	125,263			761,183	565,209	396,739
Production and ad valorem taxes	11,757	11,993	9,969	9,163	6,790	6,717	6,049	5,887			42,882	25,443	33,860
Brokered natural gas and marketing	51,131	59,773	55,857	53,550	46,471	44,622	40,925	36,558			220,311	168,576	115,866
Exploration	7,893	22,767	14,498	8,504	13,684	6,943	6,785	4,913			53,662	32,325	21,406
Abandonment and impairment of unproved properties	217,544	42,568	5,193	4,420	6,307	6,082	7,059	10,628			269,725	30,076	47,619
General and administrative	80,553	53,035	52,322	47,496	57,027	41,024	46,064	40,657			233,406	184,772	194,015
MRD Merger expenses					813	33,791	2,621	0		$ 37,200	0	37,225	0
Termination costs	(279)	(47)	(96)	4,192	(822)	136	5	162	$ 8,400		3,770	(519)	15,070
Deferred compensation plan	(14,077)	(9,203)	(14,466)	(13,169)	(11,013)	(11,636)	25,746	16,056			(50,915)	19,153	(77,627)
Interest	51,473	49,179	47,926	47,101	46,749	45,967	37,758	37,739			195,679	168,213	166,439
Loss on early extinguishment of debt											0	0	22,495
Depletion, depreciation and amortization	162,918	159,749	152,504	149,821	149,662	131,489	122,390	120,561			624,992	524,102	581,155
Impairment of proved properties and other	0	63,679	0	0	0	0	0	43,040			63,679	43,040	590,174
(Gain) loss on the sale of assets	(207)	(102)	(807)	(22,600)	(470)	2,597	3,304	1,643			(23,716)	7,074	406,856
Total costs and expenses	806,927	681,924	545,910	494,149	509,812	468,883	456,221	467,161			2,528,910	1,902,077	2,650,430
Income (loss) before income taxes	(127,895)	(199,692)	127,201	282,506	(256,290)	(55,676)	(354,424)	(135,748)			82,120	(802,138)	(1,052,362)
Income tax (benefit) expense:
Current	17	0	0	0	98	0	0	0			17	98	29
Deferred	(349,097)	(71,992)	57,651	112,395	(95,679)	(13,705)	(129,488)	(41,976)			(251,043)	(280,848)	(338,706)
Total (benefit) expense for income taxes	(349,080)	(71,992)	57,651	112,395	(95,581)	(13,705)	(129,488)	(41,976)			(251,026)	(280,750)	(338,677)
Net income (loss)	$ 221,185	$ (127,700)	$ 69,550	$ 170,111	$ (160,709)	$ (41,971)	$ (224,936)	$ (93,772)			$ 333,146	$ (521,388)	$ (713,685)
Net income (loss) per common share:
Basic	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)			$ 1.34	$ (2.75)	$ (4.29)
Diluted	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)			$ 1.34	$ (2.75)	$ (4.29)

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Detail) - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Natural gas and oil properties:

Properties subject to depletion

^[1]

$ 10,572,453

$ 9,462,350

$ 8,047,181

Unproved properties

^[1]

2,644,000

2,923,803

949,155

Total

^[1]

13,216,453

12,386,153

8,996,336

Accumulated depletion and depreciation

^[1]

(3,649,716)

(3,129,816)

(2,635,031)

Natural gas and oil properties, successful efforts method, net

^[1]

$ 9,566,737

$ 9,256,337

$ 6,361,305

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Acquisitions

Acreage purchases

^[1]

$ 62,075

$ 33,142

$ 73,025

Oil and gas properties

^[1]

18,269

3,098,772

Asset retirement obligations and other

^[1]

21,908

Development

^[1]

1,177,526

497,795

708,268

Exploration:

Exploration drilling costs incurred

^[1]

2,030

37,680

87,505

Asset retirement obligations

82,776

^[2]

55,618

57,801

Gas gathering facilities:

Development

^[1]

15,097

3,595

13,337

Subtotal

^[1]

1,328,659

3,725,217

903,541

^[1],[3]

20,245

(24,064)

22,184

Total costs incurred

^[1]

1,348,904

3,701,153

925,725

Expense

Exploration:

Exploration costs incurred

^[1]

50,920

30,027

18,421

^[1]

$ 2,742

^[2]

$ 2,298

$ 2,985

[1]	Includes cost incurred whether capitalized or expensed.
[2]	Includes $30.8 million accelerated vesting of equity grants.
[3]	For additional information on non-cash investing activities associated with the MRD Merger, see Note 3

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Additional Information (Detail)
$ in Millions

12 Months Ended

Dec. 31, 2017

USD ($)

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2016

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2015

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2014

MMcfe

MMcf

MBbls

Percentage of proved resources reviewed by consultants

98.00%

Statement That Reserve Estimates Differ From Auditors

more than 10%

Proved Reserve And Pretax Present Value of Reserve Discounted

10.00%

Variance in reserve estimates

less than 5%.

Scheduled to be drilling period maximum for undeveloped reserves

Scheduled to be drilled within five years

Reserve attributable to natural gas

82.00%

86.00%

80.00%

Revisions of positive pricing

46,000

Improved recoveries

597,000

393,000

781,000

Proved undeveloped reserves dropped

668,000

269,000

1,200,000

Cost spent on undeveloped reserves transferred to developed reserves | $

$ 920

Estimated future development costs in 2018 | $

717

Estimated future development costs in 2019 | $

707

Estimated future development costs in 2020 | $

$ 567

Proved undeveloped reserves reported for more than five years

64,000

Maximum

Percentage of proved undeveloped reserves reported for more than five years

1.00%

Crude Oil and NGL

Benchmark price used for calculating average realized prices | $ / bbl

51.19

42.68

50.13

Crude Oil

Estimate reserve information average realized prices | $ / bbl

45.73

37.41

35.07

Proved developed and undeveloped reserves | MBbls

69,854

70,252

53,193

48,658

NGLs

Estimate reserve information average realized prices | $ / bbl

17.84

13.44

11.74

Proved developed and undeveloped reserves | MBbls

763,264

630,066

549,135

515,907

Natural Gas

Estimate reserve information average realized prices | $ / Mcf

2.60

2.07

Proved developed and undeveloped reserves | MMcf

10,263,649

7,870,416

6,277,697

6,922,836

Natural Gas, Per Thousand Cubic Feet

Benchmark price used for calculating average realized prices | $ / MMBTU

2.98

2.48

2.59

Natural Gas Equivalents

Proved reserves from drilling activities and evaluations of proved areas

^[1]

3,487,519

1,394,134

1,265,348

Proved developed and undeveloped reserve balances

^[1]

15,262,361

12,072,322

9,891,663

10,310,229

Revisions of previous estimates

^[1]

506,919

255,794

(211,163)

Revisions of positive performance

532,000

154,000

Ethane and Natural Gas Equivalents

Proved developed and undeveloped reserve balances

1,596,000

1,367,000

1,296,000

Ethane Reserves and NGLs

Proved developed and undeveloped reserves | MBbls

360,600

308,900

292,800

[1]	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.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail)

12 Months Ended

Dec. 31, 2017

MMcfe

MMcf

MBbls

Dec. 31, 2016

MMcfe

MMcf

MBbls

Dec. 31, 2015

MMcfe

MMcf

MBbls

Proved undeveloped reserves | MMcfe

6,914,287

5,302,414

Natural Gas

Extensions, discoveries and additions | MMcf

Beginning Balance | MMcf

7,870,416

6,277,697

6,922,836

Revisions | MMcf

70,222

(7,441)

(340,286)

2,866,103

1,193,154

1,017,956

Purchases | MMcf

7,738

943,544

Property sales | MMcf

(60,278)

(160,727)

(960,122)

Production | MMcf

(490,552)

(375,811)

(362,687)

Ending Balance | MMcf

10,263,649

7,870,416

6,277,697

Proved developed reserves | MMcf

5,437,674

4,352,141

3,376,165

Proved undeveloped reserves | MMcf

4,825,975

3,518,275

2,901,533

NGLs

Extensions, discoveries and additions

Beginning Balance

630,066

549,135

515,907

Revisions

83,338

41,402

17,717

87,572

26,991

36,308

Purchases

330

40,724

Property sales

(2,356)

(360)

(441)

Production

(35,686)

(27,826)

(20,356)

Ending Balance

763,264

630,066

549,135

Proved developed reserves

448,258

363,852

309,306

Proved undeveloped reserves

315,006

266,214

239,828

Crude Oil and Condensate

Extensions, discoveries and additions

Beginning Balance

70,252

53,193

48,658

Revisions

(10,555)

2,471

3,804

15,997

6,506

4,924

Purchases

11,986

Property sales

(1,121)

(295)

(109)

Production

(4,785)

(3,609)

(4,084)

Ending Balance

69,854

70,252

53,193

Proved developed reserves

36,808

39,110

31,679

Proved undeveloped reserves

33,046

31,143

21,514

Natural Gas Equivalents

Proved developed reserves | MMcfe

^[1]

8,348,074

6,769,908

5,422,075

Proved undeveloped reserves | MMcfe

^[1]

6,914,287

5,302,414

4,469,588

Beginning Balance | MMcfe

^[1]

12,072,322

9,891,663

10,310,229

Revisions | MMcfe

^[1]

506,919

255,794

(211,163)

Extensions, discoveries and additions | MMcfe

^[1]

3,487,519

1,394,134

1,265,348

Purchases | MMcfe

^[1]

10,116

1,259,806

Property sales | MMcfe

^[1]

(81,133)

(164,655)

(963,423)

Production | MMcfe

^[1]

(733,382)

(564,420)

(509,328)

Ending Balance | MMcfe

^[1]

15,262,361

12,072,322

9,891,663

[1]	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.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Detail)

12 Months Ended

Dec. 31, 2017

MMcfe

Beginning proved undeveloped reserves at December 31, 2016

5,302,414

Undeveloped reserves transferred to developed

(1,861,994)

Revisions

308,929

^[1]

Purchases/(sales)

(8,907)

Extension and discoveries

3,173,845

Ending proved undeveloped reserves at December 31, 2017

6,914,287

[1]	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.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) - MMcfe MMcfe in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved undeveloped reserves dropped	668	269	1,200

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014