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Natural gas and oil properties, successful efforts method

1,654,292

^[1]

12,386,153

8,996,336

Accumulated depletion and depreciation

^[1]

(3,129,816)

(2,635,031)

Natural gas and oil properties, successful efforts method, net

^[1]

9,256,337

6,361,305

Other property and equipment

112,796

110,013

Accumulated depreciation and amortization

(95,923)

(90,558)

Other Property and equipment, net

16,873

19,455

Other assets

72,655

72,979

Total assets

11,282,245

6,900,031

Current liabilities:

Accounts payable

229,190

117,346

Asset retirement obligations

7,271

15,071

Accrued liabilities

265,843

188,028

Accrued interest

35,340

30,139

Derivative liabilities

165,009

1,136

Total current liabilities

702,653

351,720

Bank debt

876,428

86,427

2,848,591

738,101

Deferred compensation liabilities

48,498

1,826,775

Deferred tax liabilities

943,343

777,947

Derivative liabilities

24,491

119,231

104,792

Asset retirement obligations and other liabilities

310,642

254,590

Total liabilities

5,873,877

4,140,373

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, 247,174,903 issued at December 31, 2016 and 169,375,743 issued at December 31, 2015

2,471

1,693

Common stock held in treasury, 30,547 shares at December 31, 2016 and 59,283 shares at December 31, 2015

(1,209)

(2,245)

Additional paid-in capital

5,524,423

2,442,623

Retained earnings (deficit)

(117,317)

317,587

Total stockholders' equity

5,408,368

2,759,658

Total liabilities and stockholders' equity

$ 11,282,245

$ 6,900,031

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

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 5,559	$ 4,994
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	247,174,903	169,375,743
Common stock held in treasury, shares	30,547	59,283

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

3 Months Ended

12 Months Ended

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, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Revenues and other income:

Natural gas, NGLs and oil sales

$ 458,645

$ 304,477

$ 224,606

$ 209,487

$ 254,043

$ 252,065

$ 258,053

$ 325,483

$ 1,197,215

$ 1,089,644

$ 1,911,989

Derivative fair value (loss) income

(250,057)

64,556

(162,798)

86,908

126,312

202,004

(34,791)

122,839

(261,391)

416,364

383,520

Brokered natural gas, marketing and other

44,934

44,174

39,989

35,018

30,372

25,864

21,339

14,485

164,115

92,060

130,548

Total revenues and other income

253,522

413,207

101,797

331,413

410,727

479,933

244,601

462,807

1,099,939

1,598,068

2,426,057

Costs and expenses:

Direct operating

30,276

22,387

20,671

24,054

29,388

35,058

34,780

37,137

97,388

136,363

150,483

Transportation, gathering, processing and compression

164,338

138,764

136,844

125,263

112,481

99,634

95,198

89,426

565,209

396,739

325,289

Production and ad valorem taxes

6,790

6,717

6,049

5,887

7,354

7,336

9,242

9,928

25,443

33,860

44,555

Brokered natural gas and marketing

46,471

44,622

40,925

36,558

34,942

32,331

27,031

21,562

168,576

115,866

129,980

Exploration

13,684

6,943

6,785

4,913

4,260

4,235

5,025

7,886

32,325

21,406

63,548

Abandonment and impairment of unproved properties

6,307

6,082

7,059

10,628

11,432

12,366

12,330

11,491

30,076

47,619

47,079

General and administrative

57,027

41,024

46,064

40,657

43,544

46,178

55,964

48,329

184,772

194,015

213,426

MRD Merger expenses

813

33,791

2,621

37,225

Termination costs

(822)

136

162

8,780

(77)

417

5,950

$ 8,400

(519)

15,070

8,371

Deferred compensation plan

(11,013)

(11,636)

25,746

16,056

(21,016)

(43,705)

(7,282)

(5,624)

19,153

(77,627)

(74,550)

Interest

46,749

45,967

37,758

37,739

40,849

42,904

43,479

39,207

168,213

166,439

168,977

Loss on early extinguishment of debt

22,495

24,596

Depletion, depreciation and amortization

149,662

131,489

122,390

120,561

127,977

153,993

151,895

147,290

524,102

581,155

551,032

Impairment of proved properties

43,040

87,941

502,233

43,040

590,174

28,024

Loss (gain) on the sale of assets

(470)

2,597

3,304

1,643

408,909

681

(2,909)

175

7,074

406,856

(285,638)

Total costs and expenses

509,812

468,883

456,221

467,161

896,841

915,662

425,170

412,757

1,902,077

2,650,430

1,395,172

(Loss) income before income taxes

(256,290)

(55,676)

(354,424)

(135,748)

(486,114)

(435,729)

(180,569)

50,050

(802,138)

(1,052,362)

1,030,885

Income tax (benefit) expense:

Current

Deferred

(95,679)

(13,705)

(129,488)

(41,976)

(164,316)

(134,781)

(61,975)

22,366

(280,848)

(338,706)

396,502

Total income tax (benefit) expense

(95,581)

(13,705)

(129,488)

(41,976)

(164,287)

(134,781)

(61,975)

22,366

(280,750)

(338,677)

396,503

Net (loss) income

$ (160,709)

$ (41,971)

$ (224,936)

$ (93,772)

$ (321,827)

$ (300,948)

$ (118,594)

$ 27,684

$ (521,388)

$ (713,685)

$ 634,382

Net (loss) income per common share:

Basic

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ (1.93)

$ (1.81)

$ (0.71)

$ 0.16

$ (2.75)

$ (4.29)

$ 3.81

Diluted

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ (1.93)

$ (1.81)

$ (0.71)

$ 0.16

$ (2.75)

$ (4.29)

$ 3.79

Weighted average common shares outstanding:

Basic

^[1]

189,868

166,389

163,625

Diluted

189,868

166,389

164,403

[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 (LOSS) INCOME - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Statement Of Income And Comprehensive Income [Abstract]

Net (loss) income

$ (521,388)

$ (713,685)

$ 634,382

Other comprehensive loss:

De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes

^[1]

(6,236)

Total comprehensive (loss) income

^[2]

$ (521,388)

$ (713,685)

$ 628,146

[1]	Amounts are net of income tax benefit of $3,986 for the year ended December 31, 2014.
[2]	As of March 31, 2013, we elected to discontinue hedge accounting prospectively, and as of December 31, 2014, all remaining accumulated other comprehensive income had been transferred to earnings.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)
Statement Of Income And Comprehensive Income [Abstract]
De-designated hedges reclassified into natural gas, NGLs and oil sales, tax portion	$ 3,986

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net (loss) income	$ (521,388)	$ (713,685)	$ 634,382
Adjustments to reconcile net (loss) income to net cash provided from operating activities:
Loss from equity method investments, net of distributions	0	0	3,095
Deferred income tax (benefit) expense	(280,848)	(338,706)	396,502
Depletion, depreciation and amortization and impairment	567,142	1,171,329	579,056
Exploration dry hole and impairment costs	18	88	16,145
Abandonment and impairment of unproved properties	30,076	47,619	47,079
Derivative fair value loss (income)	261,391	(416,364)	(383,520)
Cash settlements on derivative financial instruments that do not qualify for hedge accounting	347,336	532,122	(42,634)
Allowance for bad debt	800	2,300	250
Amortization of deferred financing costs, loss on extinguishment of debt and other	7,170	29,383	24,694
Deferred and stock-based compensation	74,685	(20,411)	(4,295)
Loss (gain) on the sale of assets	7,074	406,856	(285,638)
Changes in working capital:
Accounts receivable	(20,586)	64,704	(5,329)
Inventory and other	6,220	(14,868)	(4,521)
Accounts payable	(27,259)	(26,197)	(1,023)
Accrued liabilities and other	(64,763)	(32,768)	110
Net cash provided from operating activities	387,068	691,402	974,353
Investing activities:
Additions to natural gas and oil properties	(466,252)	(1,030,644)	(1,200,419)
Additions to field service assets	(3,052)	(4,441)	(11,863)
Acreage purchases	(43,482)	(74,880)	(211,971)
MRD Merger, net of cash acquired	7,180	0	0
Other	0	(75)	1,103
Proceeds from disposal of assets	193,755	890,901	180,508
Purchases of marketable securities held by the deferred compensation plan	(37,019)	(28,876)	(30,898)
Proceeds from the sales of marketable securities held by the deferred compensation plan	40,035	29,243	28,084
Net cash used in investing activities	(308,835)	(218,772)	(1,245,456)
Financing activities:
Borrowings on credit facilities	2,274,000	2,271,000	2,107,000
Repayments on credit facilities	(1,487,000)	(2,899,000)	(1,884,000)
Issuance of senior notes	0	750,000	0
Repayment of senior or senior subordinated notes	(273,012)	(516,875)	(312,000)
Dividends paid	(16,682)	(27,083)	(26,610)
Debt issuance costs	(6,342)	(14,156)	(8,866)
Issuance of common stock	0	0	396,562
Taxes paid for shares withheld	(3,849)	(7,702)	(20,218)
Change in cash overdrafts	18,393	(37,089)	3,371
Proceeds from the sales of common stock held by the deferred compensation plan	13,102	8,298	15,964
Net cash (used in) provided from financing activities	(78,390)	(472,607)	271,203
(Decrease) increase in cash and cash equivalents	(157)	23	100
Cash and cash equivalents at beginning of year	471	448	348
Cash and cash equivalents at end of year	314	471	448
MRD
Financing activities:
Repayments on credit facilities	$ (597,000)	$ 0	$ 0

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common stock held in treasury	Additional paid-in capital	Retained earnings	Accumulated other comprehensive income (loss)
Beginning balance at Dec. 31, 2013	$ 2,414,452	$ 1,634	$ (3,637)	$ 1,959,636	$ 450,583	$ 6,236
Beginning balance Shares at Dec. 31, 2013		163,441,000
Issuance of common stock	398,607	$ 53	0	398,554	0	0
Issuance of common stock, shares		5,270,000
Stock-based compensation expense	42,834	$ 0	0	42,834	0	0
Common dividends declared ($0.16 per share for 2014, 2015 and $0.08 per share for 2016)	(26,610)	0	0	0	(26,610)	0
Treasury stock issuance	0	0	549	(549)	0	0
Other comprehensive income (loss)	(6,236)	0	0	0	0	(6,236)
Net (loss) income	634,382	0	0	0	634,382	0
Ending balance at Dec. 31, 2014	3,457,429	$ 1,687	(3,088)	2,400,475	1,058,355	0
Ending 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 2014, 2015 and $0.08 per share for 2016)	(27,083)	0	0	0	(27,083)	0
Treasury stock issuance	0	0	843	(843)	0	0
Net (loss) income	(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	169,375,743	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 2014, 2015 and $0.08 per share for 2016)	(16,682)	0	0	0	(16,682)	0
Treasury stock issuance	0	0	1,036	(1,036)	0	0
Cumulative-effect adjustment from adoption of ASU 2016-09	103,166	0	0	0	103,166	0
Net (loss) income	(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

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended												12 Months Ended
	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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Stockholders Equity [Abstract]
Common dividends declared per share	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.08	$ 0.16	$ 0.16

Summary of Organization and Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2016
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 growth in 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, 2016

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. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in brokered natural gas, marketing and other revenues in the accompanying consolidated statements of operations. As of June 2014, we no longer have equity method investments. All material intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States 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.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform to the current year presentation. These reclassifications were not material to the financial statements.

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 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 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 titles to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. In 2014, we included additional broker revenues and broker expenses from the release of transportation capacity where we had taken firm transportation ahead of our production volumes. Our net brokered margin was a loss of $2.8 million in 2016 compared to a loss of $2.7 million in 2015 and a gain $9.4 million in 2014.

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 $5.6 million at December 31, 2016 compared to $5.0 million at December 31, 2015. We recorded bad debt expense of $800,000 in the year ended December 31, 2016 compared to $2.3 million in the year ended December 31, 2015 and $250,000 in the year ended 2014.

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 is included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as financing activities 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 is reported in other assets in the accompanying consolidated balance sheet.

Inventory

Inventories were comprised of $9.4 million of materials and supplies at December 31, 2016 compared to $20.8 million at December 31, 2015. 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 market, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. At December 31, 2016, we also had commodity inventory of $8.3 million, compared to $4.8 million at December 31, 2015, which is carried at lower of weighted average cost or market, on a first-in, first-out basis. Commodity inventory at December 31, 2016 consists of natural gas and NGLs held in storage or as line fill in pipelines.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, we have only one reporting unit. Our annual assessment date will be November 1. The fair value of a reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairment expense. To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value. Absent a qualitative assessment, or, through a qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair value of the reporting unit. For additional information see Note 4.

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, 2016, additional expense of $1.9 million was recorded related to these costs.

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. Unproved properties had a net book value of $2.9 billion as of December 31, 2016 compared to $949.2 million in 2015. We have recorded abandonment and impairment expense related to unproved properties of $30.1 million in the year ended December 31, 2016 compared to $47.6 million in 2015 and $47.1 million in 2014.

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. For additional information regarding our dispositions, see Note 3.

Acquisitions. Acquisitions of proved properties are accounted for as business combinations and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. 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 $8.4 million in the year ended December 31, 2016 compared to $11.9 million in the year ended December 31, 2015 and $12.9 million in the year ended December 31, 2014.

Other Assets

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. Other assets at December 31, 2015 include $62.4 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage.

Stock-based Compensation Arrangements

The fair value of performance share unit awards (“PSUs”) is estimated on the date of grant using a Monte Carlo simulation method. A Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award granted. The fair value of restricted stock awards (or “Liability Awards”) and restricted stock unit awards (or “Equity Awards”) is determined based on the fair market value of our common stock on the date of grant.

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. The majority of our Liability Awards are deposited in our deferred compensation plan at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying consolidated statements of operations.

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 unless specific hedge accounting criteria are met. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. For more information, see Note 11. The effective portions of the discontinued deferred hedges as of March 1, 2013 were included in accumulated other comprehensive income (“AOCI”) and were transferred to earnings during the same periods in which the forecasted transactions were recognized in earnings. During 2014, our remaining AOCI hedging gains were transferred to earnings. Since discontinuing hedge accounting, 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. 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.

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. We have not modified any existing derivative contracts.

Concentrations of Credit Risk

As of December 31, 2016, 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 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, obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $5.6 million at December 31, 2016 compared to $5.0 million at December 31, 2015.

For the years ended December 31, 2016 and 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2014, we had four customers 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. In 2017, we have derivatives contracts with one counterparty for natural gas volumes of 6,575 Mmbtu/day and crude oil contracts for 608 bbls/day that may have a margin requirement if natural gas is higher than $4.43 per mcf or crude oil is higher than $83.20 per barrel.

At December 31, 2016, our derivative counterparties included twenty-two financial institutions and commodity traders of which all but five are secured lenders in our bank credit facility. At December 31, 2016, our net derivative asset includes a payable to the counterparties not included in our bank credit facility totaling $16.8 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.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the year ended December 31, 2014 (in thousands). Amounts included in AOCI exclusively relate to our derivative activity. See Note 11 for additional information on the discontinuance of hedge accounting.

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2013		10,222			(3,986	)		6,236
Contract settlements reclassified to income		(10,222	)		3,986			(6,236	)
Accumulated other comprehensive income at December 31, 2014	$	—		$	—		$	—

New Accounting Pronouncements

Recently Adopted

In April 2014, an accounting standards update was issued that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption was permitted but only for disposals (or classifications that are held for sale) that had not been reported in financial statements previously issued or available for use. We adopted this new standard in first quarter 2014 and, as a result, the Conger Exchange defined and described in more detail below, was not reported as a discontinued operation.

In August 2014, an accounting standards update was issued that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. This standard is effective for us in first quarter 2016. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, we did implement and formalize policies and procedures to ensure compliance with the requirement to perform ongoing interim and annual going concern assessments.

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 is permitted. We are electing to early adopt this accounting standards update in fourth quarter 2016 which requires us to reflect any adjustments as of January 1, 2016, the beginning of the annual period that includes the interim period of adoption. The following summarizes the impact of Accounting Standards Update 2016-09 “Compensation-Stock Compensation (Topic 718)” (ASU 2016-09) 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
	(unaudited)
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 adjustments 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
Year ended 2012		647,099		658,069
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
Year ended 2012		881,619			870,649
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

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 will be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. We continue to evaluate the available adoption methods. Early adoption is permitted with an effective date no earlier than first quarter 2017. We are utilizing 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 net revenues, operating income (loss) and our consolidated balance sheet. We are still evaluating the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures.

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 12 months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standard update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standard 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 and 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 standard, we will provide additional information about the expected financial impact at a future date.

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 will be applied retrospectively with early adoption permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated cash flow statement presentation.

In January 2017, an accounting standards update was issued that eliminates the requirements to calculate the implied fair value of goodwill to measure 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 us in first quarter 2020 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 are evaluating the provisions of this accounting standards update and assessing the impact, if any, that it may have on our consolidated results of operations, financial position or cash flows.

Dispositions and Acquisitions

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Dispositions and Acquisitions

(3)	Dispositions and Acquisitions

We recognized a pretax net loss on the sale of assets of $7.1 million in the year ended December 31, 2016 compared to a loss of $406.9 million in 2015 and a gain of $285.6 million in 2014. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2016, 2015 and 2014.

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 compared to $98.3 million in the year ended December 31, 2014.

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 and resulting in a pretax gain of $943,000.

2014 Dispositions

Conger Exchange Transaction. In April 2014, we entered into an exchange agreement with EQT Corporation and certain of its affiliates (collectively, “EQT”) in which we sold our Conger assets in Glasscock and Sterling Counties, Texas in exchange for producing properties and gas gathering assets in Virginia and $145.0 million in cash, before closing adjustments (“the Conger Exchange”). We closed the exchange transaction in June 2014 and recognized a pretax gain of $272.7 million, after selling expenses of $5.0 million, which is recognized as a gain on sale of assets in our consolidated statements of operations for the year ended December 31, 2014. For the period from January 1, 2014 through June 16, 2014, we recognized $21.9 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 and transportation expenses) for our Conger assets.

In connection with the Conger Exchange, we acquired the remaining 50% interest held by EQT in Nora Gathering, LLC (“NGLLC”), a natural gas gathering operation, which we had previously accounted for using the equity method of accounting. As of June 2014, we consolidated NGLLC into our consolidated financial statements. Our previous 50% membership interest in NGLLC was remeasured to fair value of $134.8 million on the acquisition date, resulting in a gain of $10.0 million which is recognized in gain on sale of assets in our consolidated statements of operations for the year ended December 31, 2014.

For the period from June 16, 2014 through December 31, 2014, we recognized $33.8 million of natural gas, oil and NGLs sales from the property interests acquired in the Conger Exchange and we recognized $25.7 million of field net operating income from the property interests acquired in the Conger Exchange.

Conger Exchange Fair Value. Accounting standards define fair value as 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 (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The fair value of the Conger Exchange described above was based on an income approach which was supplemented by a market approach. For the natural gas and oil properties, the income approach uses significant inputs not observable in the market, which are Level 3 inputs. The significant inputs assumed include future production, costs and capital, commodity prices, risk-adjusted discount rates, natural gas and oil pricing differentials, and projected reserve recovery factors. The market approach uses inputs such as recent market transactions in a similar geographic region and with similar production. The income approach for the natural gas gathering operations was based on a discounted future net cash flow model, which uses Level 3 inputs and was supplemented by a market approach.

Other. During 2014, we also sold miscellaneous proved and unproved oil and gas properties, inventory and other property and equipment for proceeds of $35.5 million and recognized a pretax gain of $3.0 million.

Memorial Merger

On September 16, 2016, we completed our merger with Memorial Resource Development Corporation (the “MRD Merger” or “Memorial”) 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 have incurred merger-related expenses of approximately $37.2 million to date 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 preliminary 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. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of certain pre-merger contingencies, final tax returns that provide the underlying tax basis of Memorial’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities, including goodwill, may be revised as appropriate.

The following table sets forth our preliminary purchase price allocation (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		114,426
Long-term debt		1,204,449
Deferred taxes		547,348
Other long-term liabilities		77,223
Total purchase price plus liabilities assumed	$	5,032,243

Fair value of Memorial assets:
Cash and equivalents	$	7,180
Other current assets		97,875
Derivative instruments		152,994
Natural gas and oil properties:
Proved property		1,117,011
Unproved property		1,999,187
Other property and equipment		3,579
Goodwill ^(a)		1,654,292
Other		125
Total asset value	$	5,032,243

^(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 statement of operations beginning on September 16, 2016. 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 oil and gas 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	$	(590,777	)	$	(555,793	)

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

Goodwill

12 Months Ended

Dec. 31, 2016

Goodwill And Intangible Assets Disclosure [Abstract]

Net (Loss) Income 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. In fourth quarter 2016, we reviewed our goodwill balance for impairment in accordance with our accounting policy. Based on the length of time between the closing of the MRD Merger and November 1 (the date of our annual impairment analysis), we performed a qualitative assessment to assess whether it was more likely than not that the fair value of our reporting unit was less than the carrying value by examining the relevant events and circumstances that could have a negative impact on goodwill, such as macroeconomic conditions, industry and market conditions, including current commodity prices, earnings and cash flows, overall financial performance and other relevant entity specific events. Based on our qualitative assessment of these circumstances, we concluded it was not more likely than not, that the fair value of our reporting unit was less than the carrying value and therefore, a full impairment test was not warranted.

Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

(5)	Income Taxes

Our income tax benefit was $280.8 million for the year ended December 31, 2016 compared to income tax benefit of $338.7 million in 2015 and income tax expense of $396.5 million in 2014. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2016		2015			2014
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
State	3.0			4.3			3.1
State apportionment rate change	1.0			(0.2	)		(0.2	)
Non-deductible executive compensation	(0.2	)		(0.1	)		0.2
Non-deductible MRD transaction costs	(0.6	)		—			—
Valuation allowances	(2.5	)		(6.8	)		0.2
Deficits in equity compensation	(0.7	)		—			—
Other	—			—			0.2
Consolidated effective tax rate	35.0	%		32.2	%		38.5	%

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

		2016								2015										2014
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred		Total
U.S. federal	$	—	$	(266,105	)	$	(266,105	)	$	—	$	(328,257	)		$	(328,257	)		$		—	$		361,152		$	361,152
U.S. state and local		98		(14,743	)		(14,645	)		29		(10,449	)			(10,420	)				1			35,350			35,351
Total	$	98	$	(280,848	)	$	(280,750	)	$	29	$	(338,706	)		$	(338,677	)		$		1	$		396,502		$	396,503

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

	December 31,
	2016			2015
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	478,203		$	173,503
Deferred compensation		50,808			45,413
Equity compensation		29,528			25,940
AMT credits and other credits		13,644			4,437
Asset retirement obligation		99,000			101,142
Cumulative mark-to-market loss		73,404			—
Other		39,922			10,163
Valuation allowances:
Federal		(43,600	)		(42,500	)
State, net of federal benefit		(58,424	)		(41,516	)
Deferred compensation plans and other		(5,150	)		(3,607	)
Total deferred tax assets		677,335			272,975
Deferred tax liabilities:
Depreciation, depletion and investments		(1,619,922	)		(940,482	)
Cumulative mark-to-market gain		—			(109,845	)
Other		(756	)		(595	)
Total deferred tax liabilities		(1,620,678	)		(1,050,922	)
Net deferred tax liability	$	(943,343	)	$	(777,947	)

At December 31, 2016, deferred tax liabilities exceeded deferred tax assets by $943.3 million. As of December 31, 2016, we have a valuation allowance of $4.2 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, 2016, we have a full valuation allowance of $24.5 million in net operating loss carryforwards and state credits for California, Colorado, Mississippi, New Mexico, Oklahoma and West Virginia where we do not expect to generate any taxable income in the future due to completed or anticipated sales. We also have a $1.5 million valuation allowance against our Louisiana net operating loss carryfowards related to our activity in Louisiana prior to the MRD Merger. During 2016, we adjusted our valuation allowance related to our Pennsylvania net operating loss carryforwards to $32.4 million due to the low commodity price environment and the limitation Pennsylvania places on future utilization of net operating loss carryforwards.

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

		2016			2015			2014
Balance at the beginning of the year	$	(87,623	)	$	(16,599	)	$	(14,781	)
Charged to provision for income taxes:
State net operating loss carryforwards		(17,374	)		(30,457	)		(5,800	)
Federal net operating carryforwards		(1,100	)		(42,500	)		—
Other state valuation allowances		500			(1,050	)		—
Other federal valuation allowances		(477	)		(511	)		363
Rabbi trust valuation allowance		(1,066	)		3,494			3,619
Other		(34	)		—			—
Balance at the end of the year	$	(107,174	)	$	(87,623	)	$	(16,599	)

At December 31, 2016, we had federal and state net operating loss (“NOL”) carryforwards of $1.2 billion and alternative minimum tax (“AMT”) NOL carryforwards of $1.0 billion that expire between 2018 and 2035. Our federal deferred tax asset related to regular NOL carryforwards at December 31, 2016 was $403.4 million, after the adoption of ASU 2016-9. At December 31, 2016, we have AMT credit carryforwards of $9.7 million that are not subject to limitation or expiration.

We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Mississippi, 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, 2016. Throughout 2016, our unrecognized tax benefits were not material.

In September 2016, we completed the MRD Merger. For federal income tax purposes, the merger qualified as a tax-free merger and we acquired carryover tax basis in MRD’s assets and liabilities. MRD had a net deferred tax asset resulting from its federal net operating loss estimated at $12.4 million through the date of acquisition. The merger resulted in a change of control for federal income tax purposes and the NOL’s usage will be subject to an annual limitation in part based on MRD’s value at the date of the merger. We anticipate 100% utilization of the NOL prior to expiration.

Net (Loss) Income Per Common Share

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

(6)	Net (Loss) Income 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. 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,
	2016			2015			2014
Net (loss) income, as reported	$	(521,388	)	$	(713,685	)	$	634,382
Participating basic earnings ^(a)		(223	)		(450	)		(10,725	)
Basic net (loss) income attributed to common stockholders		(521,611	)		(714,135	)		623,657
Reallocation of participating earnings ^(a)		—			—			48
Diluted net (loss) income attributed to common stockholders	$	(521,611	)	$	(714,135	)	$	623,705
Net (loss) income per common share:
Basic	$	(2.75	)	$	(4.29	)	$	3.81
Diluted	$	(2.75	)	$	(4.29	)	$	3.79

^(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,
	2016	2015		2014
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	189,868		166,389		163,625
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	—		—		778
Weighted average common shares outstanding – diluted	189,868		166,389		164,403

⁽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 all of the periods ending December 31, 2016, 2015 and 2014. Due to our net loss for the years ended December 31, 2016 and 2015, we excluded all outstanding stock appreciation rights and restricted stock from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. SARs of 1,900 for the year ended December 31, 2014 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2016

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 project with exploratory well costs at December 31, 2015 was completed in 2016. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2016, 2015 and 2014 (in thousands, except for number of projects):

	2016			2015			2014
Balance at beginning of period	$	4,161		$	2,996		$	6,964
Additions to capitalized exploratory well costs pending the determination of proved reserves		9,128			1,165			18,747
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(5,877	)		—			(15,735	)
Capitalized exploratory well costs charged to expense		—			—			(6,980	)
Balance at end of period		7,412			4,161			2,996
Less exploratory well costs that have been capitalized for a period of one year or less		(7,412	)		(1,165	)		(2,996	)
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, 2016

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, 2016 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 2016, 2015, and 2014.


		December 31, 2016			December 31, 2015
Bank debt (2.4%) ^(a)	$	882,000		$	95,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,514			—
5.00% senior notes due 2022		580,032			—
5.75% senior notes due 2021		475,952			—
5.875% senior notes due 2022 ^(b)		329,244			—
Other senior notes due 2022 ^(c)		1,090			—
Total senior notes		2,877,832			750,000
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			750,000
5.00% senior subordinated notes due 2022		19,054			600,000
5.75% senior subordinated notes due 2021		22,214			500,000
Total senior subordinated notes		48,980			1,850,000
Total debt		3,808,812			2,695,000
Unamortized premium		7,258			—
Unamortized debt issuance costs		(42,553	)		(43,697	)
Total debt net of debt issuance costs	$	3,773,517		$	2,651,303

^(a) As of September 16, 2016, we repaid the $597.0 million balance outstanding on the Memorial credit facility with funds borrowed under the Range credit facility and terminated the Memorial credit facility.

^(b) 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 Note Exchange and Cash Tender Offer below.

^(c) 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 Note 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, 2016, 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 each May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 17, 2016, 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, 2016, the outstanding balance under the bank credit facility was $882.0 million with $268.1 million of undrawn letters of credit leaving $849.9 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 of the ABR loans to LIBOR loans. The weighted average interest rate was 2.2% for the year ended December 31, 2016 compared to 1.7% for the year ended December 31, 2015 and 2.0% for the year ended December 31, 2014. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2016, the commitment fee was 0.3%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

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 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 of 1933, as amended (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 Note 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 $329.2 million senior unsecured 5.875% notes due 2022 (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 was 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 Note 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	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%

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 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 notes 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 all 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 are subordinated 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.

In 2014, we announced a call for the redemption of $300.0 million of our outstanding 8.0% senior subordinated notes due 2019 at 104.0% of par plus accrued and unpaid interest which were redeemed on June 26, 2014. In the year ended 2014, we recognized a $24.6 million loss on extinguishment of debt, including transaction call premium costs as well as 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, 2016.

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2016 (in thousands):

	Year Ended December 31,
2017	$	—
2018		—
2019		882,000
2020		—
2021		498,166
Thereafter		2,428,646
	$	3,808,812

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015 (in thousands):


	2016			2015
Beginning of period	$	264,137		$	287,463
Liabilities incurred		2,694			4,595
Acquisitions		21,900			1,584
Liabilities settled		(11,511	)		(18,828	)
Disposition of wells		(10,540	)		(45,845	)
Accretion expense		18,021			19,163
Change in estimate		(26,758	)		16,005
End of period		257,943			264,137
Less current portion		(7,271	)		(15,071	)
Long-term asset retirement obligations	$	250,672		$	249,066

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, 2016

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 2014:


	Year Ended December 31,
	2016			2015		2014
Beginning balance		169,316,460			168,628,177		163,342,894
MRD Merger		77,042,749			—		—
Equity offering		—			—		4,560,000
Stock options/SARs exercised		—			77,002		195,242
Restricted stock grants		490,609			335,103		270,062
Restricted stock units vested		266,541			252,507		244,413
Shares retired		(739	)		—		—
Treasury shares		28,736			23,671		15,566
Ending balance		247,144,356			169,316,460		168,628,177

Common Stock Dividends

The board of directors declared quarterly dividends of $0.02 per common share for each of the four quarters of 2016. The board of directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2015 and 2014. 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 and cash flow from operations, level of capital expenditures, 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. Dividends are limited to our legally available funds.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Activities

12 Months Ended

Dec. 31, 2016

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 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. Their fair value, 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 loss of $187.2 million at December 31, 2016. These contracts expire monthly through December 2018. The following table sets forth the derivative volumes by year as of December 31, 2016, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2017	Swaps ⁽¹⁾	840,692 Mmbtu/day	$ 3.19
2018	Swaps	276,712 Mmbtu/day	$ 3.12
2017	Collar ⁽¹⁾	42,750 Mmbtu/day	$ 3.48-$ 4.15
2017	Purchased Put ⁽¹⁾	175,890 Mmbtu/day	$ 3.48 ⁽²⁾
2017	Sold Call	9,041 Mmbtu/day	$ 3.75 ⁽³⁾

Crude Oil
2017	Swaps ⁽¹⁾	8,542 bbls/day	$ 55.77
2018	Swaps	2,750 bbls/day	$ 54.24

NGLs (C2-Ethane)
2017	Swaps	3,000 bbls/day	$ 0.27/gallon

NGLs (C3-Propane)
2017	Swaps	11,610 bbls/day	$ 0.55/gallon
2018	Swaps	5,699 bbls/day	$ 0.65/gallon

NGLs (NC4-Normal Butane)
2017	Swaps	7,000 bbls/day	$ 0.73/gallon
2018	Swaps	2,000 bbls/day	$ 0.78/gallon

NGLs (C5-Natural Gasoline)
2017	Swaps	5,250 bbls/day	$ 1.06/gallon
2018	Swaps	1,000 bbls/day	$ 1.18/gallon

⁽¹⁾ Includes derivative instruments assumed in connection with the MRD Merger.

⁽²⁾Weighted average deferred premium is ($0.32).

⁽³⁾ Weighted average deferred premium is $0.31.

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income or loss.

Basis Swap Contracts

In addition to the swaps and options above, at December 31, 2016, 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 December 2018 and include a total volume of 66,210,000 Mmbtu. The fair value of these contracts was a gain of $11.8 million on December 31, 2016.

At December 31, 2016, 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 1,637,500 barrels in 2017 and 750,000 barrels in 2018. The fair value of these contracts was a loss of $742,000 on December 31, 2016.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2016, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly beginning in fourth quarter 2017 through December 2018 and cover 5,000 metric tons per month with a fair value gain of $65,000 on December 31, 2016. These contracts use observable third-party pricing inputs that we consider to be Level 2 fair value classification.

Discontinuance of Hedge Accounting

Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values included in AOCI as of the de-designation date were frozen and were reclassified into earnings in natural gas, NGLs and oil sales in future periods as the underlying hedged transactions occurred. As of December 31, 2014, all frozen values have been reclassified to earnings.

For those derivative instruments that qualified for hedge accounting, settled transaction gains and losses were determined monthly and were included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged production was sold. Natural gas, NGLs and oil sales include $10.2 million of gains in 2014 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value in the accompanying consolidated statements of operations. The ineffective portion is calculated as the difference between the changes in fair value of the derivative and the estimated change in future cash flows from the item hedged.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2016 and 2015 is summarized below (in thousands). As of December 31, 2016, we are conducting derivative activities with twenty-two 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, 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	)

		December 31, 2015
		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	$	219,357	$	(10,245	)	$	209,112
	–natural gas basis swaps		8,251		(2,765	)		5,486
Crude oil	–swaps		38,699		—			38,699
NGLs	–C3 swaps		15,884		—			15,884
	–C3 propane spread swaps		2,497		(2,497	)		—
	–C4 swaps		6,968		—			6,968
	–C5 swaps		12,694		(81	)		12,613
		$	304,350	$	(15,588	)	$	288,762

		December 31, 2015
		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	$	(10,245	)	$	10,245	$	—
	–natural gas basis swaps		(2,786	)		2,765		(21	)
NGLs	–C3 propane spread swaps		(3,633	)		2,497		(1,136	)
	–C5 swaps		(81	)		81		—
		$	(16,745	)	$	15,588	$	(1,157	)

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)
	2016			2015		2014
Commodity Swaps	$	(265,466	)	$	398,020	$	367,484
Re-purchased swaps		—			851		—
Collars		(6,926	)		16,539		42,836
Basis swaps		29,154			954		(26,800	)
Puts		(18,201	)		—		—
Calls		(18	)		—		—
Freight swaps		66			—		—
Total	$	(261,391	)	$	416,364	$	383,520

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2016

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 that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair 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, 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

		Fair Value Measurements at December 31, 2015 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, 2015
Trading securities held in the deferred compensation plans		$	62,376	$	—	$	—	$	62,376
Derivatives	–swaps		—		283,276		—		283,276
	–basis swaps		—		4,329		—		4,329

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2016 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.

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, 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. For the year ended December 31, 2014, interest and dividends were $911,000 and mark-to-market was a loss of $2.4 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 2016 of $43.0 million related to our natural gas and oil properties in Western Oklahoma. We recorded non-cash charges during the year ended 2015 related to natural gas and oil properties in Northern Oklahoma of $306.6 million, $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 onshore Gulf Coast properties. We recorded non-cash charges during the year ended 2014 of $5.5 million related to natural gas and oil properties in Mississippi, $18.5 million related to properties in West Texas and $4.0 million to fully impair our remaining oil and natural gas properties in North Texas. 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,
	2016				2015				2014
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	90,150	$	43,040	$	152,230	$	590,174	$	15,605	$	28,024

Fair Values - Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2016 and 2015 (in thousands):

	December 31, 2016						December 31, 2015
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	13,483		$	13,483		$	288,762		$	288,762
Marketable securities ^(a)		61,717			61,717			62,376			62,376
(Liabilities):
Commodity swaps, options and basis swaps		(189,500	)		(189,500	)		(1,157	)		(1,157	)
Bank credit facility ^(b)		(882,000	)		(882,000	)		(95,000	)		(95,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(496,180	)		—			—
5.00% senior notes due 2022 ^(b)		(580,032	)		(577,132	)		—			—
5.875% senior notes due 2022 ^(b)		(329,244	)		(343,648	)		—			—
Other senior notes due 2022 ^(b)		(1,090	)		(1,104	)		—			—
5.00% senior notes due 2023 ^(b)		(741,514	)		(735,026	)		—			—
4.875% senior notes due 2025 ^(b)		(750,000	)		(724,688	)		(750,000	)		(572,813	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,325	)		(500,000	)		(396,250	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,387	)		(600,000	)		(447,000	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,645	)		(750,000	)		(551,250	)
Deferred compensation plan ^(c)		(139,580	)		(139,580	)		(122,918	)		(122,918	)

^(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.

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.

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-based Compensation Plans

12 Months Ended

Dec. 31, 2016

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 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.

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 Director Plan continue to be exercisable in accordance with their original terms and conditions.

Stock-Based Awards

In 2005, we began granting SARs to reduce the dilutive impact of our equity plans. SARs represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted. Beginning in 2011, we began granting restricted stock units under our equity-based stock compensation plan. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. 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. In 2014, we began granting PSU awards. The number of shares to be issued is determined by our total shareholder return compared to the total shareholder return of a predetermined group of peer companies over the performance period. The PSU awards vest at the end of the three-year performance period. The grant date fair value of the PSU awards is determined using a Monte Carlo simulation and is recognized as stock-based compensation expense over the three-year performance period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us.

The compensation committee also grants restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. 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 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.

Total Stock-Based Compensation Expense

Stock-based compensation expense represents amortization of restricted stock, PSUs and SARs grants. 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, 2016 (in thousands):

	2016		2015			2014
Direct operating expense	$	2,302		$	2,780		$	4,208
Brokered natural gas and marketing expense		1,725			2,132			3,523
Exploration expense		2,298			2,985			4,569
General and administrative expense		49,293			49,687			55,382
Termination costs		—			217			2,999
Total	$	55,618		$	57,801		$	70,681

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 and therefore, is not allocated to the functional categories and is reported as deferred compensation plan expense in the accompanying consolidated statements of operations. Stock-based compensation expense in the year ended December 31, 2014 includes $6.7 million of awards granted to our former executive chairman for his 2013 service while he was a Range officer, which were fully vested upon grant. 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 deduction was recorded as a reduction to additional paid-in capital. For the year ended December 31, 2014, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized due to our net operating loss position.

Performance Share Unit Awards

The following is a summary of our non-vested PSU award activities:

	Number of Units ^(a)			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		—			—
Granted		227,929		$	86.14
Vested ^(b)		(92,077	)		86.23
Forfeited		(1,511	)		82.60
Outstanding at December 31, 2014		134,341			86.11
Granted		276,204			56.78
Vested ^(c)		(143,094	)		68.73
Forfeited		(5,327	)		82.60
Outstanding at December 31, 2015		262,124			64.77
Granted		413,959			36.64
Vested ^(c)		(237,572	)		53.07
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		395,908		$	44.39

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

^(b) Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

^(c) Includes PSU awards of 19,684 that were modified and fully vested effective with the closing of our Oklahoma City Office and the sale of our Virginia and West Virginia assets.

The fair value of 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. 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, 2016, 2015 and 2014:

	Year Ended December 31, 2016
	2016			2015			2014
Risk-free interest rate		0.94	%		1.02	%		0.77	%
Expected annual volatility		49	%		33	%		33	%
Grant date fair value per unit	$	36.64		$	56.78		$	86.14

We recorded PSU compensation expense of $12.4 million in the year ended December 31, 2016 compared to $8.7 million in the year ended December 31, 2015 and $7.9 million in the year ended December 31, 2014. As of December 31, 2016, there was $16.2 million of unrecognized compensation related to PSU awards to be recognized over a weighted average period of 1.8 years.

Restricted Stock Awards

Equity Awards

In 2016, we granted 973,000 restricted stock Equity Awards to employees which generally vest over a three-year period compared to 588,000 in 2015 and 356,000 in 2014. We recorded compensation expense for these awards of $22.8 million in the year ended December 31, 2016 compared to $23.8 million in 2015 and $28.1 million in 2014. As of December 31, 2016, there was $24.7 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.8 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.

Liability Awards

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-employees 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. In 2014, we granted 272,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $87.34. This grant included 64,000 issued to non-employee directors, which vest immediately and 208,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $18.6 million in the year ended December 31, 2016 compared to $20.8 million in 2015 and $26.3 million in 2014. As of December 31, 2016, there was $17.7 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.8 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 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 $13.1 million in 2016 compared to $8.3 million in 2015 and $16.0 million in 2014. The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2016:

	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		385,063		$	68.24		389,013		$	71.02
Granted		356,194			84.87		272,052			87.34
Vested		(354,237	)		72.85		(356,413	)		75.52
Forfeited		(26,605	)		75.66		(148	)		77.35
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

Stock Appreciation Right Awards

During 2014, we granted SARs to our former executive chairman in conjunction with his retirement from Range as an employee. Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2013		2,582,074		$	56.36
Granted		1,104			81.74
Exercised		(616,563	)		45.45
Expired/forfeited		(66	)		46.44
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
Exercised		—			—
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600		$	69.08

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2016:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 40.00–$ 49.99		10,108		0.04	$	49.18		10,108	$	49.18
50.00–59.99		—		—		—		—		—
60.00–69.99		578,064		0.36		64.23		578,064		64.23
70.00–79.99		413,528		1.28		76.29		413,528		76.29
80.00–81.15		1,900		1.69		81.15		1,900		81.15
Total		1,003,600		0.74	$	69.08		1,003,600	$	69.08

The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:

	2014
Weighted average exercise price per share	$	81.74
Expected annual dividend yield		0.20	%
Expected life in years		4.3
Expected volatility		33	%
Risk-free interest rate		1.4	%
Weighted average grant date fair value per share	$	23.17

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 compared to $27.1 million in 2014. There were no SARs exercised in 2016. As of December 31, 2016, 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, 2016, the number of fully vested awards and the awards expected to vest was 1.0 million shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $69.08 and 0.7 years. As of December 31, 2016, 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 2016, we contributed $4.7 million to the 401(k) Plan compared to $6.1 million in 2015 and $5.8 million in 2014. 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 loss of $19.2 million in 2016 compared to a gain of $77.6 million in 2015 and a gain of $74.6 million in 2014. The Rabbi Trust held 2.7 million shares (2.3 million of vested shares) of Range stock at December 31, 2016 compared to 2.8 million (2.5 million of vested shares) at December 31, 2015.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information

(14)	Supplemental Cash Flow Information

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(102	)	$	100		$	(156	)
Interest paid		159,875			168,826			165,530
Non-cash investing and financing activities included ^(a):
Asset retirement costs capitalized, net	$	(24,064	)	$	22,184		$	56,822
Increase (decrease) in accrued capital expenditures		61,419			(225,455	)		150,604

^(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, 2016

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 $14.0 million in 2016 compared to $15.9 million in 2015 and $13.3 million in 2014. 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
2017	$	18,407
2018		16,126
2019		13,498
2020		13,088
2021		12,076
Thereafter		40,892
	$	114,087

Transportation and Gathering 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 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 liability of $59.2 million for certain expected volume deficiency payments related to our properties in North Louisiana. As of December 31, 2016, future minimum transportation and gathering fees under our commitments are as follows (in thousands):

	Transportation and Gathering Contracts ^(a)
2017	$	705,243
2018		699,863
2019		699,254
2020		635,379
2021		606,797
Thereafter		3,326,015
	$	6,672,551

^(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 additional agreements which are contingent on certain pipeline and gathering line modifications and/or construction. These agreements range between fifteen and twenty year terms and may begin in 2017. Based on these contracts, we will have additional transportation obligations for natural gas volumes of 1,300,000 mcf per day through 2032 decreasing to 400,000 mcf per day until 2037. We also have gathering obligations which begin in 2017 of up to 400,000 mcf per day through 2032.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Marcellus Shale, Oklahoma 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, 2016, our delivery commitments through 2030 were as follows:

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2017		122,578	68,000
2018		170,390	68,000
2019		138,487	52,932
2020		94,111	48,132
2021		66,189	48,000
2022		27,068	43,000
2023—2028		—	35,000
2029—2030		—	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 10,000 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 50,000 mcf per day starting in late 2017, increasing to 65,000 mcf per day in late 2018 and 215,000 mcf per day in early 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 to 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.

Equity Method Investments

12 Months Ended

Dec. 31, 2016

Equity Method Investments And Joint Ventures [Abstract]

Equity Method Investments

(16)	Equity Method Investments

We accounted for our investments in entities over which we had significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, we recorded our proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. We also evaluated our equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other than temporary decline in value of the investment. Such events include sustained operating losses by the investee or long-term negative changes in the investee’s industry. As of June 2014, we no longer have equity method investments.

Office Closing and Exit Costs

12 Months Ended

Dec. 31, 2016

Restructuring And Related Activities [Abstract]

Office Closing and Exit Costs

(17)	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 was probable of occurring. In early 2015, those plans and personnel involved 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 addition, the year ended December 31, 2015 includes 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. The following table details the accrued liability as of December 31, 2016 and December 31, 2015 (in thousands):

		2016			2015
Beginning balance	$	11,630		$	5,372
Accrued severance costs		(822	)		11,706
Accrued building rent		303			3,147
Payments		(8,651	)		(8,595	)
Ending balance	$	2,460		$	11,630

The following summarizes our termination costs for three years ended December 31, 2016, 2015 and 2014 (in thousands):

		2016			2015		2014
Severance costs	$	(822	)	$	11,706	$	5,372
Building lease		303			3,147		—
Stock-based compensation		—			217		2,999
Total termination costs	$	(519	)	$	15,070	$	8,371

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data (Unaudited)

(18)	Selected Quarterly Financial Data (Unaudited)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. The adoption of ASU 2016-09 affected our previously reported first quarter 2016 results. For additional information see Note 2. 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. Fourth quarter 2015 includes a loss of $407.7 million from the sale of our Virginia and West Virginia oil and gas properties and impairment expense of $87.9 million related to oil and gas properties in the Texas Panhandle and South Texas. Third quarter 2015 includes impairment expense of $502.2 million related to our Northern Oklahoma and legacy shallow Northwest Pennsylvania assets (in thousands, except per share data):

	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 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
Loss on early extinguishment of debt		—			—			—			—			—
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) income 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) income	$	(93,772	)	$	(224,936	)	$	(41,971	)	$	(160,709	)	$	(521,388	)
Net (loss) income 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	)

	2015
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	325,483		$	258,053		$	252,065		$	254,043		$	1,089,644
Derivative fair value income (loss)		122,839			(34,791	)		202,004			126,312			416,364
Brokered natural gas, marketing and other		14,485			21,339			25,864			30,372			92,060
Total revenue and other income		462,807			244,601			479,933			410,727			1,598,068
Costs and expenses:
Direct operating		37,137			34,780			35,058			29,388			136,363
Transportation, gathering and compression		89,426			95,198			99,634			112,481			396,739
Production and ad valorem taxes		9,928			9,242			7,336			7,354			33,860
Brokered natural gas and marketing		21,562			27,031			32,331			34,942			115,866
Exploration		7,886			5,025			4,235			4,260			21,406
Abandonment and impairment of unproved properties		11,491			12,330			12,366			11,432			47,619
General and administrative		48,329			55,964			46,178			43,544			194,015
Termination costs		5,950			417			(77	)		8,780			15,070
Deferred compensation plan		(5,624	)		(7,282	)		(43,705	)		(21,016	)		(77,627	)
Interest		39,207			43,479			42,904			40,849			166,439
Loss on early extinguishment of debt		—			—			22,495			—			22,495
Depletion, depreciation and amortization		147,290			151,895			153,993			127,977			581,155
Impairment of proved properties and other		—			—			502,233			87,941			590,174
Loss (gain) on sale of assets		175			(2,909	)		681			408,909			406,856
Total costs and expenses		412,757			425,170			915,662			896,841			2,650,430

Income (loss) before income taxes		50,050			(180,569	)		(435,729	)		(486,114	)		(1,052,362	)
Income tax expense (benefit):
Current		—			—			—			29			29
Deferred		22,366			(61,975	)		(134,781	)		(164,316	)		(338,706	)
		22,366			(61,975	)		(134,781	)		(164,287	)		(338,677	)
Net income (loss)	$	27,684		$	(118,594	)	$	(300,948	)	$	(321,827	)	$	(713,685	)
Net income (loss) per common share:
Basic	$	0.16		$	(0.71	)	$	(1.81	)	$	(1.93	)	$	(4.29	)
Diluted	$	0.16		$	(0.71	)	$	(1.81	)	$	(1.93	)	$	(4.29	)

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

12 Months Ended

Dec. 31, 2016

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

(19)	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,
	2016			2015			2014
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,462,350		$	8,047,181		$	9,624,725
Unproved properties		2,923,803			949,155			943,246
Total		12,386,153			8,996,336			10,567,971
Accumulated depreciation, depletion and amortization		(3,129,816	)		(2,635,031	)		(2,590,398	)
Net capitalized costs	$	9,256,337		$	6,361,305		$	7,977,573

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

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

	December 31,
	2016			2015		2014
	(in thousands)
Acquisitions ^(b)
Acreage purchases	$	33,142		$	73,025	$	226,475
Oil and gas properties		3,098,772			—		392,325
Asset retirement obligations and other		21,908			—		11,927
Development		497,795			708,268		1,119,896
Exploration:
Drilling		37,680			87,505		180,925
Expense		30,027			18,421		58,979
Stock-based compensation expense		2,298			2,985		4,569
Gas gathering facilities:
Development		3,595			13,337		13,137
Subtotal		3,725,217			903,541		2,008,233
Asset retirement obligations		(24,064	)		22,184		56,822
Total costs incurred	$	3,701,153		$	925,725	$	2,065,055

^(a)

Includes cost incurred whether capitalized or expensed.

^(b)

See also Note 3 for additional information related to the 2014 Conger Exchange which includes $134.8 million of gas gathering assets received in the exchange.

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.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2016, 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, 2016, our consultants collectively audited approximately 96% 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.

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, 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. The average realized prices used at December 31, 2014 to estimate reserve information were $79.04 per barrel of oil, $27.20 per barrel of NGLs and $4.14 per mcf for gas, using a benchmark (NYMEX) of $94.42 per barrel and $4.35 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, 2013		5,665,645			374,412			48,360			8,202,274
Revisions		(30,566	)		19,716			515			90,822
Extensions, discoveries and additions		1,393,108			154,664			12,936			2,398,709
Purchases		262,813			—			—			262,813
Property sales		(81,238	)		(14,064	)		(9,083	)		(220,122	)
Production		(286,926	)		(18,821	)		(4,070	)		(424,267	)
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
Purchases		—			—			—			—
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
Proved developed reserves:
December 31, 2014		3,583,051			270,271			24,180			5,349,761
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
Proved undeveloped reserves:
December 31, 2014		3,339,785			245,636			24,478			4,960,468
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

^(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 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 reflects 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.

During 2014, we added approximately 2.4 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 58% of 2014 reserve additions were attributable to natural gas. Included in 2014 proved reserves is a total of 1,170 Bcfe of ethane reserves (264.3 Mmbbls) in the Marcellus Shale. Revisions of previous estimates of a positive 91 Bcfe includes positive performance revisions, improved recoveries of 449.6 Bcfe primarily from our Marcellus Shale natural gas properties and positive price revisions are somewhat offset by reserves of 611 Bcfe reclassified to unproved as we continue to see success from drilling longer laterals, increasing the number of frac stages and better lateral targeting which caused some previously planned wells to not be drilled within the original five-year development horizon.

The following details the changes in proved undeveloped reserves for 2016 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2015	4,469,588
Undeveloped reserves transferred to developed	(1,065,262	)
Revisions^(a)	145,204
Purchases/(sales)	503,192
Extension and discoveries	1,249,692
Ending proved undeveloped reserves at December 31, 2016	5,302,414

^(a) Includes 269 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 $245.6 million was spent during 2016 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $877.9 million in 2017, $516.6 million in 2018 and $607.7 million in 2019. As of December 31, 2016, we have 50 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 proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2021.

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 2016, 2015 and 2014, 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,
	2016			2015
	(in thousands)
Future cash inflows	$	27,413,864		$	21,290,873
Future costs:
Production		(14,465,059	)		(10,411,360	)
Development^(a)		(2,647,801	)		(2,213,582	)
Future net cash flows before income taxes		10,301,004			8,665,931
Future income tax expense		(1,946,259	)		(2,007,794	)
Total future net cash flows before 10% discount		8,354,745			6,658,137
10% annual discount		(4,902,816	)		(3,932,274	)
Standardized measure of discounted future net cash flows	$	3,451,929		$	2,725,863

^(a) 2016 includes $405.3 million of undiscounted future asset retirement costs estimated as of December 31, 2016, using current estimates of future abandonment costs.

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

	December 31,
	2016			2015			2014
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	(212,867	)	$	(7,231,629	)	$	5,069
Revisions in quantities		96,615			(868,886	)		102,760
Changes in future development and abandonment costs		(314,864	)		359,540			(407,688	)
Net change in income taxes		27,842			2,173,904			(441,935	)
Accretion of discount		302,920			1,007,027			789,754
Purchases of reserves in place		488,959			—			297,358
Additions to proved reserves from extensions, discoveries and improved recovery		541,095			486,478			2,713,999
Natural gas, NGLs and oil sales, net of production costs		(509,174	)		(522,682	)		(1,391,663	)
Development costs incurred during the period		435,928			1,033,539			755,384
Sales of reserves in place		(65,538	)		(1,050,237	)		(249,055	)
Timing and other		(64,850	)		(254,218	)		(443,187	)
Net change for the year		726,066			(4,867,164	)		1,730,796
Beginning of year		2,725,863			7,593,027			5,862,231
End of year	$	3,451,929		$	2,725,863		$	7,593,027

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

Use of Estimates

Reclassifications

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

Accumulated Other Comprehensive Income

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2013		10,222			(3,986	)		6,236
Contract settlements reclassified to income		(10,222	)		3,986			(6,236	)
Accumulated other comprehensive income at December 31, 2014	$	—		$	—		$	—

Recently Adopted

New Accounting Pronouncements

Recently Adopted

		For The Three Months Ended March 31, 2016
		As Reported			As Adjusted
	(unaudited)
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
Year ended 2012		647,099		658,069
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
Year ended 2012		881,619			870,649
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, 2016

Accounting Policies [Abstract]

Accumulated Other Comprehensive Income

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2013		10,222			(3,986	)		6,236
Contract settlements reclassified to income		(10,222	)		3,986			(6,236	)
Accumulated other comprehensive income at December 31, 2014	$	—		$	—		$	—

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

		For The Three Months Ended March 31, 2016
		As Reported			As Adjusted
	(unaudited)
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
Year ended 2012		647,099		658,069
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
Year ended 2012		881,619			870,649
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, 2016

Business Combinations [Abstract]

Summary of Preliminary Purchase Price Allocation

The following table sets forth our preliminary purchase price allocation (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		114,426
Long-term debt		1,204,449
Deferred taxes		547,348
Other long-term liabilities		77,223
Total purchase price plus liabilities assumed	$	5,032,243

Fair value of Memorial assets:
Cash and equivalents	$	7,180
Other current assets		97,875
Derivative instruments		152,994
Natural gas and oil properties:
Proved property		1,117,011
Unproved property		1,999,187
Other property and equipment		3,579
Goodwill ^(a)		1,654,292
Other		125
Total asset value	$	5,032,243

^(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	$	(590,777	)	$	(555,793	)

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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax


	Year Ended December 31,
	2016		2015			2014
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
State	3.0			4.3			3.1
State apportionment rate change	1.0			(0.2	)		(0.2	)
Non-deductible executive compensation	(0.2	)		(0.1	)		0.2
Non-deductible MRD transaction costs	(0.6	)		—			—
Valuation allowances	(2.5	)		(6.8	)		0.2
Deficits in equity compensation	(0.7	)		—			—
Other	—			—			0.2
Consolidated effective tax rate	35.0	%		32.2	%		38.5	%

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):

		2016								2015										2014
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred		Total
U.S. federal	$	—	$	(266,105	)	$	(266,105	)	$	—	$	(328,257	)		$	(328,257	)		$		—	$		361,152		$	361,152
U.S. state and local		98		(14,743	)		(14,645	)		29		(10,449	)			(10,420	)				1			35,350			35,351
Total	$	98	$	(280,848	)	$	(280,750	)	$	29	$	(338,706	)		$	(338,677	)		$		1	$		396,502		$	396,503

Significant Components of Deferred Tax Assets and Liabilities

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

	December 31,
	2016			2015
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	478,203		$	173,503
Deferred compensation		50,808			45,413
Equity compensation		29,528			25,940
AMT credits and other credits		13,644			4,437
Asset retirement obligation		99,000			101,142
Cumulative mark-to-market loss		73,404			—
Other		39,922			10,163
Valuation allowances:
Federal		(43,600	)		(42,500	)
State, net of federal benefit		(58,424	)		(41,516	)
Deferred compensation plans and other		(5,150	)		(3,607	)
Total deferred tax assets		677,335			272,975
Deferred tax liabilities:
Depreciation, depletion and investments		(1,619,922	)		(940,482	)
Cumulative mark-to-market gain		—			(109,845	)
Other		(756	)		(595	)
Total deferred tax liabilities		(1,620,678	)		(1,050,922	)
Net deferred tax liability	$	(943,343	)	$	(777,947	)

Change in Deferred Tax Asset Valuation Allowances

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

		2016			2015			2014
Balance at the beginning of the year	$	(87,623	)	$	(16,599	)	$	(14,781	)
Charged to provision for income taxes:
State net operating loss carryforwards		(17,374	)		(30,457	)		(5,800	)
Federal net operating carryforwards		(1,100	)		(42,500	)		—
Other state valuation allowances		500			(1,050	)		—
Other federal valuation allowances		(477	)		(511	)		363
Rabbi trust valuation allowance		(1,066	)		3,494			3,619
Other		(34	)		—			—
Balance at the end of the year	$	(107,174	)	$	(87,623	)	$	(16,599	)

Net (Loss) Income Per Common Share (Tables)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

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


	Year Ended December 31,
	2016			2015			2014
Net (loss) income, as reported	$	(521,388	)	$	(713,685	)	$	634,382
Participating basic earnings ^(a)		(223	)		(450	)		(10,725	)
Basic net (loss) income attributed to common stockholders		(521,611	)		(714,135	)		623,657
Reallocation of participating earnings ^(a)		—			—			48
Diluted net (loss) income attributed to common stockholders	$	(521,611	)	$	(714,135	)	$	623,705
Net (loss) income per common share:
Basic	$	(2.75	)	$	(4.29	)	$	3.81
Diluted	$	(2.75	)	$	(4.29	)	$	3.79

^(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,
	2016	2015		2014
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	189,868		166,389		163,625
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	—		—		778
Weighted average common shares outstanding – diluted	189,868		166,389		164,403

⁽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, 2016

Suspended Exploratory Well Costs

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2016, 2015 and 2014 (in thousands, except for number of projects):

	2016			2015			2014
Balance at beginning of period	$	4,161		$	2,996		$	6,964
Additions to capitalized exploratory well costs pending the determination of proved reserves		9,128			1,165			18,747
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(5,877	)		—			(15,735	)
Capitalized exploratory well costs charged to expense		—			—			(6,980	)
Balance at end of period		7,412			4,161			2,996
Less exploratory well costs that have been capitalized for a period of one year or less		(7,412	)		(1,165	)		(2,996	)
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, 2016

Debt Disclosure [Abstract]

Debt Outstanding


		December 31, 2016			December 31, 2015
Bank debt (2.4%) ^(a)	$	882,000		$	95,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,514			—
5.00% senior notes due 2022		580,032			—
5.75% senior notes due 2021		475,952			—
5.875% senior notes due 2022 ^(b)		329,244			—
Other senior notes due 2022 ^(c)		1,090			—
Total senior notes		2,877,832			750,000
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			750,000
5.00% senior subordinated notes due 2022		19,054			600,000
5.75% senior subordinated notes due 2021		22,214			500,000
Total senior subordinated notes		48,980			1,850,000
Total debt		3,808,812			2,695,000
Unamortized premium		7,258			—
Unamortized debt issuance costs		(42,553	)		(43,697	)
Total debt net of debt issuance costs	$	3,773,517		$	2,651,303

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	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%

Schedule for Long-Term Debt Outstanding

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2016 (in thousands):

	Year Ended December 31,
2017	$	—
2018		—
2019		882,000
2020		—
2021		498,166
Thereafter		2,428,646
	$	3,808,812

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.

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Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation

The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2016 and 2015 (in thousands):


	2016			2015
Beginning of period	$	264,137		$	287,463
Liabilities incurred		2,694			4,595
Acquisitions		21,900			1,584
Liabilities settled		(11,511	)		(18,828	)
Disposition of wells		(10,540	)		(45,845	)
Accretion expense		18,021			19,163
Change in estimate		(26,758	)		16,005
End of period		257,943			264,137
Less current portion		(7,271	)		(15,071	)
Long-term asset retirement obligations	$	250,672		$	249,066

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Capital Stock

The following is a schedule of changes in the number of common shares outstanding since the beginning of 2014:


	Year Ended December 31,
	2016			2015		2014
Beginning balance		169,316,460			168,628,177		163,342,894
MRD Merger		77,042,749			—		—
Equity offering		—			—		4,560,000
Stock options/SARs exercised		—			77,002		195,242
Restricted stock grants		490,609			335,103		270,062
Restricted stock units vested		266,541			252,507		244,413
Shares retired		(739	)		—		—
Treasury shares		28,736			23,671		15,566
Ending balance		247,144,356			169,316,460		168,628,177

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2017	Swaps ⁽¹⁾	840,692 Mmbtu/day	$ 3.19
2018	Swaps	276,712 Mmbtu/day	$ 3.12
2017	Collar ⁽¹⁾	42,750 Mmbtu/day	$ 3.48-$ 4.15
2017	Purchased Put ⁽¹⁾	175,890 Mmbtu/day	$ 3.48 ⁽²⁾
2017	Sold Call	9,041 Mmbtu/day	$ 3.75 ⁽³⁾

Crude Oil
2017	Swaps ⁽¹⁾	8,542 bbls/day	$ 55.77
2018	Swaps	2,750 bbls/day	$ 54.24

NGLs (C2-Ethane)
2017	Swaps	3,000 bbls/day	$ 0.27/gallon

NGLs (C3-Propane)
2017	Swaps	11,610 bbls/day	$ 0.55/gallon
2018	Swaps	5,699 bbls/day	$ 0.65/gallon

NGLs (NC4-Normal Butane)
2017	Swaps	7,000 bbls/day	$ 0.73/gallon
2018	Swaps	2,000 bbls/day	$ 0.78/gallon

NGLs (C5-Natural Gasoline)
2017	Swaps	5,250 bbls/day	$ 1.06/gallon
2018	Swaps	1,000 bbls/day	$ 1.18/gallon

⁽¹⁾ Includes derivative instruments assumed in connection with the MRD Merger.

⁽²⁾Weighted average deferred premium is ($0.32).

⁽³⁾ Weighted average deferred premium is $0.31.

Combined Fair Value of Derivatives, by Consolidated Balance Sheets

		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	)

		December 31, 2015
		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	$	219,357	$	(10,245	)	$	209,112
	–natural gas basis swaps		8,251		(2,765	)		5,486
Crude oil	–swaps		38,699		—			38,699
NGLs	–C3 swaps		15,884		—			15,884
	–C3 propane spread swaps		2,497		(2,497	)		—
	–C4 swaps		6,968		—			6,968
	–C5 swaps		12,694		(81	)		12,613
		$	304,350	$	(15,588	)	$	288,762

		December 31, 2015
		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	$	(10,245	)	$	10,245	$	—
	–natural gas basis swaps		(2,786	)		2,765		(21	)
NGLs	–C3 propane spread swaps		(3,633	)		2,497		(1,136	)
	–C5 swaps		(81	)		81		—
		$	(16,745	)	$	15,588	$	(1,157	)

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)
	2016			2015		2014
Commodity Swaps	$	(265,466	)	$	398,020	$	367,484
Re-purchased swaps		—			851		—
Collars		(6,926	)		16,539		42,836
Basis swaps		29,154			954		(26,800	)
Puts		(18,201	)		—		—
Calls		(18	)		—		—
Freight swaps		66			—		—
Total	$	(261,391	)	$	416,364	$	383,520

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.

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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

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

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

		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

		Fair Value Measurements at December 31, 2015 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, 2015
Trading securities held in the deferred compensation plans		$	62,376	$	—	$	—	$	62,376
Derivatives	–swaps		—		283,276		—		283,276
	–basis swaps		—		4,329		—		4,329

Value of Assets Measured at Fair Value on Non Recurring 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,
	2016				2015				2014
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	90,150	$	43,040	$	152,230	$	590,174	$	15,605	$	28,024

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, 2016 and 2015 (in thousands):

	December 31, 2016						December 31, 2015
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	13,483		$	13,483		$	288,762		$	288,762
Marketable securities ^(a)		61,717			61,717			62,376			62,376
(Liabilities):
Commodity swaps, options and basis swaps		(189,500	)		(189,500	)		(1,157	)		(1,157	)
Bank credit facility ^(b)		(882,000	)		(882,000	)		(95,000	)		(95,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(496,180	)		—			—
5.00% senior notes due 2022 ^(b)		(580,032	)		(577,132	)		—			—
5.875% senior notes due 2022 ^(b)		(329,244	)		(343,648	)		—			—
Other senior notes due 2022 ^(b)		(1,090	)		(1,104	)		—			—
5.00% senior notes due 2023 ^(b)		(741,514	)		(735,026	)		—			—
4.875% senior notes due 2025 ^(b)		(750,000	)		(724,688	)		(750,000	)		(572,813	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,325	)		(500,000	)		(396,250	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,387	)		(600,000	)		(447,000	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,645	)		(750,000	)		(551,250	)
Deferred compensation plan ^(c)		(139,580	)		(139,580	)		(122,918	)		(122,918	)

^(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, 2016

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

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, 2016 (in thousands):

	2016		2015			2014
Direct operating expense	$	2,302		$	2,780		$	4,208
Brokered natural gas and marketing expense		1,725			2,132			3,523
Exploration expense		2,298			2,985			4,569
General and administrative expense		49,293			49,687			55,382
Termination costs		—			217			2,999
Total	$	55,618		$	57,801		$	70,681

Summary of Performance Share Unit Awards Activities

The following is a summary of our non-vested PSU award activities:

	Number of Units ^(a)			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		—			—
Granted		227,929		$	86.14
Vested ^(b)		(92,077	)		86.23
Forfeited		(1,511	)		82.60
Outstanding at December 31, 2014		134,341			86.11
Granted		276,204			56.78
Vested ^(c)		(143,094	)		68.73
Forfeited		(5,327	)		82.60
Outstanding at December 31, 2015		262,124			64.77
Granted		413,959			36.64
Vested ^(c)		(237,572	)		53.07
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		395,908		$	44.39

^(b) Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

^(c) Includes PSU awards of 19,684 that were modified and fully vested effective with the closing of our Oklahoma City Office and the sale of our Virginia and West Virginia assets.

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, 2016, 2015 and 2014:

	Year Ended December 31, 2016
	2016			2015			2014
Risk-free interest rate		0.94	%		1.02	%		0.77	%
Expected annual volatility		49	%		33	%		33	%
Grant date fair value per unit	$	36.64		$	56.78		$	86.14

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, 2016:

	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		385,063		$	68.24		389,013		$	71.02
Granted		356,194			84.87		272,052			87.34
Vested		(354,237	)		72.85		(356,413	)		75.52
Forfeited		(26,605	)		75.66		(148	)		77.35
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

Stock Option and SARs Activities

Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2013		2,582,074		$	56.36
Granted		1,104			81.74
Exercised		(616,563	)		45.45
Expired/forfeited		(66	)		46.44
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
Exercised		—			—
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600		$	69.08

Summary of SARs Outstanding and Exercisable

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2016:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 40.00–$ 49.99		10,108		0.04	$	49.18		10,108	$	49.18
50.00–59.99		—		—		—		—		—
60.00–69.99		578,064		0.36		64.23		578,064		64.23
70.00–79.99		413,528		1.28		76.29		413,528		76.29
80.00–81.15		1,900		1.69		81.15		1,900		81.15
Total		1,003,600		0.74	$	69.08		1,003,600	$	69.08

Weighted Average Grant Date Fair Value of SARs

The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:

	2014
Weighted average exercise price per share	$	81.74
Expected annual dividend yield		0.20	%
Expected life in years		4.3
Expected volatility		33	%
Risk-free interest rate		1.4	%
Weighted average grant date fair value per share	$	23.17

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

	Year Ended December 31,
	2016			2015			2014
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(102	)	$	100		$	(156	)
Interest paid		159,875			168,826			165,530
Non-cash investing and financing activities included ^(a):
Asset retirement costs capitalized, net	$	(24,064	)	$	22,184		$	56,822
Increase (decrease) in accrued capital expenditures		61,419			(225,455	)		150,604

^(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, 2016

Commitments And Contingencies Disclosure [Abstract]

Future Minimum Rental Commitments

	Operating Lease Obligations
2017	$	18,407
2018		16,126
2019		13,498
2020		13,088
2021		12,076
Thereafter		40,892
	$	114,087

Schedule of Future Minimum Transportation and Gathering Fees

	Transportation and Gathering Contracts ^(a)
2017	$	705,243
2018		699,863
2019		699,254
2020		635,379
2021		606,797
Thereafter		3,326,015
	$	6,672,551

Future Delivery Commitments

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2017		122,578	68,000
2018		170,390	68,000
2019		138,487	52,932
2020		94,111	48,132
2021		66,189	48,000
2022		27,068	43,000
2023—2028		—	35,000
2029—2030		—	20,000

Tabular disclosure of a lessee's leasing arrangements including: (1) the basis on which contingent rental payments are determined, (2) the existence and terms of renewal or purchase options and escalation clauses, (3) restrictions imposed by lease arrangements, such as those concerning dividends, additional debt, and further leasing, (4) rent holidays, rent concessions, or leasehold improvement incentives and unusual provisions or conditions. Disclosure may also include the specific period used to amortize material leasehold improvements made at the inception of the lease or during the lease term. Additionally, for operating leases having initial or remaining noncancelable lease terms in excess of one year: (a) future minimum rental payments required as of the date of the latest balance sheet presented, in the aggregate and for each of the five succeeding fiscal years, (b) the total of minimum rentals to be received in the future under noncancelable subleases as of the date of the latest balance sheet presented, and (c) for all operating leases, rental expense for each period for which an income statement is presented, with separate amounts for minimum rentals, contingent rentals, and sublease rentals. Rental payments under leases with terms of a month or less that were not renewed need not be included.

Restructuring And Related Activities [Abstract]

Office Closing and Exit Costs (Tables)

12 Months Ended

Dec. 31, 2016

Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet

The following table details the accrued liability as of December 31, 2016 and December 31, 2015 (in thousands):

		2016			2015
Beginning balance	$	11,630		$	5,372
Accrued severance costs		(822	)		11,706
Accrued building rent		303			3,147
Payments		(8,651	)		(8,595	)
Ending balance	$	2,460		$	11,630

Summary of Termination Costs

The following summarizes our termination costs for three years ended December 31, 2016, 2015 and 2014 (in thousands):

		2016			2015		2014
Severance costs	$	(822	)	$	11,706	$	5,372
Building lease		303			3,147		—
Stock-based compensation		—			217		2,999
Total termination costs	$	(519	)	$	15,070	$	8,371

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

	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 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
Loss on early extinguishment of debt		—			—			—			—			—
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) income 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) income	$	(93,772	)	$	(224,936	)	$	(41,971	)	$	(160,709	)	$	(521,388	)
Net (loss) income 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	)

	2015
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	325,483		$	258,053		$	252,065		$	254,043		$	1,089,644
Derivative fair value income (loss)		122,839			(34,791	)		202,004			126,312			416,364
Brokered natural gas, marketing and other		14,485			21,339			25,864			30,372			92,060
Total revenue and other income		462,807			244,601			479,933			410,727			1,598,068
Costs and expenses:
Direct operating		37,137			34,780			35,058			29,388			136,363
Transportation, gathering and compression		89,426			95,198			99,634			112,481			396,739
Production and ad valorem taxes		9,928			9,242			7,336			7,354			33,860
Brokered natural gas and marketing		21,562			27,031			32,331			34,942			115,866
Exploration		7,886			5,025			4,235			4,260			21,406
Abandonment and impairment of unproved properties		11,491			12,330			12,366			11,432			47,619
General and administrative		48,329			55,964			46,178			43,544			194,015
Termination costs		5,950			417			(77	)		8,780			15,070
Deferred compensation plan		(5,624	)		(7,282	)		(43,705	)		(21,016	)		(77,627	)
Interest		39,207			43,479			42,904			40,849			166,439
Loss on early extinguishment of debt		—			—			22,495			—			22,495
Depletion, depreciation and amortization		147,290			151,895			153,993			127,977			581,155
Impairment of proved properties and other		—			—			502,233			87,941			590,174
Loss (gain) on sale of assets		175			(2,909	)		681			408,909			406,856
Total costs and expenses		412,757			425,170			915,662			896,841			2,650,430

Income (loss) before income taxes		50,050			(180,569	)		(435,729	)		(486,114	)		(1,052,362	)
Income tax expense (benefit):
Current		—			—			—			29			29
Deferred		22,366			(61,975	)		(134,781	)		(164,316	)		(338,706	)
		22,366			(61,975	)		(134,781	)		(164,287	)		(338,677	)
Net income (loss)	$	27,684		$	(118,594	)	$	(300,948	)	$	(321,827	)	$	(713,685	)
Net income (loss) per common share:
Basic	$	0.16		$	(0.71	)	$	(1.81	)	$	(1.93	)	$	(4.29	)
Diluted	$	0.16		$	(0.71	)	$	(1.81	)	$	(1.93	)	$	(4.29	)

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

12 Months Ended

Dec. 31, 2016

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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

	December 31,
	2016			2015			2014
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,462,350		$	8,047,181		$	9,624,725
Unproved properties		2,923,803			949,155			943,246
Total		12,386,153			8,996,336			10,567,971
Accumulated depreciation, depletion and amortization		(3,129,816	)		(2,635,031	)		(2,590,398	)
Net capitalized costs	$	9,256,337		$	6,361,305		$	7,977,573

^(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,
	2016			2015		2014
	(in thousands)
Acquisitions ^(b)
Acreage purchases	$	33,142		$	73,025	$	226,475
Oil and gas properties		3,098,772			—		392,325
Asset retirement obligations and other		21,908			—		11,927
Development		497,795			708,268		1,119,896
Exploration:
Drilling		37,680			87,505		180,925
Expense		30,027			18,421		58,979
Stock-based compensation expense		2,298			2,985		4,569
Gas gathering facilities:
Development		3,595			13,337		13,137
Subtotal		3,725,217			903,541		2,008,233
Asset retirement obligations		(24,064	)		22,184		56,822
Total costs incurred	$	3,701,153		$	925,725	$	2,065,055

^(a)

Includes cost incurred whether capitalized or expensed.

^(b)

See also Note 3 for additional information related to the 2014 Conger Exchange which includes $134.8 million of gas gathering assets received in the exchange.

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, 2013		5,665,645			374,412			48,360			8,202,274
Revisions		(30,566	)		19,716			515			90,822
Extensions, discoveries and additions		1,393,108			154,664			12,936			2,398,709
Purchases		262,813			—			—			262,813
Property sales		(81,238	)		(14,064	)		(9,083	)		(220,122	)
Production		(286,926	)		(18,821	)		(4,070	)		(424,267	)
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
Purchases		—			—			—			—
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
Proved developed reserves:
December 31, 2014		3,583,051			270,271			24,180			5,349,761
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
Proved undeveloped reserves:
December 31, 2014		3,339,785			245,636			24,478			4,960,468
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

^(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 2016 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2015	4,469,588
Undeveloped reserves transferred to developed	(1,065,262	)
Revisions^(a)	145,204
Purchases/(sales)	503,192
Extension and discoveries	1,249,692
Ending proved undeveloped reserves at December 31, 2016	5,302,414

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2016			2015
	(in thousands)
Future cash inflows	$	27,413,864		$	21,290,873
Future costs:
Production		(14,465,059	)		(10,411,360	)
Development^(a)		(2,647,801	)		(2,213,582	)
Future net cash flows before income taxes		10,301,004			8,665,931
Future income tax expense		(1,946,259	)		(2,007,794	)
Total future net cash flows before 10% discount		8,354,745			6,658,137
10% annual discount		(4,902,816	)		(3,932,274	)
Standardized measure of discounted future net cash flows	$	3,451,929		$	2,725,863

^(a) 2016 includes $405.3 million of undiscounted future asset retirement costs estimated as of December 31, 2016, 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,
	2016			2015			2014
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	(212,867	)	$	(7,231,629	)	$	5,069
Revisions in quantities		96,615			(868,886	)		102,760
Changes in future development and abandonment costs		(314,864	)		359,540			(407,688	)
Net change in income taxes		27,842			2,173,904			(441,935	)
Accretion of discount		302,920			1,007,027			789,754
Purchases of reserves in place		488,959			—			297,358
Additions to proved reserves from extensions, discoveries and improved recovery		541,095			486,478			2,713,999
Natural gas, NGLs and oil sales, net of production costs		(509,174	)		(522,682	)		(1,391,663	)
Development costs incurred during the period		435,928			1,033,539			755,384
Sales of reserves in place		(65,538	)		(1,050,237	)		(249,055	)
Timing and other		(64,850	)		(254,218	)		(443,187	)
Net change for the year		726,066			(4,867,164	)		1,730,796
Beginning of year		2,725,863			7,593,027			5,862,231
End of year	$	3,451,929		$	2,725,863		$	7,593,027

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.

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.

Summary Of Significant Accounting Policies [Line Items]

Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) Segment	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (loss)	$ (2,800)	$ (2,700)	$ 9,400
Allowance for doubtful accounts on accounts receivable	5,559	4,994
Bad debt expense	800	2,300	$ 250
Inventory, other	$ 26,573	33,217
Number of reporting unit \| Segment	1
Materials and supplies inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory, other	$ 9,400	20,800
Commodity inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory, other	$ 8,300	$ 4,800

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

3 Months Ended

12 Months Ended

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, 2016

Dec. 31, 2015

Dec. 31, 2014

Net book value of unproved properties

^[1]

$ 2,923,803,000

$ 949,155,000

$ 2,923,803,000

$ 949,155,000

$ 943,246,000

Abandonment and impairment of unproved properties

6,307,000

$ 6,082,000

$ 7,059,000

$ 10,628,000

11,432,000

$ 12,366,000

$ 12,330,000

$ 11,491,000

30,076,000

47,619,000

47,079,000

Depreciation expense

8,400,000

11,900,000

$ 12,900,000

Marketable securities held in deferred compensation plans

61,700,000

62,400,000

61,700,000

62,400,000

Surface acreage

$ 10,600,000

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

$ 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, 2016 USD ($) Customer Counterparty	Dec. 31, 2015 USD ($) Customer	Dec. 31, 2014 Customer	Dec. 31, 2017 MMBTU / d bbl / d $ / Mcf $ / bbl
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts on accounts receivable	$ 5,559	$ 4,994
Number of customers accounted more than 10% of total oil and gas revenues \| Customer	1	1	4
Net derivative asset	$ 16,800
Number of counterparties \| Counterparty	5
Total Number of Derivative Counterparties \| Counterparty	22
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
Natural Gas \| Scenario Forecast \| Counterparty One
Summary Of Significant Accounting Policies [Line Items]
Derivative contract volumes \| MMBTU / d				6,575
Natural Gas \| Minimum \| Scenario Forecast \| Counterparty One
Summary Of Significant Accounting Policies [Line Items]
Price used for calculating margin requirement \| $ / Mcf				4.43
Crude Oil \| Scenario Forecast \| Counterparty One
Summary Of Significant Accounting Policies [Line Items]
Derivative contract volumes \| bbl / d				608
Crude Oil \| Minimum \| Scenario Forecast \| Counterparty One
Summary Of Significant Accounting Policies [Line Items]
Price used for calculating margin requirement \| $ / bbl				83.20

Summary of Significant Accounting Policies - Accumulated Other Comprehensive Income (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)
Disclosure Summary Of Significant Accounting Policies Accumulated Other Comprehensive Income [Abstract]
Beginning Balance, Gross	$ 10,222
Contract settlements reclassified to income, Gross	(10,222)
Ending Balance, Gross	0
Beginning Balance, Tax Effect	(3,986)
Contract settlements reclassified to income, Tax Effect	3,986
Ending Balance, Tax Effect	0
Beginning Balance, Net of Tax	6,236
Contract settlements reclassified to income, Net of Tax	(6,236)
Ending Balance, Net of Tax	$ 0

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncement Early Adoption [Line Items]
Income tax benefit	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	$ (164,287)	$ (134,781)	$ (61,975)	$ 22,366	$ (280,750)	$ (338,677)	$ 396,503
Net loss	$ (160,709)	$ (41,971)	$ (224,936)	$ (93,772)	$ (321,827)	$ (300,948)	$ (118,594)	$ 27,684	$ (521,388)	$ (713,685)	$ 634,382
Basic earnings per share	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ (2.75)	$ (4.29)	$ 3.81
Diluted earnings per share	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ (2.75)	$ (4.29)	$ 3.79
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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
New Accounting Pronouncement Early Adoption [Line Items]
Net cash provided from operating activities				$ 387,068	$ 691,402	$ 974,353
Net cash (used in) provided from financing activities				$ (78,390)	(472,607)	271,203
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	$ 658,069
Net cash (used in) provided from financing activities	(75,834)	(99,008)	(39,029)		(472,607)	271,203	226,159	870,649
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	647,099
Net cash (used in) provided from financing activities	$ (72,473)	$ (95,411)	$ (35,229)		$ (464,905)	$ 291,421	$ 239,994	$ 881,619

Dispositions and Acquisitions - Dispositions - Additional Information (Detail) - USD ($)	1 Months Ended		3 Months Ended								6 Months Ended		9 Months Ended	12 Months Ended
	Feb. 28, 2015	Apr. 30, 2014	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, 2014	Jun. 16, 2014	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 30, 2015	Dec. 31, 2014
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets			$ 470,000	$ (2,597,000)	$ (3,304,000)	$ (1,643,000)	$ (408,909,000)	$ (681,000)	$ 2,909,000	$ (175,000)				$ (7,074,000)	$ (406,856,000)		$ 285,638,000
Conger Exchange Transaction
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets		$ 145,000,000
Net operating income prior to disposition												$ 21,900,000
Gain on sale of assets after selling expenses																	272,700,000
Sale and exchange transaction, closing date														Jun. 16, 2014
Selling expenses for property sale																	$ 5,000,000
Net operating income prior to acquisition											$ 25,700,000
Recognized revenue from sale of property interests acquire											$ 33,800,000
Nora Gathering, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Percentage of ownership interest, acquired											50.00%						50.00%
Percentage ownership interest											50.00%						50.00%
Fair value of membership interest on acquisition date																	$ 134,800,000
Nora Gathering, LLC \| Conger Exchange Transaction
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on fair value of membership interest																	10,000,000
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)
Proceeds from sale of oil and gas properties													$ 78,600,000
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
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														$ 302,000	943,000		3,000,000
Proceeds from sale of oil and gas properties														3,700,000	4,400,000		35,500,000
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)								(407,700,000)
Cash proceeds from sale of assets															$ 876,000,000
Net operating income prior to disposition																$ 52,300,000	$ 98,300,000
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	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 ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Merger-related expenses		$ 813	$ 33,791	$ 2,621	$ 0		$ 37,225	$ 0	$ 0
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
Merger-related expenses	$ 37,225
Revenues						$ 146,600
Net operating income						$ 94,900
Merger related costs incurred by Memorial excluded from ProForma							$ 7,100

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

Sep. 16, 2016

Dec. 31, 2016

Sep. 15, 2016

Dec. 31, 2015

Natural gas and oil properties:

Shares of Range common stock issued to Memorial stockholders

$ 1,654,292

$ 0

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

114,426

Long-term debt

1,204,449

Deferred taxes

547,348

Other long-term liabilities

77,223

Total purchase price plus liabilities assumed

5,032,243

Fair value of Memorial assets:

Cash and equivalents

7,180

Other current assets

97,875

Derivative instruments

152,994

Natural gas and oil properties:

Proved property

1,117,011

Unproved property

1,999,187

Other property and equipment

3,579

Earnings Per Share Reconciliation [Abstract]

^[1]

1,654,292

Other

125

Total asset value

$ 5,032,243

[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 Combinations [Abstract]
Revenues	$ 1,334,290	$ 2,253,368
Net loss	$ (590,777)	$ (555,793)
Loss per share:
Basic	$ (2.42)	$ (2.28)
Diluted	$ (2.42)	$ (2.28)

Income Taxes - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended								12 Months Ended
	Sep. 30, 2016	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Income tax (benefit) expense		$ (95,581,000)	$ (13,705,000)	$ (129,488,000)	$ (41,976,000)	$ (164,287,000)	$ (134,781,000)	$ (61,975,000)	$ 22,366,000	$ (280,750,000)	$ (338,677,000)	$ 396,503,000
Deferred tax liabilities		943,343,000				$ 777,947,000				943,343,000	$ 777,947,000
Deductible limit		1,000,000								1,000,000
Alternative minimum tax carryforwards		1,000,000,000								1,000,000,000
Accrued interest or penalties related to tax amounts		0								0
MRD
Income Taxes [Line Items]
Net deferred tax asset resulting from federal net operating loss	$ 12,400,000		$ 12,400,000
Anticipated utilization of net operating loss	100.00%
Accounting Standards Update 2016-09
Income Taxes [Line Items]
Income tax (benefit) expense					$ (41,976,000)
Net deferred tax asset resulting from federal net operating loss		403,400,000								$ 403,400,000
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
Alternative Minimum Tax
Income Taxes [Line Items]
AMT credit carryforwards that are not subject to limitation or expiration		9,700,000								$ 9,700,000
California, Colorado, Mississippi, New Mexico, Oklahoma and West Virginia
Income Taxes [Line Items]
Valuation allowance to net operating loss carryforward		24,500,000								24,500,000
Louisiana
Income Taxes [Line Items]
Valuation allowance to net operating loss carryforward		1,500,000								1,500,000
Pennsylvania
Income Taxes [Line Items]
Valuation allowance to net operating loss carryforward		32,400,000								32,400,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards		1,200,000,000								1,200,000,000
Deferred compensation plan
Income Taxes [Line Items]
Valuation allowances		$ 4,200,000								$ 4,200,000

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Federal statutory tax rate	35.00%	35.00%	35.00%
State	3.00%	4.30%	3.10%
State apportionment rate change	1.00%	(0.20%)	(0.20%)
Non-deductible executive compensation	(0.20%)	(0.10%)	0.20%
Valuation allowances	(2.50%)	(6.80%)	0.20%
Deficits in equity compensation	(0.70%)	0.00%	0.00%
Other	0.00%	0.00%	0.20%
Consolidated effective tax rate	35.00%	32.20%	38.50%
MRD
Income Taxes [Line Items]
Non-deductible MRD transaction costs	(0.60%)	0.00%	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current									$ 0	$ 0	$ 0
U.S. state and local, Current									98	29	1
Total, Current	$ 98	$ 0	$ 0	$ 0	$ 29	$ 0	$ 0	$ 0	98	29	1
U.S. federal, Deferred									(266,105)	(328,257)	361,152
U.S. state and local, Deferred									(14,743)	(10,449)	35,350
Total, Deferred	(95,679)	(13,705)	(129,488)	(41,976)	(164,316)	(134,781)	(61,975)	22,366	(280,848)	(338,706)	396,502
U.S. federal, Total									(266,105)	(328,257)	361,152
U.S. state and local, Total									(14,645)	(10,420)	35,351
Total income tax (benefit) expense	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	$ (164,287)	$ (134,781)	$ (61,975)	$ 22,366	$ (280,750)	$ (338,677)	$ 396,503

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Net operating loss carryforward	$ 478,203	$ 173,503
Deferred compensation	50,808	45,413
Equity compensation	29,528	25,940
AMT credits and other credits	13,644	4,437
Asset retirement obligation	99,000	101,142
Cumulative mark-to-market loss	73,404	0
Other	39,922	10,163
Valuation allowances:
Total deferred tax assets	677,335	272,975
Deferred tax liabilities:
Depreciation, depletion and investments	(1,619,922)	(940,482)
Cumulative mark-to-market gain	0	(109,845)
Other	(756)	(595)
Total deferred tax liabilities	(1,620,678)	(1,050,922)
Net deferred tax liability	(943,343)	(777,947)
Federal
Valuation allowances:
Valuation allowances	(43,600)	(42,500)
State, net of federal benefit
Valuation allowances:
Valuation allowances	(58,424)	(41,516)
Deferred compensation plans and other
Valuation allowances:
Valuation allowances	$ (5,150)	$ (3,607)

Income Taxes - Change in Deferred Tax Asset Valuation Allowances (Detail) - Valuation Allowance of Deferred Tax Assets - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Balance at the beginning of the year	$ (87,623)	$ (16,599)	$ (14,781)
Charged to provision for income taxes:
Other state valuation allowances	500	(1,050)	0
Other federal valuation allowances	(477)	(511)	363
Rabbi trust valuation allowance	(1,066)	3,494	3,619
Other	(34)	0	0
Balance at the end of the year	(107,174)	(87,623)	(16,599)
State
Charged to provision for income taxes:
Net operating loss carryforwards	(17,374)	(30,457)	(5,800)
Federal
Charged to provision for income taxes:
Net operating loss carryforwards	$ (1,100)	$ (42,500)	$ 0

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

3 Months Ended

12 Months Ended

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, 2016

Dec. 31, 2015

Dec. 31, 2014

Net (loss) income

$ (160,709)

$ (41,971)

$ (224,936)

$ (93,772)

$ (321,827)

$ (300,948)

$ (118,594)

$ 27,684

$ (521,388)

$ (713,685)

$ 634,382

Participating basic earnings

^[1]

(223)

(450)

(10,725)

Basic net (loss) income attributed to common stockholders

(521,611)

(714,135)

623,657

Reallocation of participating earnings

^[1]

Diluted net (loss) income attributed to common stockholders

$ (521,611)

$ (714,135)

$ 623,705

Net (loss) income per common share:

Basic

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ (1.93)

$ (1.81)

$ (0.71)

$ 0.16

$ (2.75)

$ (4.29)

$ 3.81

Diluted

$ (0.66)

$ (0.23)

$ (1.35)

$ (0.56)

$ (1.93)

$ (1.81)

$ (0.71)

$ 0.16

$ (2.75)

$ (4.29)

$ 3.79

[1]

Net (Loss) Income 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, 2016

Dec. 31, 2015

Dec. 31, 2014

Denominator:

Weighted average common shares outstanding – basic

^[1]

189,868

166,389

163,625

Effect of dilutive securities:

Director and employee SARs and restricted stock Equity Awards

778

Weighted average common shares outstanding – diluted

189,868

166,389

164,403

[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 (Loss) Income 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 (Loss) Income Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock Appreciation Rights (SARs)
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation			1,900
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

Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) Project	Dec. 31, 2015 USD ($) Project	Dec. 31, 2014 USD ($) Project
Extractive Industries [Abstract]
Balance at beginning of period	$ 4,161	$ 2,996	$ 6,964
Additions to capitalized exploratory well costs pending the determination of proved reserves	9,128	1,165	18,747
Reclassifications to wells, facilities and equipment based on determination of proved reserves	(5,877)	0	(15,735)
Capitalized exploratory well costs charged to expense	0	0	(6,980)
Balance at end of period	7,412	4,161	2,996
Less exploratory well costs that have been capitalized for a period of one year or less	(7,412)	(1,165)	(2,996)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 0	$ 2,996	$ 0
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| Project	0	1	0

Indebtedness - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

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

Dec. 31, 2016

Dec. 31, 2015

May 31, 2015

Bank debt

$ 876,428

$ 86,427

2,877,832

750,000

Unamortized debt issuance costs

48,980

1,850,000

Total debt

3,808,812

2,695,000

Unamortized premium

7,258

(42,553)

(43,697)

Total debt net of debt issuance costs

3,773,517

2,651,303

2.4% Bank Debt | Notes Payable to Banks

4.875% Senior Notes Due 2025

Bank debt

^[1]

882,000

95,000

5.00% Senior Notes Due 2023

750,000

$ 750,000

5.00% Senior Notes Due 2022

741,514

5.875% Senior Notes Due 2022

580,032

5.75% Senior Notes Due 2021

^[2]

329,244

Other Senior Notes Due 2022

475,952

5.00% Senior Subordinated Notes Due 2023

^[3]

1,090

5.00% Senior Subordinated Notes Due 2022

7,712

750,000

5.75% Senior Subordinated Notes Due 2021

19,054

600,000

$ 22,214

$ 500,000

[1]	As of September 16, 2016, we repaid the $597.0 million balance outstanding on the Memorial credit facility with funds borrowed under the Range credit facility and terminated the Memorial credit facility.
[2]	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 Note Exchange and Cash Tender Offer below.
[3]	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 Note Exchange and Cash Tender Offer below.

Indebtedness - Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Thousands		12 Months Ended
	Sep. 16, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 31, 2015
Debt Instrument [Line Items]
Balance outstanding repaid to terminate debt		$ 1,487,000	$ 2,899,000	$ 1,884,000
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% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	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%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes		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 \| 2.4% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage		2.40%	2.40%
MRD
Debt Instrument [Line Items]
Balance outstanding repaid to terminate debt	$ 597,000	$ 597,000	$ 0	$ 0

Indebtedness - Bank Debt - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2016 USD ($) CommercialBank	Dec. 31, 2015	Dec. 31, 2014	Mar. 17, 2016 USD ($)
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	$ 882,000,000
Undrawn letters of credit	268,100,000
Borrowing capacity available under the commitment amount	$ 849,900,000
Weighted average interest rate on the bank credit facility	2.20%	1.70%	2.00%
Annual rate of commitment fee paid on the undrawn balance	0.30%
Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.50%
LIBOR Rate
Debt Instrument [Line Items]
Interest rate margin	1.50%
Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Minimum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.15%
Minimum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	0.25%
Minimum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.125%
Minimum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Minimum \| LIBOR Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.125%
Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Maximum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Maximum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Maximum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.75%
Maximum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	2.25%
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
	May 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Aggregate principal amount		$ 2,877,832	$ 750,000
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Aggregate principal amount	$ 750,000	$ 750,000	$ 750,000
Interest rate on notes	4.875%	4.875%	4.875%
Net proceeds after underwriting discounts and commissions	$ 737,400
Underwriting discounts and commissions	$ 12,600
Maximum redemption price of notes as percentage of principal amount	101.00%

Indebtedness - Senior Note Exchange and Cash Tender Offer - Additional Information (Detail) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
	Sep. 16, 2016	Sep. 30, 2013	Dec. 31, 2016	Dec. 31, 2015
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes			5.875%	5.875%
Senior Note Cash Tender Offer \| 5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Early cash tender premium paid	$ 3.3
Senior Note 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 Note Exchange Offer \| MRD
Debt Instrument [Line Items]
Percentage of outstanding notes exchanged	54.90%
Unsecured Debt \| Senior Note Exchange Offer \| 5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes exchange amount	$ 329.2
Interest rate on notes	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
Debt Instrument [Line Items]
Principal Amount of Notes Validly Tendered	$ 742,291
Approximate Percentage Validly Tendered	99.00%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Principal Amount of Notes Validly Tendered	$ 580,946
Approximate Percentage Validly Tendered	96.80%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Principal Amount of Notes Validly Tendered	$ 477,786
Approximate Percentage Validly Tendered	95.60%

Indebtedness - Summary of Debt Exchange Offer to Exchange All Validly Tendered and Accepted Range Senior Subordinated Notes (Parenthetical) (Detail)	Dec. 31, 2016	Sep. 16, 2016	Dec. 31, 2015
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% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	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%

Indebtedness - Senior Subordinated Note Exchange- Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Sep. 16, 2016	Dec. 31, 2015
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes		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%
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%
Maturity date of loan		Jun. 01, 2021
Senior Notes
Debt Instrument [Line Items]
Interest expense on debt	$ 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	3 Months Ended								12 Months Ended
	Jul. 31, 2015	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Loss on early extinguishment of debt		$ 0	$ 0	$ 0	$ 0	$ 0	$ 22,495	$ 0	$ 0	$ 0	$ 22,495	$ 24,596
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount										101.00%
Subordinated Debt \| 8.0% Senior Subordinated notes due 2019
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount												104.00%
Announced call for redemption amount of debt												$ 300,000
Interest rate on notes												8.00%
Debt instrument, redemption description										In 2014, we announced a call for the redemption of $300.0 million of our outstanding 8.0% senior subordinated notes due 2019 at 104.0% of par plus accrued and unpaid interest which were redeemed on June 26, 2014.
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, 2016
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, 2016.
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]
2017	$ 0
2018	0
2019	882,000
2020	0
2021	498,166
Thereafter	2,428,646
Total debt	$ 3,808,812

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Beginning of period	$ 264,137	$ 287,463
Liabilities incurred	2,694	4,595
Acquisitions	21,900	1,584
Liabilities settled	(11,511)	(18,828)
Disposition of wells	(10,540)	(45,845)
Accretion expense	18,021	19,163
Change in estimate	(26,758)	16,005
End of period	257,943	264,137
Less current portion	(7,271)	(15,071)
Long-term asset retirement obligations	$ 250,672	$ 249,066

Capital Stock - Additional Information (Detail) - $ / shares	3 Months Ended												12 Months Ended
	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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.08	$ 0.16	$ 0.16

Capital Stock (Detail) - shares	12 Months Ended
Capital Stock (Detail) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class Of Stock [Line Items]
Beginning balance	169,316,460	168,628,177	163,342,894
Stock options/SARs exercised	0	77,002	195,242
Restricted stock grants	490,609	335,103	270,062
Restricted stock units vested	266,541	252,507	244,413
Shares retired	(739)	0	0
Treasury shares	28,736	23,671	15,566
Ending balance	247,144,356	169,316,460	168,628,177
MRD
Class Of Stock [Line Items]
MRD Merger	77,042,749	0	0
Common Stock
Class Of Stock [Line Items]
Equity offering	77,799,000	665,000	5,270,000
Common Stock \| Equity Offering
Class Of Stock [Line Items]
Equity offering	0	0	4,560,000

Derivative Activities - Additional Information (Detail)

12 Months Ended

Dec. 31, 2016

USD ($)

MMBTU / d

t_per_M

MMBTU

Counterparty

Institution

bbl

Dec. 31, 2014

USD ($)

Number of financial institutions with whom we conduct derivative activities | Institution

Number of secured lenders not in banking credit facility | Counterparty

Designated as Hedging Instrument

Gains (Losses) in oil and gas sales related to settled hedging transactions

$ 10,200,000

Derivatives Excluding Basis Swaps

Natural Gas | Basis Swaps

$ (187,200,000)

Natural Gas | Swaps | 2017

$ 11,800,000

Volume Hedged | MMBTU

66,210,000

Natural Gas | Swaps | 2018

^[1]

840,692

^[1]

276,712

Propane | Spread Swaps

Propane | Spread Swaps | 2017

$ (742,000)

Propane | Spread Swaps | 2018

Volume Hedged | bbl

1,637,500

Freight | Swaps | Level 2

Volume Hedged | bbl

750,000

Natural Gas | Swaps | 2017

$ 65,000

Volume Hedged | t_per_M

5,000

[1]	Includes derivative instruments assumed in connection with the MRD Merger.

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

Dec. 31, 2016

MMBTU / d

bbl / d

$ / bbl

$ / MMBTU

$ / gal

840,692

^[1]

Natural Gas | Swaps | 2018

3.19

^[1]

276,712

^[1]

Natural Gas | Collar | 2017

3.12

Weighted Average Floor Price | $ / MMBTU

42,750

^[1]

3.48

^[1]

Weighted Average Cap Price | $ / MMBTU

4.15

^[1]

Natural Gas | Purchased Put | 2017

175,890

^[1]

Natural Gas | Sold Call | 2017

3.48

^[1],[2]

9,041

3.75

^[3]

Crude Oil | Swaps | 2017

Weighted Average Hedge Price | $ / bbl

8,542

^[1]

55.77

^[1]

Crude Oil | Swaps | 2018

Weighted Average Hedge Price | $ / bbl

2,750

54.24

Commodity Contract NGLs (C2 - Ethane) | Swaps | 2017

3,000

Commodity Contract NGLs (C3 - Propane) | Swaps | 2017

0.27

11,610

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

0.55

5,699

Commodity Contract NGLs (NC4 - Normal Butane) | Swaps | 2017

0.65

7,000

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

0.73

2,000

Commodity Contract NGLs (C5 - Natural Gasoline) | Swaps | 2017

0.78

5,250

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

1.06

1,000

1.18

[1]	Includes derivative instruments assumed in connection with the MRD Merger.
[2]	Weighted average deferred premium is ($0.32).
[3]	Weighted average deferred premium is $0.31.

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Natural Gas - 2017	Dec. 31, 2016 $ / MMBTU
Purchased Put
Derivative [Line Items]
Weighted average deferred premium	0.32
Sold Call
Derivative [Line Items]
Weighted average deferred premium	0.31

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 77,079	$ 304,350
Gross Amounts Offset in the Balance Sheet	(63,596)	(15,588)
Net Amounts of Assets Presented in the Balance Sheet	13,483	288,762
Gross Amounts of Recognized (Liabilities)	(253,096)	(16,745)
Gross Amounts Offset in the Balance Sheet	63,596	15,588
Net Amounts of (Liabilities) Presented in the Balance Sheet	(189,500)	(1,157)
Natural Gas \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	13,213	219,357
Gross Amounts Offset in the Balance Sheet	(11,425)	(10,245)
Net Amounts of Assets Presented in the Balance Sheet	1,788	209,112
Gross Amounts of Recognized (Liabilities)	(158,359)	(10,245)
Gross Amounts Offset in the Balance Sheet	11,425	10,245
Net Amounts of (Liabilities) Presented in the Balance Sheet	(146,934)	0
Natural Gas \| Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,535	8,251
Gross Amounts Offset in the Balance Sheet	(9,437)	(2,765)
Net Amounts of Assets Presented in the Balance Sheet	3,098	5,486
Gross Amounts of Recognized (Liabilities)	(687)	(2,786)
Gross Amounts Offset in the Balance Sheet	9,437	2,765
Net Amounts of (Liabilities) Presented in the Balance Sheet	8,750	(21)
Natural Gas \| Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	6,298
Gross Amounts Offset in the Balance Sheet	(6,298)
Net Amounts of Assets Presented in the Balance Sheet	0
Gross Amounts of Recognized (Liabilities)	(2,625)
Gross Amounts Offset in the Balance Sheet	6,298
Net Amounts of (Liabilities) Presented in the Balance Sheet	3,673
Natural Gas \| Puts
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
Natural Gas \| Calls
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)
Crude Oil \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	9,356	38,699
Gross Amounts Offset in the Balance Sheet	(3,489)	0
Net Amounts of Assets Presented in the Balance Sheet	5,867	38,699
Gross Amounts of Recognized (Liabilities)	(13,206)
Gross Amounts Offset in the Balance Sheet	3,489
Net Amounts of (Liabilities) Presented in the Balance Sheet	(9,717)
Commodity Contract NGLs (C2 - Ethane) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	53
Gross Amounts Offset in the Balance Sheet	(53)
Net Amounts of Assets Presented in the Balance Sheet	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 Contract NGLs (C3 - Propane) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		15,884
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		15,884
Gross Amounts of Recognized (Liabilities)	(32,437)
Gross Amounts Offset in the Balance Sheet	0
Net Amounts of (Liabilities) Presented in the Balance Sheet	(32,437)
Commodity Contract NGLs (C3 - Propane) \| Spread Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	17,396	2,497
Gross Amounts Offset in the Balance Sheet	(17,396)	(2,497)
Net Amounts of Assets Presented in the Balance Sheet	0	0
Gross Amounts of Recognized (Liabilities)	(18,138)	(3,633)
Gross Amounts Offset in the Balance Sheet	17,396	2,497
Net Amounts of (Liabilities) Presented in the Balance Sheet	(742)	(1,136)
Commodity Contract NGLs (NC4 - Normal Butane) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	4
Gross Amounts Offset in the Balance Sheet	(4)
Net Amounts of Assets Presented in the Balance Sheet	0
Gross Amounts of Recognized (Liabilities)	(13,419)
Gross Amounts Offset in the Balance Sheet	4
Net Amounts of (Liabilities) Presented in the Balance Sheet	(13,415)
Freight \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	65
Gross Amounts Offset in the Balance Sheet	(65)
Net Amounts of Assets Presented in the Balance Sheet	0
Gross Amounts of Recognized (Liabilities)	0
Gross Amounts Offset in the Balance Sheet	65
Net Amounts of (Liabilities) Presented in the Balance Sheet	65
Commodity Contract NGLs (C5 - Natural Gasoline) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		12,694
Gross Amounts Offset in the Balance Sheet		(81)
Net Amounts of Assets Presented in the Balance Sheet		12,613
Gross Amounts of Recognized (Liabilities)	(12,176)	(81)
Gross Amounts Offset in the Balance Sheet	0	81
Net Amounts of (Liabilities) Presented in the Balance Sheet	$ (12,176)	0
Commodity Contract NGLs (C4 - Propane) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		6,968
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		$ 6,968

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ (250,057)	$ 64,556	$ (162,798)	$ 86,908	$ 126,312	$ 202,004	$ (34,791)	$ 122,839	$ (261,391)	$ 416,364	$ 383,520
Re-purchased Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									0	851	0
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)									(6,926)	16,539	42,836
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									29,154	954	(26,800)
Puts
Derivative [Line Items]
Derivative Fair Value Income (Loss)									(18,201)	0	0
Calls
Derivative [Line Items]
Derivative Fair Value Income (Loss)									(18)	0	0
Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									(265,466)	398,020	367,484
Freight \| Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									$ 66	$ 0	$ 0

Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends									$ 972,000	$ 908,000	$ 911,000
Mark-to-market gain (loss)									3,100,000	(5,900,000)	(2,400,000)
Impairment on natural gas and oil properties	$ 0	$ 0	$ 0	$ 43,040,000	$ 87,941,000	$ 502,233,000	$ 0	$ 0	43,040,000	590,174,000	28,024,000
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
Mississippi
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											5,500,000
West Texas
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											18,500,000
North Texas
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties											$ 4,000,000

Fair Value Measurements - Value of Assets Measured at Fair Value on Non Recurring Basis (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties	$ 0	$ 0	$ 0	$ 43,040	$ 87,941	$ 502,233	$ 0	$ 0	$ 43,040	$ 590,174	$ 28,024
Fair Value, Measurements, Nonrecurring \| Natural Gas and Oil Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value									90,150	152,230	15,605
Impairment of proved properties									$ 43,040	$ 590,174	$ 28,024

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

Dec. 31, 2016

Dec. 31, 2015

Carrying Value

Assets:

$ 13,483

$ 288,762

Marketable securities

^[1]

61,717

62,376

Deferred compensation plan

(189,500)

(1,157)

Bank credit facility

^[2]

(882,000)

(95,000)

^[3]

(139,580)

(122,918)

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]

(741,514)

Carrying Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(1,090)

Carrying Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(22,214)

(500,000)

Carrying Value | 4.875% Senior Notes Due 2025

^[2]

(7,712)

(750,000)

Carrying Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(750,000)

^[2]

(19,054)

(600,000)

Fair Value

Assets:

13,483

288,762

Marketable securities

^[1]

61,717

62,376

Deferred compensation plan

(189,500)

(1,157)

Bank credit facility

^[2]

(882,000)

(95,000)

^[3]

(139,580)

(122,918)

Fair Value | 5.75% Senior Notes Due 2021

Fair Value | 5.00% Senior Notes Due 2022

^[2]

(496,180)

Fair Value | 5.875% Senior Notes Due 2022

^[2]

(577,132)

Fair Value | 5.00% Senior Notes Due 2023

^[2]

(343,648)

Fair Value | Other Senior Notes Due 2022

^[2]

(735,026)

Fair Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(1,104)

Fair Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(22,325)

(396,250)

Fair Value | 4.875% Senior Notes Due 2025

^[2]

(7,645)

(551,250)

Fair Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(724,688)

(572,813)

Summary of Performance Share Unit Awards outstanding, Number of Units

^[2]

$ (18,387)

$ (447,000)

[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, 2016	Sep. 16, 2016	Dec. 31, 2015	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%
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%
5.875% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	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%
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) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2014
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted		1,104
Vesting period	3 years
Stock Appreciation Rights (SARs) \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration term of stock units	5 years
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 55,618	$ 57,801	$ 70,681
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,302	2,780	4,208
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	1,725	2,132	3,523
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,298	2,985	4,569
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	49,293	49,687	55,382
Termination Costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 0	$ 217	$ 2,999

Stock-based Compensation Plans - Additional Information 1 (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax (benefit) expense	$ (95,581)	$ (13,705)	$ (129,488)	$ (41,976)	$ (164,287)	$ (134,781)	$ (61,975)	$ 22,366	$ (280,750)	$ (338,677)	$ 396,503
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax (benefit) expense									5,700
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense									12,400	$ 8,700	7,900
Unrecognized compensation related to Awards	$ 16,200								$ 16,200
Weighted average period									1 year 9 months 18 days
Former Executive Chairman
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense											$ 6,700

Stock-based Compensation Plans - PSUA Activities (Detail) - Performance Shares - $ / shares

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Outstanding, Beginning Balance

^[1]

262,124

134,341

Granted

^[1]

413,959

276,204

227,929

Vested

^[1]

(237,572)

^[2]

(143,094)

^[2]

(92,077)

^[3]

Forfeited

^[1]

(42,603)

(5,327)

(1,511)

Outstanding, Ending Balance

^[1]

395,908

262,124

134,341

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

Outstanding, Beginning Balance, weighted average grant date fair value

$ 64.77

$ 86.11

$ 0

Granted, weighted average grant date fair value

36.64

56.78

86.14

Vested, weighted average grant date fair value

53.07

68.73

86.23

Forfeited, weighted average grant date fair value

46.09

82.60

Outstanding, Ending Balance, weighted average grant date fair value

$ 44.39

$ 64.77

$ 86.11

[1]	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent 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 PSU awards of 19,684 that were modified and fully vested effective with the closing of our Oklahoma City Office and the sale of our Virginia and West Virginia assets.
[3]	Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

Stock-based Compensation Plans - PSUA Activities (Parenthetical) (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oklahoma, Virginia And West Virginia
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares vested in period on performance number of units	19,684
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	0.00%	0.00%	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	150.00%	150.00%	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	0.94%	1.02%	0.77%
Expected annual volatility	49.00%	33.00%	33.00%
Grant date fair value per unit	$ 36.64	$ 56.78	$ 86.14

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Proceeds from the sales of common stock held by the deferred compensation plan	$ 13,102,000	$ 8,298,000	$ 15,964,000
Total intrinsic value of stock options and SARs exercised	0	$ 5,400,000	$ 27,100,000
Aggregate intrinsic value of the awards outstanding	0
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
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	973,491	587,711	356,194
Vesting period	3 years	3 years	3 years
Stock-based compensation expense	$ 22,800,000	$ 23,800,000	$ 28,100,000
Unrecognized compensation related to Awards	$ 24,700,000
Weighted average period	1 year 9 months 18 days
Granted, weighted average grant date fair value	$ 28.51	$ 52.29	$ 84.87
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	540,128	343,397	272,052
Stock-based compensation expense	$ 18,600,000	$ 20,800,000	$ 26,300,000
Unrecognized compensation related to Awards	$ 17,700,000
Weighted average period	1 year 9 months 18 days
Granted, weighted average grant date fair value	$ 35.92	$ 55.92	$ 87.34
Restricted Stock Liability Awards \| Non Employee Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	59,000	48,000	64,000
Restricted Stock Liability Awards \| Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	481,000	295,000	208,000
Vesting period	3 years	3 years	3 years
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation related to Awards	$ 0
Number of fully vested awards and awards expected to vest	1,000,000
Weighted average exercise price of fully vested awards and awards expected to vest	$ 69.08
Weighted average exercise price of fully vested awards and awards expected to vest in years	8 months 12 days

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	436,764	360,415	385,063
Granted	973,491	587,711	356,194
Vested	(525,617)	(480,253)	(354,237)
Forfeited	(118,667)	(31,109)	(26,605)
Outstanding, Ending Balance	765,971	436,764	360,415
Outstanding, Beginning Balance, weighted average grant date fair value	$ 59.74	$ 79.60	$ 68.24
Granted, weighted average grant date fair value	28.51	52.29	84.87
Vested, weighted average grant date fair value	43.83	65.21	72.85
Forfeited, weighted average grant date fair value	42.60	64.73	75.66
Outstanding, Ending Balance, weighted average grant date fair value	$ 33.62	$ 59.74	$ 79.60
Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	308,737	304,504	389,013
Granted	540,128	343,397	272,052
Vested	(374,328)	(330,870)	(356,413)
Forfeited	(49,519)	(8,294)	(148)
Outstanding, Ending Balance	425,018	308,737	304,504
Outstanding, Beginning Balance, weighted average grant date fair value	$ 65.80	$ 80.33	$ 71.02
Granted, weighted average grant date fair value	35.92	55.92	87.34
Vested, weighted average grant date fair value	51.40	68.71	75.52
Forfeited, weighted average grant date fair value	40.33	74.22	77.35
Outstanding, Ending Balance, weighted average grant date fair value	$ 43.48	$ 65.80	$ 80.33

Stock-based Compensation Plans - Stock Option and SARs Activities (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Beginning Balance, Shares	1,510,977	1,966,549	2,582,074
Granted, Shares			1,104
Exercised, Shares	0	(427,598)	(616,563)
Expired/forfeited, Shares	(507,377)	(27,974)	(66)
Ending Balance, Shares	1,003,600	1,510,977	1,966,549
Beginning Balance, Weighted Average Exercise Price	$ 63.73	$ 59.80	$ 56.36
Granted, Weighted Average Exercise Price			81.74
Exercised, Weighted Average Exercise Price	0	45.67	45.45
Expired/forfeited, Weighted Average Exercise Price	53.16	63.10	46.44
Ending Balance, Weighted Average Exercise Price	$ 69.08	$ 63.73	$ 59.80

Stock-based Compensation Plans - Summary of SARs Outstanding and Exercisable (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number of outstanding Number of exercisable, Shares	1,003,600
Weighted Average Remaining Contractual Life (in years)	8 months 27 days
Weighted Average Exercise Price, Outstanding	$ 69.08	$ 63.73	$ 59.80	$ 56.36
Number of exercisable, Shares	1,003,600
Weighted Average Exercise Price, Exercisable	$ 69.08
Range of Exercise Prices One
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	40.00
Exercise Price, Maximum	$ 49.99
Number of outstanding Number of exercisable, Shares	10,108
Weighted Average Remaining Contractual Life (in years)	15 days
Weighted Average Exercise Price, Outstanding	$ 49.18
Number of exercisable, Shares	10,108
Weighted Average Exercise Price, Exercisable	$ 49.18
Range of Exercise Prices Two
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	50.00
Exercise Price, Maximum	$ 59.99
Number of outstanding Number of exercisable, Shares	0
Weighted Average Exercise Price, Outstanding	$ 0
Number of exercisable, Shares	0
Weighted Average Exercise Price, Exercisable	$ 0
Range of Exercise Prices Three
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	60.00
Exercise Price, Maximum	$ 69.99
Number of outstanding Number of exercisable, Shares	578,064
Weighted Average Remaining Contractual Life (in years)	4 months 10 days
Weighted Average Exercise Price, Outstanding	$ 64.23
Number of exercisable, Shares	578,064
Weighted Average Exercise Price, Exercisable	$ 64.23
Range of Exercise Prices Four
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	413,528
Weighted Average Remaining Contractual Life (in years)	1 year 3 months 11 days
Weighted Average Exercise Price, Outstanding	$ 76.29
Number of exercisable, Shares	413,528
Weighted Average Exercise Price, Exercisable	$ 76.29
Range of Exercise Prices Five
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)	1 year 8 months 9 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 - Weighted Average Grant Date Fair Value of SARs (Detail) - Stock Appreciation Rights (SARs)	12 Months Ended
	Dec. 31, 2014 $ / shares
Schedule Of Weighted Average Assumptions For Fair Values Of Stock Options [Line Items]
Weighted average exercise price per share	$ 81.74
Expected annual dividend yield	0.20%
Expected life in years	4 years 3 months 18 days
Expected volatility	33.00%
Risk-free interest rate	1.40%
Weighted average grant date fair value per share	$ 23.17

Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Maximum percentage of employees contribution									75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer contribution									$ 4,700	$ 6,100	$ 5,800
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ (11,013)	$ (11,636)	$ 25,746	$ 16,056	$ (21,016)	$ (43,705)	$ (7,282)	$ (5,624)	$ 19,153	$ (77,627)	$ (74,550)
Shares held in rabbi trust total	2.7				2.8				2.7	2.8
Vested shares held in rabbi trust	2.3				2.5				2.3	2.5

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Net cash provided from operating activities included:

Income taxes (refunded from) paid to taxing authorities

$ (102)

$ 100

$ (156)

Interest paid

159,875

168,826

165,530

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net

^[1],[2]

(24,064)

22,184

56,822

Increase (decrease) in accrued capital expenditures

^[1]

$ 61,419

$ (225,455)

$ 150,604

[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, 2016 USD ($) bbl / d Mcf / d	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Commitments And Contingencies Disclosure [Line Items]
Rent expense under operating leases \| $	$ 14.0	$ 15.9	$ 13.3
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	10,000
Minimum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	15 years
Maximum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	20 years
Natural Gas \| 2032
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	1,300,000
Natural Gas \| 2037
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	400,000
Natural Gas \| 2017 through 2032
Commitments And Contingencies Disclosure [Line Items]
Gathering commitments contingent upon pipeline construction or modification	400,000
Natural Gas \| 2018
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	65,000
Natural Gas \| 2017
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	50,000
Natural Gas \| 2019
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	215,000
North Louisiana
Commitments And Contingencies Disclosure [Line Items]
Liability for expected volume deficiency payments \| $	$ 59.2

Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands	Dec. 31, 2016 USD ($)
Commitments And Contingencies Disclosure [Abstract]
2017	$ 18,407
2018	16,126
2019	13,498
2020	13,088
2021	12,076
Thereafter	40,892
Operating Lease Obligations	$ 114,087

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

Dec. 31, 2016

USD ($)

^[1]

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

$ 705,243

699,863

699,254

635,379

606,797

3,326,015

Transportation and Gathering Contracts

$ 6,672,551

[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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost And Reserve [Line Items]
Termination costs	$ (822,000)	$ 136,000	$ 5,000	$ 162,000	$ 8,780,000	$ (77,000)	$ 417,000	$ 5,950,000	$ 8,400,000	$ (519,000)	$ 15,070,000	$ 8,371,000
Stock-based compensation expense (gain)										0	217,000	2,999,000
Building lease										303,000	3,147,000	$ 0
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	$ 11,630	$ 5,372
Accrued severance costs	(822)	11,706	$ 5,372
Accrued building rent	303	3,147
Payments	(8,651)	(8,595)
Ending balance	$ 2,460	$ 11,630	$ 5,372

Office Closing and Exit Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	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, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Severance costs										$ (822)	$ 11,706	$ 5,372
Building lease										303	3,147	0
Stock-based compensation										0	217	2,999
Total termination costs	$ (822)	$ 136	$ 5	$ 162	$ 8,780	$ (77)	$ 417	$ 5,950	$ 8,400	$ (519)	$ 15,070	$ 8,371

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								9 Months Ended		12 Months Ended
	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, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets	$ 470	$ (2,597)	$ (3,304)	$ (1,643)	$ (408,909)	$ (681)	$ 2,909	$ (175)			$ (7,074)	$ (406,856)	$ 285,638
Impairment of proved properties and other	$ 0	$ 0	$ 0	43,040	87,941	502,233	$ 0	$ 0			$ 43,040	590,174	$ 28,024
Virginia And West Virginia Property
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets					(407,700)							$ (407,700)
Western Oklahoma Properties
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets										$ (5,300)
Impairment of proved properties and other				$ 43,000
Northern Oklahoma and Legacy Shallow Northwest Pennsylvania Assets
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other						$ 502,200
Texas Panhandle And South Texas
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other					$ 87,900
MRD
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other									$ 37,200

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	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, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues and other income:
Natural gas, NGLs and oil sales	$ 458,645	$ 304,477	$ 224,606	$ 209,487	$ 254,043	$ 252,065	$ 258,053	$ 325,483		$ 1,197,215	$ 1,089,644	$ 1,911,989
Derivative fair value income (loss)	(250,057)	64,556	(162,798)	86,908	126,312	202,004	(34,791)	122,839		(261,391)	416,364	383,520
Brokered natural gas, marketing and other	44,934	44,174	39,989	35,018	30,372	25,864	21,339	14,485		164,115	92,060	130,548
Total revenues and other income	253,522	413,207	101,797	331,413	410,727	479,933	244,601	462,807		1,099,939	1,598,068	2,426,057
Costs and expenses:
Direct operating	30,276	22,387	20,671	24,054	29,388	35,058	34,780	37,137		97,388	136,363	150,483
Transportation, gathering and compression	164,338	138,764	136,844	125,263	112,481	99,634	95,198	89,426		565,209	396,739	325,289
Production and ad valorem taxes	6,790	6,717	6,049	5,887	7,354	7,336	9,242	9,928		25,443	33,860	44,555
Brokered natural gas and marketing	46,471	44,622	40,925	36,558	34,942	32,331	27,031	21,562		168,576	115,866	129,980
Exploration	13,684	6,943	6,785	4,913	4,260	4,235	5,025	7,886		32,325	21,406	63,548
Abandonment and impairment of unproved properties	6,307	6,082	7,059	10,628	11,432	12,366	12,330	11,491		30,076	47,619	47,079
General and administrative	57,027	41,024	46,064	40,657	43,544	46,178	55,964	48,329		184,772	194,015	213,426
MRD Merger expenses	813	33,791	2,621	0						37,225	0	0
Termination costs	(822)	136	5	162	8,780	(77)	417	5,950	$ 8,400	(519)	15,070	8,371
Deferred compensation plan	(11,013)	(11,636)	25,746	16,056	(21,016)	(43,705)	(7,282)	(5,624)		19,153	(77,627)	(74,550)
Interest	46,749	45,967	37,758	37,739	40,849	42,904	43,479	39,207		168,213	166,439	168,977
Loss on early extinguishment of debt	0	0	0	0	0	22,495	0	0		0	22,495	24,596
Depletion, depreciation and amortization	149,662	131,489	122,390	120,561	127,977	153,993	151,895	147,290		524,102	581,155	551,032
Impairment of proved properties and other	0	0	0	43,040	87,941	502,233	0	0		43,040	590,174	28,024
Loss (gain) on the sale of assets	(470)	2,597	3,304	1,643	408,909	681	(2,909)	175		7,074	406,856	(285,638)
Total costs and expenses	509,812	468,883	456,221	467,161	896,841	915,662	425,170	412,757		1,902,077	2,650,430	1,395,172
(Loss) income before income taxes	(256,290)	(55,676)	(354,424)	(135,748)	(486,114)	(435,729)	(180,569)	50,050		(802,138)	(1,052,362)	1,030,885
Income tax (benefit) expense:
Current	98	0	0	0	29	0	0	0		98	29	1
Deferred	(95,679)	(13,705)	(129,488)	(41,976)	(164,316)	(134,781)	(61,975)	22,366		(280,848)	(338,706)	396,502
Total income tax (benefit) expense	(95,581)	(13,705)	(129,488)	(41,976)	(164,287)	(134,781)	(61,975)	22,366		(280,750)	(338,677)	396,503
Net (loss) income	$ (160,709)	$ (41,971)	$ (224,936)	$ (93,772)	$ (321,827)	$ (300,948)	$ (118,594)	$ 27,684		$ (521,388)	$ (713,685)	$ 634,382
Net (loss) income per common share:
Basic	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16		$ (2.75)	$ (4.29)	$ 3.81
Diluted	$ (0.66)	$ (0.23)	$ (1.35)	$ (0.56)	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16		$ (2.75)	$ (4.29)	$ 3.79

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, 2016

Dec. 31, 2015

Dec. 31, 2014

Natural gas and oil properties:

Properties subject to depletion

^[1]

$ 9,462,350

$ 8,047,181

$ 9,624,725

Unproved properties

^[1]

2,923,803

949,155

943,246

Total

^[1]

12,386,153

8,996,336

10,567,971

Accumulated depletion and depreciation

^[1]

(3,129,816)

(2,635,031)

(2,590,398)

Natural gas and oil properties, successful efforts method, net

^[1]

$ 9,256,337

$ 6,361,305

$ 7,977,573

[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, 2016

Dec. 31, 2015

Dec. 31, 2014

Acquisitions

Acreage purchases

^[1],[2]

$ 33,142

$ 73,025

$ 226,475

Oil and gas properties

^[1],[2]

3,098,772

392,325

Asset retirement obligations and other

^[1],[2]

21,908

11,927

Development

^[1]

497,795

708,268

1,119,896

Exploration:

Exploration drilling costs incurred

^[1]

37,680

87,505

180,925

Gas gathering facilities:

Development

^[1]

3,595

13,337

13,137

Subtotal

^[1]

3,725,217

903,541

2,008,233

Asset retirement obligations

^[1],[3]

(24,064)

22,184

56,822

Total costs incurred

^[1]

3,701,153

925,725

2,065,055

Expense

Exploration:

Exploration costs incurred

^[1]

30,027

18,421

58,979

Stock-based compensation expense

^[1]

$ 2,298

$ 2,985

$ 4,569

[1]	Includes cost incurred whether capitalized or expensed.
[2]	See also Note 3 for additional information related to the 2014 Conger Exchange which includes $134.8 million of gas gathering assets received in the exchange.
[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) - Costs Incurred for Property Acquisition, Exploration and Development (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Gas Gathering Assets
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Acquisition Costs, Period Cost	$ 134.8

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

12 Months Ended

Dec. 31, 2016

USD ($)

MMcfe

$ / Mcf

$ / bbl

$ / MMBTU

MMcf

MBbls

Dec. 31, 2015

MMcfe

$ / Mcf

$ / bbl

$ / MMBTU

MMcf

MBbls

Dec. 31, 2014

MMcfe

$ / Mcf

$ / bbl

$ / MMBTU

MMcf

MBbls

Dec. 31, 2013

MMcfe

MMcf

MBbls

Percentage of proved resources reviewed by consultants

96.00%

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

86.00%

80.00%

58.00%

Improved recoveries

393,000

781,000

449,600

Proved undeveloped reserves dropped

269,000

1,200,000

611,000

Cost spent on undeveloped reserves transferred to developed reserves | $

$ 245.6

Estimated future development costs in 2017 | $

877.9

Estimated future development costs in 2018 | $

516.6

Estimated future development costs in 2019 | $

$ 607.7

Proved undeveloped reserves reported for more than five years

50,000

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

42.68

50.13

94.42

Crude Oil

Estimate reserve information average realized prices | $ / bbl

37.41

35.07

79.04

Proved developed and undeveloped reserves | MBbls

70,252

53,193

48,658

48,360

NGLs

Estimate reserve information average realized prices | $ / bbl

13.44

11.74

27.20

Proved developed and undeveloped reserves | MBbls

630,066

549,135

515,907

374,412

Natural Gas

Estimate reserve information average realized prices | $ / Mcf

2.07

4.14

Proved developed and undeveloped reserves | MMcf

7,870,416

6,277,697

6,922,836

5,665,645

Natural Gas, Per Thousand Cubic Feet

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

2.48

2.59

4.35

Natural Gas Equivalents

Proved reserves from drilling activities and evaluations of proved areas

^[1]

1,394,134

1,265,348

2,398,709

Proved developed and undeveloped reserve balances

^[1]

12,072,322

9,891,663

10,310,229

8,202,274

Revisions of previous estimates

^[1]

255,794

(211,163)

90,822

Revisions of positive performance

154,000

Ethane and Natural Gas Equivalents

Proved developed and undeveloped reserve balances

1,367,000

1,296,000

1,170,000

Ethane Reserves and NGLs

Proved developed and undeveloped reserves | MBbls

308,900

292,800

264,300

[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, 2016

MMcfe

MMcf

MBbls

Dec. 31, 2015

MMcfe

MMcf

MBbls

Dec. 31, 2014

MMcfe

MMcf

MBbls

Proved undeveloped reserves | MMcfe

5,302,414

4,469,588

Natural Gas

Extensions, discoveries and additions | MMcf

Beginning Balance | MMcf

6,277,697

6,922,836

5,665,645

Revisions | MMcf

(7,441)

(340,286)

(30,566)

1,193,154

1,017,956

1,393,108

Purchases | MMcf

943,544

262,813

Property sales | MMcf

(160,727)

(960,122)

(81,238)

Production | MMcf

(375,811)

(362,687)

(286,926)

Ending Balance | MMcf

7,870,416

6,277,697

6,922,836

Proved developed reserves | MMcf

4,352,141

3,376,165

3,583,051

Proved undeveloped reserves | MMcf

3,518,275

2,901,533

3,339,785

NGLs

Extensions, discoveries and additions

Beginning Balance

549,135

515,907

374,412

Revisions

41,402

17,717

19,716

26,991

36,308

154,664

Purchases

40,724

Property sales

(360)

(441)

(14,064)

Production

(27,826)

(20,356)

(18,821)

Ending Balance

630,066

549,135

515,907

Proved developed reserves

363,852

309,306

270,271

Proved undeveloped reserves

266,214

239,828

245,636

Crude Oil and Condensate

Extensions, discoveries and additions

Beginning Balance

53,193

48,658

48,360

Revisions

2,471

3,804

515

6,506

4,924

12,936

Purchases

11,986

Property sales

(295)

(109)

(9,083)

Production

(3,609)

(4,084)

(4,070)

Ending Balance

70,252

53,193

48,658

Proved developed reserves

39,110

31,679

24,180

Proved undeveloped reserves

31,143

21,514

24,478

Natural Gas Equivalents

Proved developed reserves | MMcfe

^[1]

6,769,908

5,422,075

5,349,761

Proved undeveloped reserves | MMcfe

^[1]

5,302,414

4,469,588

4,960,468

Beginning Balance | MMcfe

^[1]

9,891,663

10,310,229

8,202,274

Revisions | MMcfe

^[1]

255,794

(211,163)

90,822

Extensions, discoveries and additions | MMcfe

^[1]

1,394,134

1,265,348

2,398,709

Purchases | MMcfe

^[1]

1,259,806

262,813

Property sales | MMcfe

^[1]

(164,655)

(963,423)

(220,122)

Production | MMcfe

^[1]

(564,420)

(509,328)

(424,267)

Ending Balance | MMcfe

^[1]

12,072,322

9,891,663

10,310,229

[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, 2016

MMcfe

Beginning proved undeveloped reserves at December 31, 2015

4,469,588

Undeveloped reserves transferred to developed

(1,065,262)

Revisions

145,204

^[1]

Purchases/(sales)

503,192

Extension and discoveries

1,249,692

Ending proved undeveloped reserves at December 31, 2016

5,302,414

[1]	Includes 269 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Proved undeveloped reserves dropped	269	1,200	611

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, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013