View Filing Data

Senior subordinated notes

2,856,166

2,851,754

48,677

48,585

Deferred tax liabilities

666,668

693,356

Derivative liabilities

3,462

9,789

Deferred compensation liabilities

67,542

101,102

Asset retirement obligations and other liabilities

319,379

286,043

Total liabilities

5,648,723

5,954,569

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, 249,519,687 issued at December 31, 2018 and 248,144,397 issued at December 31, 2017

2,495

2,481

Common stock held in treasury, 9,665 shares at December 31, 2018 and 14,967 shares at December 31, 2017

(391)

(599)

Additional paid-in capital

5,628,447

5,577,732

Accumulated other comprehensive loss

(658)

(1,332)

Retained (deficit) earnings

(1,570,462)

195,990

Total stockholders' equity

4,059,431

5,774,272

Total liabilities and stockholders' equity

$ 9,708,154

$ 11,728,841

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

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 6,118	$ 7,111
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	249,519,687	248,144,397
Common stock held in treasury, shares	9,665	14,967

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Revenues and other income:

Revenues and other income

$ 3,333,836

Derivative fair value (loss) income

$ 100,698

$ (34,591)

$ (103,290)

$ (14,009)

$ 25,024

$ (88,426)

$ 111,195

$ 165,557

(51,192)

$ 213,350

$ (261,391)

Total revenues and other income

1,072,637

811,225

656,184

742,599

679,032

482,232

673,111

776,655

3,282,645

2,611,030

1,099,939

Costs and expenses:

Production and ad valorem taxes

16,656

9,427

10,140

9,926

11,757

11,993

9,969

9,163

46,149

42,882

25,443

Brokered natural gas and marketing

221,626

116,080

102,747

55,594

51,131

59,773

55,857

53,550

496,047

220,311

168,576

Exploration

10,600

8,299

7,499

7,719

7,893

22,767

14,498

8,504

34,117

53,662

32,325

Abandonment and impairment of unproved properties

441,750

6,549

54,922

11,773

217,544

42,568

5,193

4,420

514,994

269,725

30,076

General and administrative

50,090

43,722

47,583

68,417

80,553

53,035

52,322

47,496

209,812

233,406

184,772

MRD Merger expenses

37,225

Termination costs

(336)

(37)

(279)

(47)

(96)

4,192

(373)

3,770

(519)

Deferred compensation plan

(18,072)

223

6,615

(7,397)

(14,077)

(9,203)

(14,466)

(13,169)

(18,631)

(50,915)

19,153

Interest

49,161

54,801

53,862

52,385

51,473

49,179

47,926

47,101

210,209

195,679

168,213

Depletion, depreciation and amortization

147,909

164,266

161,026

162,266

162,918

159,749

152,504

149,821

635,467

624,992

524,102

Impairment of proved properties

15,302

7,312

63,679

22,614

63,679

43,040

Impairment of goodwill

1,641,197

Loss (gain) on the sale of assets

10,815

(156)

(23)

(207)

(102)

(807)

(22,600)

10,666

(23,716)

7,074

Total costs and expenses

2,905,843

738,549

764,538

650,685

806,927

681,924

545,910

494,149

5,059,615

2,528,910

1,902,077

(Loss) income before income taxes

(1,833,206)

72,676

(108,354)

91,914

(127,895)

(199,692)

127,201

282,506

(1,776,970)

82,120

(802,138)

Income tax (benefit) expense:

Current

Deferred

(68,784)

24,137

(28,518)

42,676

(349,097)

(71,992)

57,651

112,395

(30,489)

(251,043)

(280,848)

Total (benefit) expense for income taxes

(68,784)

24,137

(28,518)

42,676

(349,080)

(71,992)

57,651

112,395

(30,489)

(251,026)

(280,750)

Net (loss) income

$ (1,764,422)

$ 48,539

$ (79,836)

$ 49,238

$ 221,185

$ (127,700)

$ 69,550

$ 170,111

$ (1,746,481)

$ 333,146

$ (521,388)

Net (loss) income per common share:

Basic

$ (7.15)

$ 0.19

$ (0.32)

$ 0.20

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (7.10)

$ 1.34

$ (2.75)

Diluted

$ (7.15)

$ 0.19

$ (0.32)

$ 0.20

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (7.10)

$ 1.34

$ (2.75)

Weighted average common shares outstanding:

Basic

^[1]

246,171

245,091

189,868

Diluted

246,171

245,458

189,868

Natural Gas, NGLs and Oil Sales

Revenues and other income:

Revenues and other income

$ 756,627

$ 736,431

$ 661,390

$ 696,629

$ 603,159

$ 507,541

$ 506,137

$ 559,450

$ 2,851,077

$ 2,176,287

$ 1,197,215

Brokered Natural Gas, Marketing and Other

Revenues and other income:

Revenues and other income

215,312

109,385

98,084

59,979

50,849

63,117

55,779

51,648

482,760

221,393

164,115

Direct Operating

Costs and expenses:

Costs and expenses

35,395

30,926

35,088

38,122

37,921

36,888

31,420

28,023

139,531

134,252

97,388

Transportation, Gathering, Processing and Compression

Costs and expenses:

Costs and expenses

$ 298,716

$ 304,562

$ 269,910

$ 244,628

$ 200,300

$ 191,645

$ 191,590

$ 177,648

$ 1,117,816

$ 761,183

$ 565,209

[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, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income	$ (1,746,481)	$ 333,146	$ (521,388)
Postretirement benefits:
Actuarial gain	526
Prior service cost		(1,769)
Amortization of prior service costs	369
Income tax (expense) benefit	(221)	437
Total comprehensive (loss) income	$ (1,745,807)	$ 331,814	$ (521,388)

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Industry Specific Policies [Abstract]

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities:
Net (loss) income	$ (1,746,481,000)	$ 333,146,000	$ (521,388,000)
Adjustments to reconcile net (loss) income to net cash provided from operating activities:
Deferred income tax benefit	(30,489,000)	(251,043,000)	(280,848,000)
Depletion, depreciation and amortization and impairment of proved properties	658,081,000	688,671,000	567,142,000
Impairment of goodwill	1,641,197,000	0	0
Exploration dry hole and impairment costs	4,000	9,172,000	18,000
Abandonment and impairment of unproved properties	514,994,000	269,725,000	30,076,000
Derivative fair value loss (income)	51,192,000	(213,350,000)	261,391,000
Cash settlements on derivative financial instruments	(131,522,000)	13,117,000	347,336,000
Allowance for bad debt	(1,000,000)	1,550,000	800,000
Amortization of deferred financing costs, loss on extinguishment of debt and other	2,515,000	5,445,000	7,170,000
Deferred and stock-based compensation	29,757,000	30,706,000	74,685,000
Loss (gain) on the sale of assets	10,666,000	(23,716,000)	7,074,000
Changes in working capital:
Accounts receivable	(142,381,000)	(102,866,000)	(20,586,000)
Inventory and other	138,000	(2,979,000)	6,220,000
Accounts payable	(4,274,000)	45,912,000	(27,259,000)
Accrued liabilities and other	138,293,000	12,764,000	(64,763,000)
Net cash provided from operating activities	990,690,000	816,254,000	387,068,000
Investing activities:
Additions to natural gas and oil properties	(960,916,000)	(1,148,613,000)	(466,252,000)
Additions to field service assets	(1,477,000)	(5,710,000)	(3,052,000)
Acreage purchases	(60,603,000)	(58,213,000)	(43,482,000)
MRD Merger, net of cash acquired	0	0	7,180,000
Proceeds from disposal of assets	324,549,000	72,468,000	193,755,000
Purchases of marketable securities held by the deferred compensation plan	(46,177,000)	(88,167,000)	(37,019,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	49,190,000	89,178,000	40,035,000
Net cash used in investing activities	(695,434,000)	(1,139,057,000)	(308,835,000)
Financing activities:
Borrowings on credit facilities	2,070,000,000	2,041,000,000	2,274,000,000
Repayments on credit facilities	(2,338,000,000)	(1,712,000,000)	(1,487,000,000)
Repayment of senior or senior subordinated notes	0	(500,000)	(273,012,000)
Dividends paid	(19,940,000)	(19,839,000)	(16,682,000)
Debt issuance costs	(8,220,000)	(403,000)	(6,342,000)
Taxes paid for shares withheld	(3,183,000)	(6,983,000)	(3,849,000)
Change in cash overdrafts	(5,563,000)	17,180,000	18,393,000
Proceeds from the sales of common stock held by the deferred compensation plan	9,747,000	4,482,000	13,102,000
Net cash (used in) provided from financing activities	(295,159,000)	322,937,000	(78,390,000)
Increase (decrease) in cash and cash equivalents	97,000	134,000	(157,000)
Cash and cash equivalents at beginning of year	448,000	314,000	471,000
Cash and cash equivalents at end of year	545,000	448,000	314,000
MRD
Adjustments to reconcile net (loss) income to net cash provided from operating activities:
Abandonment and impairment of unproved properties	436,000,000
Financing activities:
Repayments on credit facilities	$ 0	$ 0	$ (597,000,000)

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Common stock held in treasury	Additional paid-in capital	Retained (deficit)/earnings	Accumulated other comprehensive (loss) income
Beginning balance at Dec. 31, 2015	$ 2,759,658	$ 1,693	$ (2,245)	$ 2,442,623	$ 317,587	$ 0
Beginning balance Shares at Dec. 31, 2015		169,376,000
Issuance of common stock	3,048,653	$ 778	0	3,047,875	0	0
Issuance of common stock, shares		77,799,000
Stock-based compensation expense	37,023	$ 0	0	37,023	0	0
Tax benefit related to stock-based compensation	(2,062)	0	0	(2,062)	0	0
Cash dividends paid ($0.08 per share)	(16,682)	0	0	0	(16,682)	0
Cumulative-effect adjustment from adoption of ASU 2016-09	103,166	0	0	0	103,166	0
Treasury stock issuance		0	1,036	(1,036)	0	0
Net (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		247,175,000
Issuance of common stock	2,987	$ 10	0	2,977	0	0
Issuance of common stock, shares		969,000
Stock-based compensation expense	50,942	$ 0	0	50,942	0	0
Cash dividends paid ($0.08 per share)	(19,839)	0	0	0	(19,839)	0
Treasury stock issuance		0	610	(610)	0	0
Other comprehensive income (loss)	(1,332)	0	0	0	0	(1,332)
Net (loss) income	333,146	0	0	0	333,146	0
Ending balance at Dec. 31, 2017	$ 5,774,272	$ 2,481	(599)	5,577,732	195,990	(1,332)
Ending balance Shares at Dec. 31, 2017	248,144,397	248,144,000
Issuance of common stock	$ 13,696	$ 14	0	13,682	0	0
Issuance of common stock, shares		1,374,000
Issuance of common stock upon vesting of PSUs		$ 0	0	31	(31)	0
Issuance of common stock upon vesting of PSUs, shares		2,000
Stock-based compensation expense	37,210	$ 0	0	37,210	0	0
Cash dividends paid ($0.08 per share)	(19,940)	0	0	0	(19,940)	0
Treasury stock issuance	0	0	208	(208)	0	0
Other comprehensive income (loss)	674	0	0	0	0	674
Net (loss) income	(1,746,481)	0	0	0	(1,746,481)	0
Ending balance at Dec. 31, 2018	$ 4,059,431	$ 2,495	$ (391)	$ 5,628,447	$ (1,570,462)	$ (658)
Ending balance Shares at Dec. 31, 2018	249,519,687	249,520,000

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement Of Stockholders Equity [Abstract]
Cash dividends paid per share	$ 0.08	$ 0.08	$ 0.08

Summary of Organization and Nature of Business

12 Months Ended

Dec. 31, 2018

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, natural gas liquids (“NGLs”), crude oil and condensate company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and North Louisiana regions of the United States. Our objective is to build stockholder value through consistent returns focused development, measured on a per share debt-adjusted basis, for both reserves and production. 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, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2) Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

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

Use of Estimates

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

Estimated quantities of natural gas, NGLs, crude oil and condensate reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGLs, crude oil and condensate reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of natural gas, NGLs and crude oil and condensate that are ultimately recovered. See Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, goodwill, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.

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, crude oil and condensate in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas, crude oil and condensate 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 revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. See a more detailed summary of our product types below.

Natural Gas and NGLs Sales

Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity.

In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense.

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

•

We sell oil production at the wellhead and collect an agreed-upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

•

We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation, gathering, processing and compression expense.

Brokered Natural Gas, Marketing and Other

We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties and subsequently selling that natural gas or NGLs under our existing contracts to fill our contract commitments or use existing infrastructure contracts to economically fulfill available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $16.3 million in 2018 compared to losses of $5.7 million in 2017 and losses of $2.8 million in 2016.

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 $6.1 million at December 31, 2018 compared to $7.1 million at December 31, 2017. We recorded bad debt income of $1.0 million in the year ended December 31, 2018 compared to expense of $1.6 million in the year ended December 31, 2017 and expense of $800,000 in the year ended December 31, 2016.

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.

The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. We may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales or in limited cases may use them for contracts we intend to physically settle but that do not meet all of the criteria to be treated as normal sales.

Cash and Cash Equivalents

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

Marketable Securities

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

Inventory

Inventories were comprised of $8.0 million of materials and supplies at December 31, 2018 compared to $12.1 million at December 31, 2017. Inventories consist primarily of tubular goods and equipment used in our operations and are stated at the lower of specific cost of each inventory item or net realizable value, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is reviewed periodically for obsolescence or impairment when market conditions indicate. At December 31, 2018, we also had commodity inventory of $965,000, compared to $508,000 at December 31, 2017, which is carried at lower of weighted average cost or net realizable value, on a first-in, first-out basis. Commodity inventory at December 31, 2018 consists of NGLs held as line fill in pipelines or tanks.

Goodwill

During 2016, we recorded $1.7 billion of goodwill associated with our MRD Merger, which represented the excess of consideration transferred over the fair value of the assets acquired and liabilities assumed. In 2017, final purchase adjustments for the MRD Merger resulted in a $13.1 million decrease to goodwill. Goodwill is not amortized but tested for impairment annually, as of November 1^st, or more frequently if events or circumstances indicate that impairment may exist. We assess the value of our business under either a qualitative or quantitative approach. Under a qualitative approach, we consider various market factors, including an examination of relevant events and circumstances that could have a negative impact on our business, such as macroeconomic conditions, industry and market conditions (including current commodity prices), earnings and cash flows, overall financial performance and other relevant entity-specific events. These factors are analyzed to determine if events and circumstances have affected the fair value of our business.

If we determine that it is more likely that our business is impaired, the quantitative approach is used to assess our fair value and the amount of the impairment. When performing a quantitative impairment assessment of goodwill, fair value is estimated based on a combination of (i) projected discounted cash flows (an income approach); and (ii) market capitalization plus a control premium approach. Under the income approach, the fair value is based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for, and development of, unproved reserves, discount rates and other variables. Key assumptions used in the discounted cash flow model include estimated quantities of crude oil, natural gas and NGLs reserves, including both proved reserves and risk-adjusted unproved reserves, estimates of market prices considering forward commodity price curves as of the measurement date, and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer company based weighted average cost of capital. The estimated market capitalization approach is determined by multiplying our average stock price and outstanding common shares plus a control premium. The control premium reflects the impact on asking price for a controlling interest in a company based on recent transaction premiums of comparable companies. This requires management to make certain judgments including the selection of comparable companies and/or comparable recent company asset transactions and transaction premiums. If our carrying value exceeds our fair value calculated using the quantitative approach, an impairment charge is recorded for the difference between fair value and carrying value.

In fourth quarter 2018, we determined goodwill was fully impaired and recorded an impairment charge of $1.6 billion. For more information, see Note 11.

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 17.

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, 2018, additional expense of $9.8 million was recorded related to these costs compared to $158,000 in the year ended December 31, 2017 and $1.9 million in the year ended December 31, 2016.

Impairments. Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 11.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs and allocated probable and possible reserves value resulting from acquisitions. 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 which could impact the number of drilling locations we intend to drill. 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. Information such as reservoir performance or future plans to develop acreage is also considered. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. A significant portion of our unproved property is the result of value allocated in the MRD Merger related to probable and possible reserves whose recoverability is evaluated based on managements expectations and ability to drill these locations. Unproved properties had a net book value of $2.1 billion as of December 31, 2018 compared to $2.6 billion in 2017. We have recorded abandonment and impairment expense related to unproved properties of $515.0 million in the year ended December 31, 2018 compared to $269.7 million in 2017 and $30.1 million in 2016. Abandonment and impairment expense in 2018 includes an impairment of $436.0 million related to probable and possible reserve value allocated in the MRD Merger which we no longer have the intent to drill.

Dispositions. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 4.

Acquisitions. Acquisitions of proved properties are accounted for as either a business combination or an asset acquisition and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. In a business combination, purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In an asset acquisition, fair value is assigned to the assets acquired. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. For additional information regarding our acquisitions, see Note 4.

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 $6.0 million in the year ended December 31, 2018 compared to $7.7 million in the year ended December 31, 2017 and $8.4 million in the year ended December 31, 2016.

Other Assets

Other assets at December 31, 2018 include $57.3 million of marketable securities held in our deferred compensation plans and $9.1 million of other investments including surface acreage. Other assets at December 31, 2017 include $67.1 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage.

Stock-based Compensation Arrangements

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

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 12.

Derivative Financial Instruments and Hedging

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

All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. Beginning in third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend or double the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 10.

From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2018, we did not materially modify any existing derivative contracts.

Concentrations of Credit Risk

As of December 31, 2018, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. This concentration of companies may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $6.1 million at December 31, 2018 compared to $7.1 million at December 31, 2017. We do not anticipate a material impact on our financial results due to non-performance by third parties.

For the years ended December 31, 2018, 2017 and 2016, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production.

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

At December 31, 2018, our derivative counterparties included twenty financial institutions and commodity traders, of which all but four are secured lenders in our bank credit facility. At December 31, 2018, our net derivative asset includes a receivable from the counterparties not included in our bank credit facility totaling $9.7 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.

Contingencies

We are subject to legal proceedings, claims, and liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 15 for a more detailed discussion regarding our contingencies.

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.

Accounting Standards

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements And Changes In Accounting Principles [Abstract]

Accounting Standards

(3) Accounting Standards

Recently Adopted

Pension Accounting Standard

In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers are to present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs arising from services rendered during the period. This new standards update was effective for annual reporting periods in first quarter 2018 and must be applied retrospectively. We adopted this standards update in first quarter 2018. The adoption did not impact our consolidated results of operations, financial position, cash flows or disclosures. We had no service cost recorded prior to 2018 due to the implementation of our post retirement benefit plan at the end of 2017. In 2018, our service cost is recorded in general and administrative expense.

Modification of Share – Based Awards

In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update was intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. We adopted this standards update in first quarter 2018. The adoption of this standard did not have a material impact on our consolidated results of operations, financial position, cash flows or disclosures.

Revenue Recognition Standard

In May 2014, an accounting standards update was issued that superseded the existing revenue recognition requirements. This standard included 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 eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. This standard was effective for us in first quarter 2018 and we adopted the new standards update using the modified retrospective method to all open contracts as of January 1, 2018. Our implementation of this standard did not result in a cumulative-effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts changed. Based on previous accounting guidance, certain of our gas processing contracts were reported in revenue at the net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts are now reported as a gross price received at a delivery point and separate transportation, marketing and processing expense. The impact of adoption of the new revenue recognition standard on our current period results is as follows (in thousands):

	Year Ended December 31, 2018
	As Reported					Previous Revenue Recognition Method
		$			$ Per mcfe		$			$ Per mcfe		Increase		$ Per mcfe
Revenues:
Natural gas, NGLs and oil sales	$	2,851,077		$	3.55	$	2,678,278		$	3.33	$	172,799	$	0.22
Costs and expenses:
Transportation, gathering, processing and compression	$	1,117,816		$	1.39	$	945,017		$	1.17	$	172,799	$	0.22
Net loss	$	(1,746,481	)			$	(1,746,481	)			$	—

Changes to natural gas, NGLs and oil sales and transportation, gathering, processing, and compression expenses is due to the conclusion that we represent the role of principal in certain gas processing and marketing agreements with a midstream entity in accordance with the new accounting standard. This represents a change from our previous conclusion utilizing the principal versus agent indication that we acted as the agent in that agreement. As a result, we were required to modify our presentation to present revenue on a gross basis for amounts expected to be received from third-party customers through the marketing process, with expenses incurred prior to control of the products transferring to the midstream entity at the tailgate of the plant presented as transportation, gathering, processing and compression expense.

Goodwill Standard

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

Inventory Standard

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

Classification in the Statement of Cash Flows

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

Definition of a Business

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

Share-Based Payment Awards

In March 2016, an accounting standards update was issued that simplifies several aspects of the accounting for share-based payment award transactions. We adopted this accounting standards update in fourth quarter 2016 which required us to reflect any adjustments as of January 1, 2016, the beginning of the annual period that included the interim period of adoption. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employee’s behalf are presented in the financing section instead of the operating activities section of the statement of cash flows. The change in the statement of cash flows was not material for the year ended December 31, 2016. We recorded a cumulative-effect adjustment to retained earnings and reduced our deferred tax liability for $101.1 million for previously unrecognized tax benefits due to our NOL position. Adoption of this new standards update 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.

Not Yet Adopted

Lease Accounting Standard

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use asset and lease liability for all leases with terms of more than twelve months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. We have evaluated each of our lease arrangements and have enhanced our systems to track and calculate additional information necessary for adoption of this standard. We have identified and documented changes to processes and controls to ensure all impacts of the new standard are effectively addressed. We are evaluating the provisions of this accounting standards update and finalizing the impact it will have on our consolidated results of operations, financial position and financial disclosures. While we have yet to finalize the impact this standards update will have on our consolidated financial statements, the adoption will increase our recorded assets and liabilities related to our leases.

We will adopt this new standards update in first quarter 2019 using a modified retrospective approach and will recognize a right of use asset and lease liability on the adoption date. We are applying the following practical expedients as provided in the standards update:

•

an election to not apply the recognition requirements in the new standards update to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option); and

•

a package of practical expedients to not reassess whether a contract contains a lease, lease classification and initial direct costs; and

•

a practical expedient to not reassess certain land easements in existence prior to January 1, 2019.

We have not yet determined the extent of the adjustments that will be required upon implementation of this new standards update.

Financial Instruments – Credit Losses

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

Fair Value Measurement

In August 2018, an accounting standards update was issued which provides additional disclosure requirements for fair value measurements. This new standards update eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for us in first quarter 2020 and will be adopted on a prospective or retrospective basis depending on the changes that apply. We are evaluating the provisions of this standards update and assessing the impact, if any, it may have on our financial disclosures.

Dispositions and Acquisitions

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Dispositions and Acquisitions

(4)	Dispositions and Acquisitions

We recognized a pretax net loss on the sale of assets of $10.7 million in the year ended December 31, 2018 compared to a gain of $23.7 million in 2017 and a loss of $7.1 million in 2016. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2018, 2017 and 2016.

2018 Dispositions

Pennsylvania. In fourth quarter 2018, we sold a proportionately reduced 1% overriding royalty in our Washington County, Pennsylvania leases for gross proceeds of $300.0 million. We recorded a loss of $10.2 million related to this sale, after closing adjustments and transaction fees.

Northern Oklahoma. In third quarter 2018, we sold properties in Northern Oklahoma for proceeds of $23.3 million and we recorded a net loss of $39,000 related to this sale, after closing adjustments.

Other. In 2018, we sold miscellaneous proved property, inventory and other assets for proceeds of $1.2 million, resulting in a pretax loss of $448,000.

2017 Dispositions

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

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

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

2016 Dispositions

Western Oklahoma. In 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 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.

Memorial Merger

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

Allocation of Purchase Price. The MRD Merger was accounted for as a business combination, using the acquisition method. The total purchase price of the MRD Merger was allocated 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.

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

Revenues from Contracts with Customers

12 Months Ended

Dec. 31, 2018

Revenue From Contract With Customer [Abstract]

Revenues from Contracts with Customers

(5)	Revenues from Contracts with Customers

Disaggregation of Revenue

We have identified three material revenue streams in our business: natural gas sales, NGLs sales, crude oil and condensate sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

		Year Ended December 31, 2018
Natural gas sales ^(a)	$	2,137,573
NGLs sales ^(b)		940,378
Crude oil and condensate sales		255,885
Total	$	3,333,836

^(a)

Natural gas sales revenue reported above includes $460.3 million of brokered revenues and $13.4 million of marketing revenue.

^(b)

NGLs sales revenue reported above includes $9.0 million of brokered revenues.

Principal versus Agent

We engage in various types of transactions in which midstream entities process our wet gas and, in some scenarios, subsequently market the resulting NGLs and residue gas to third-party customers on our behalf. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient allowed in the new revenue accounting standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have also utilized the practical expedient that states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $438.3 million at December 31, 2018 and $305.7 million at December 31, 2017.

Prior−Period Performance Obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. We have internal controls in place for our estimation process and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

(6)	Income Taxes

Our income tax benefit was $30.5 million for the year ended December 31, 2018 compared to $251.0 million in 2017 and $280.8 million in 2016. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2018		2017			2016
Federal statutory tax rate	21.0	%		35.0	%		35.0	%
Federal rate change	—			(406.7	)		—
State	(0.3	)		(0.7	)		3.0
State rate and law change	0.9			(1.3	)		1.0
Non-deductible executive compensation	—			0.7			(0.2	)
Non-deductible MRD transaction costs	—			—			(0.6	)
Valuation allowances	(0.4	)		36.8			(2.5	)
Equity compensation	(0.1	)		30.2			(0.7	)
Goodwill impairment	(19.4	)		—			—
Other	—			0.3			—
Consolidated effective tax rate	1.7	%		(305.7	%)		35.0	%

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

		2018								2017										2016
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred			Total
U.S. federal	$	—	$	(25,322	)	$	(25,322	)	$	—	$	(302,507	)		$	(302,507	)		$		—	$		(266,105	)		$	(266,105	)
U.S. state and local		—		(5,167	)		(5,167	)		17		51,464				51,481					98			(14,743	)			(14,645	)
Total	$	—	$	(30,489	)	$	(30,489	)	$	17	$	(251,043	)		$	(251,026	)		$		98	$		(280,848	)		$	(280,750	)

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

	December 31,
	2018			2017
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	542,847		$	413,672
Deferred compensation		19,844			24,704
Equity compensation		8,152			5,269
AMT credits and other credits		3,296			7,264
Asset retirement obligation		78,126			69,398
Other		30,492			18,806
Valuation allowances:
Federal		(18,975	)		(31,308	)
State, net of federal benefit		(101,372	)		(93,826	)
Total deferred tax assets		562,410			413,979
Deferred tax liabilities:
Depreciation, depletion and investments		(1,207,784	)		(1,105,494	)
Cumulative mark-to-market gain		(21,294	)		(1,841	)
Other		—			—
Total deferred tax liabilities		(1,229,078	)		(1,107,335	)
Net deferred tax liability	$	(666,668	)	$	(693,356	)

On December 22, 2017, the 2017 Tax Act was signed into law. The law significantly reforms the Internal Revenue Code of 1986, as amended. The reduction in the corporate tax rate required a one-time revaluation of certain tax related assets and liabilities to reflect their value at the lower corporate tax rate of 21%. We reviewed all of the valuation allowances previously established at the corporate rate of 35% to reflect the appropriate new balances after the enactment of the new law. A one-time tax benefit was recorded related to the tax law changes in the amount of $334.0 million in the year ended December 31, 2017.

At December 31, 2018, deferred tax liabilities exceeded deferred tax assets by $666.7 million. As of December 31, 2018, we have a state valuation allowance of $101.4 million related to state tax attributes in Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. As of December 31, 2018, we have federal valuation allowances of $19.0 million primarily related to our federal net operating loss carryforward and charitable contribution carryforward. See the table below for activity related to these valuation allowances.

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

		2018			2017			2016
Balance at the beginning of the year	$	(125,134	)	$	(107,174	)	$	(87,623	)
Charged to provision for income taxes:
State net operating loss carryforwards		(23,926	)		(11,612	)		(17,374	)
Federal net operating carryforwards		11,716			15,385			(1,100	)
Other state valuation allowances		16,380			(23,790	)		500
Other federal valuation allowances		494			(247	)		(477	)
Other		123			2,304			(1,100	)
Balance at the end of the year	$	(120,347	)	$	(125,134	)	$	(107,174	)

At December 31, 2018, we had federal net operating loss (“NOL”) carryforwards of $2.0 billion that expire between 2019 and 2037 and also include $520.1 million of NOL carryforwards that do not expire. We have state NOL carryforwards in Pennsylvania of $882.7 million that expire between 2025 and 2038 and in Louisiana, we have $338.6 million that expire between 2034 and 2038. We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years 2015 and after and we are subject to various state tax examinations for years 2014 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 in 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, 2018. Throughout 2018 and 2017, our unrecognized tax benefits were not material.

Net Income (Loss) Per Common Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Net Income (Loss) Per Common Share

(7)	Net Income (Loss) per Common Share

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


	Year Ended December 31,
	2018			2017			2016
Net (loss) income, as reported	$	(1,746,481	)	$	333,146		$	(521,388	)
Participating basic earnings ^(a)		(245	)		(3,751	)		(223	)
Basic net (loss) income attributed to common stockholders		(1,746,726	)		329,395			(521,611	)
Reallocation of participating earnings ^(a)		—			5			—
Diluted net (loss) income attributed to common stockholders	$	(1,746,726	)	$	329,400		$	(521,611	)
Net (loss) income per common share:
Basic	$	(7.10	)	$	1.34		$	(2.75	)
Diluted	$	(7.10	)	$	1.34		$	(2.75	)

^(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,
	2018	2017		2016
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	246,171		245,091		189,868
Effect of dilutive securities:
Director and employee restricted stock and performance-based equity awards	—		367		—
Weighted average common shares outstanding – diluted	246,171		245,458		189,868

⁽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 3.1 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for the period ending December 31, 2018 and 2.8 million shares for both of the periods ending December 31, 2017 and 2016. Due to our net loss for the years ended December 31, 2018 and 2016, we excluded all outstanding equity grants from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. Equity grants of 702,000 for the year ended December 31, 2017 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations. For purposes of calculating diluted weighted average common shares for the year ended December 31, 2017, nonvested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

Indebtedness

12 Months Ended

Dec. 31, 2018

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, 2018 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 2018, 2017, and 2016.


		December 31, 2018			December 31, 2017
Bank debt (4.1%)	$	943,000		$	1,211,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,531			741,531
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022		329,244			329,244
Other senior notes due 2022		590			590
Total senior notes		2,877,349			2,877,349
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		3,869,329			4,137,329
Unamortized premium		4,741			6,027
Unamortized debt issuance costs		(37,209	)		(34,550	)
Total debt (net of debt issuance costs)	$	3,836,861		$	4,108,806

Bank Debt

In April 2018, 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, 2018, the facility had a borrowing base of $3.0 billion and bank commitments of $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by each May and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-seven 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 April 13, 2023. As of December 31, 2018, the outstanding balance under the bank credit facility was $943.0 million with $281.4 million of undrawn letters of credit leaving $775.6 million of borrowing capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility can either be at the alternate base rate (“ABR,” as defined in the bank credit agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to ABR loans or to convert all or any part of our ABR loans to LIBOR loans. The weighted average interest rate was 3.7% for the year ended December 31, 2018 compared to 2.7% for the year ended December 31, 2017 and 2.2% for the year ended December 31, 2016. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2018, the commitment fee was 0.30%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our ABR.

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

Senior Notes

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

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

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

Senior Subordinated Notes

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

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, 2018.

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2018 (in thousands):

	Year Ended December 31,
2019	$	—
2020		—
2021		498,166
2022		928,920
2023		1,692,243
Thereafter		750,000
	$	3,869,329

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

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 lives. 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, 2018 and 2017 (in thousands):


	2018			2017
Beginning of period	$	276,855		$	257,943
Liabilities incurred		3,376			7,724
Acquisitions		13,438			—
Liabilities settled		(5,052	)		(7,965	)
Disposition of wells		(13,332	)		(8,078	)
Accretion expense		25,456			14,711
Change in estimate		12,013			12,520
End of period		312,754			276,855
Less current portion		(5,485	)		(6,327	)
Long-term asset retirement obligations	$	307,269		$	270,528

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

Derivative Activities

12 Months Ended

Dec. 31, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Activities

(10)	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, calls, swaptions or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Their fair value, which is represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price (generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs), approximated a net derivative asset of $80.9 million at December 31, 2018. These contracts expire monthly through December 2020. The following table sets forth the derivative volumes by year as of December 31, 2018, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2019	Swaps	1,318,041 Mmbtu/day	$ 2.86
2019	Swaptions	113,014 Mmbtu/day	$ 2.81 ⁽¹⁾
2020	Swaptions	80,000 Mmbtu/day	$ 2.77 ⁽¹⁾

Crude Oil
2019	Swaps	7,000 bbls/day	$ 55.26
2020	Swaps	1,562 bbls/day	$ 61.05
2019	Collars	1,000 bbls/day	$ 63.00-$ 73.03

NGLs (C3-Propane)
January-June, 2019	Swaps	8,500 bbls/day	$ 0.92/gallon
January-June, 2019	Collars	3,983 bbls/day	$ 0.92-$ 1.02/gallon

NGLs (NC4-Normal Butane)
January-March, 2019	Swaps	2,250 bbls/day	$ 1.22/gallon

NGLs (C5-Natural Gasoline)
2019	Swaps	2,429 bbls/day	$ 1.44/gallon

⁽¹⁾ Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volume. In 2019, we have swaps in place for 150,000 Mmbtu per day on which the counterparty can elect to extend the contract through December 2020 at a weighted average price of $2.81. In 2020, if the counterparty elects to double the volume, we would have additional swaps covering 80,000 Mmbtu per day at a weighted average price of $2.77.

Basis Swap Contracts

In addition to the swaps, collars and swaptions above, at December 31, 2018, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through October 2021 and include a total volume of 70,940,000 Mmbtu. The fair value of these contracts was a net derivative asset of $4.8 million on December 31, 2018.

At December 31, 2018, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly in January through June and October through December 2019. The fair value of these contracts was a net derivative asset of $117,000 on December 31, 2018.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2018, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly through December 2019 and cover 10,000 metric tons per month with a fair value net derivative liability of $561,000 on December 31, 2018. These contracts use observable third-party pricing inputs that we consider to be Level 2 fair value classification.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2018 and 2017 is summarized below (in thousands). As of December 31, 2018, we are conducting derivative activities with twenty counterparties, of which all but four 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, 2018
		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	$	20,834	$	(11,748	)	$	9,086
	–swaptions		5,200		(3,883	)		1,317
	–basis swaps		6,468		(2,822	)		3,646
Crude oil	–swaps		26,481		(651	)		25,830
	–collars		5,945		(707	)		5,238
NGLs	–C3 propane swaps		18,719		(589	)		18,130
	–C3 propane collars		8,538		—			8,538
	–C3 propane spread swaps		8,984		(8,868	)		116
	–NC4 butane swaps		4,084		—			4,084
	–C5 natural gasoline swaps		17,371		—			17,371
Freight	–swaps		—		(561	)		(561	)
		$	122,624	$	(29,829	)	$	92,795

		December 31, 2018
		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	$	(18,332	)	$	11,748	$	(6,584	)
	–swaptions		(7,972	)		3,883		(4,089	)
	–basis swaps		(1,702	)		2,822		1,120
Crude oil	–swaps		—			651		651
	–collars		—			707		707
NGLs	–C3 propane swaps		—			589		589
	–C3 propane spread swaps		(8,868	)		8,868		—
Freight	–swaps		(561	)		561		—
		$	(37,435	)	$	29,829	$	(7,606	)

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

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

Derivative assets and liabilities

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 (Loss) Income
	2018			2017			2016
Commodity swaps	$	(57,950	)	$	181,095		$	(265,466	)
Swaptions		(6,556	)		6,534			—
Collars		17,583			18,132			(6,926	)
Basis swaps		(1,104	)		(4,647	)		29,154
Puts		—			10,929			(18,201	)
Calls		(2,653	)		987			(18	)
Freight swaps		(512	)		320			66
Total	$	(51,192	)	$	213,350		$	(261,391	)

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

(11)	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 does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•

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

•

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

•

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

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. When transfers between levels occur, it is our policy to assume the transfer occurred at the date of the event or change in circumstances that caused the transfer.

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, 2018 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, 2018
Trading securities held in the deferred compensation plans		$	57,293	$	—		$	—		$	57,293
Derivatives	–swaps		—		69,156			—			69,156
	–collars		—		5,945			8,538			14,483
	–basis swaps		—		4,883			—			4,883
	–freight swaps		—		(561	)		—			(561	)
	–swaptions		—		—			(2,772	)		(2,772	)

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

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2018 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. As of December 31, 2018, a portion of our natural gas derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a predetermined date. Derivatives in Level 3 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

		Year Ended December 31, 2018
Balance at the beginning of period	$	6,658
Total gains (losses):
Included in earnings		5,766
Settlements received		(7,277	)
Transfers in and/or out of Level 3		619
Balance at end of period	$	5,766

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, 2018, interest and dividends were $1.1 million and mark-to-market was a loss of $7.9 million. For the year ended December 31, 2017, interest and dividends were $4.1 million and mark-to-market was a gain of $4.2 million. For the year ended December 31, 2016, interest and dividends were $972,000 and mark-to-market was a gain of $3.1 million.

Fair Values - Goodwill

During 2016, we recorded goodwill associated with the MRD Merger, which represented the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. Our policy is to first assess qualitative factors in order to determine whether fair value is more likely than not less than carrying value. Certain qualitative factors used in our evaluation include, among other things, the result of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions, industry and market conditions (including commodity prices and cost factors), overall financial performance and other relevant entity-specific events. If, after considering these events and circumstances, we determine that it is more likely than not that the fair value is less than carrying value, a quantitative goodwill test is performed. As of November 1, 2018, we performed our annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount. Based on the results of this assessment, we determined it was not likely that goodwill was impaired. However, since that qualitative assessment at November 1, 2018, our stock price declined significantly through December 31, 2018 when our stock price closed at $9.57 per share. At that time, we undertook a quantitative goodwill assessment. In this assessment, fair value is estimated based on a combination of a market capitalization and an income approach. The income approach is based on internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. The estimated market capitalization approach utilized a 20 day weighted average stock price and our common shares outstanding as of December 31, 2018. Management utilized the assistance of a third-party valuation expert to determine the fair value of our business. Two additional market approaches, the guideline public company multiple and the guideline transaction method were also utilized to corroborate the estimated fair value. As a result of this measurement, we recorded a $1.6 billion impairment of goodwill during fourth quarter 2018.

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 of our 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. During 2018, we increased our interest in certain properties in our shallow legacy oil and natural gas assets in Northwest Pennsylvania for a minimal dollar amount for which the fair value was previously determined to be zero. As a result, in 2018 we recorded additional impairment of $15.3 million related to these properties. In early 2018, there were indicators that the carrying value of certain of our oil and gas properties in Oklahoma may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. We recorded non-cash impairment charges of $7.3 million related to these properties. We recorded non-cash impairment charges during the year ended 2017 of $63.7 million related to certain of our oil and gas properties in Oklahoma and the Texas Panhandle. We recorded non-cash impairment charges during 2016 of $43.0 million related to certain of our natural gas and oil properties in Western Oklahoma. 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,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	32,516	$	22,614	$	85,597	$	63,679	$	90,150	$	43,040

Fair Values-Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2018 and 2017 (in thousands):

	December 31, 2018						December 31, 2017
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	92,795		$	92,795		$	58,880		$	58,880
Marketable securities ^(a)		57,293			57,293			67,117			67,117
(Liabilities):
Commodity swaps, options and basis swaps		(7,606	)		(7,606	)		(54,022	)		(54,022	)
Bank credit facility ^(b)		(943,000	)		(943,000	)		(1,211,000	)		(1,211,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(455,972	)		(475,952	)		(493,872	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(519,343	)		(580,032	)		(578,727	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(305,989	)		(329,244	)		(339,200	)
Other senior notes due 2022 ^(b)		(590	)		(581	)		(590	)		(591	)
5.00% senior notes due 2023 ^(b)		(741,531	)		(654,683	)		(741,531	)		(735,614	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(616,313	)		(750,000	)		(733,755	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(21,638	)		(22,214	)		(22,192	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(17,072	)		(19,054	)		(18,741	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(6,690	)		(7,712	)		(7,614	)
Deferred compensation plan ^(c)		(80,092	)		(80,092	)		(114,414	)		(114,414	)

^(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, 2018

Stock-based Compensation Plans

(12)	Stock-Based Compensation Plans

Description of the Plans

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

Total Stock-Based Compensation Expense

Stock-based compensation expense represents amortization of restricted stock and performance units. The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2018 (in thousands):

	2018		2017 ⁽¹⁾			2016
Direct operating expense	$	2,109		$	2,060		$	2,302
Brokered natural gas and marketing expense		1,452			1,437			1,725
Exploration expense		1,921			2,742			2,298
General and administrative expense		43,806			74,873			49,293
Termination costs		—			1,664			—
Total	$	49,288		$	82,776		$	55,618

⁽¹⁾

Includes $30.8 million accelerated vesting of equity grants.

In fourth quarter 2017, the compensation committee approved a new post-retirement benefit plan (See Other Post Retirement Benefits below). Along with establishing the new health care benefit plan for certain officers that have met the required age and service requirements and with the intention of improving our management succession plan, those officers who qualify for the new post-retirement health care plan were fully vested in all equity grants. The one-time impact of the acceleration of these equity grants was $30.8 million in fourth quarter 2017. Effective October 2018, officers who qualify for the new post-retirement health care plan are required to provide reasonable notice of retirement and beginning in 2019 are fully vested after one year of service after grant date.

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

In 2018, we recorded $3.6 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested in the year compared to $5.3 million in 2017 and $5.7 million in 2016.

Stock-Based Awards

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

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

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

At grant date, each unit represents the value of one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can be from zero to 200% based on the performance achieved and (2) the value of our common stock on the date vesting is determined by the Compensation Committee. Dividend equivalents may accrue during the performance period and would be paid in stock at the end of the performance period. The performance period is a three-year period.

SARs. At December 31, 2018, there were 1,104 SARs outstanding.

Restricted Stock – Equity Awards

In 2018, we granted 1.8 million restricted stock Equity Awards to employees which generally vest over a three-year period compared to 888,000 in 2017 and 973,000 in 2016. We recorded compensation expense for these awards of $24.2 million in the year ended December 31, 2018 compared to $23.4 million in 2017 and $22.8 million in 2016. As of December 31, 2018, there was $25.8 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 years. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash.

Restricted Stock – Liability Awards

In 2018, we granted 891,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $15.30. This grant included 146,000 issued to non-employee directors which vest immediately and 745,000 to employees with vesting generally over a three-year period. In 2017, we granted 543,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $25.91. This grant included 90,000 issued to non-employee directors which vest immediately and 453,000 to employees with vesting generally over a three-year period. In 2016, we granted 540,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $35.92. This grant included 59,000 issued to non-employee directors which vest immediately and 481,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $11.7 million in the year ended December 31, 2018 compared to $30.4 million in 2017 and $18.6 million in 2016. Accelerated vesting compensation expense of $15.4 million is included in the year ended December 31, 2017. As of December 31, 2018, there was $2.4 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 amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $9.7 million in 2018 compared to $4.5 million in 2017 and $13.1 million in 2016. The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2018:

	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2015		436,764		$	59.74		308,737		$	65.80
Granted		973,491			28.51		540,128			35.92
Vested		(525,617	)		43.83		(374,328	)		51.40
Forfeited		(118,667	)		42.60		(49,519	)		40.33
Outstanding at December 31, 2016		765,971			33.62		425,018			43.48
Granted		888,326			32.61		543,438			25.91
Vested		(698,563	)		34.82		(908,912	)		33.71
Forfeited		(122,676	)		32.91		(4,342	)		31.10
Outstanding at December 31, 2017		833,058			31.64		55,202			32.26
Granted		1,834,883			16.98		891,350			15.30
Vested		(1,037,501	)		23.57		(738,073	)		16.34
Forfeited		(244,352	)		21.59		(23,900	)		19.76
Outstanding at December 31, 2018		1,386,088		$	20.04		184,579		$	15.65

Stock-Based Performance Units

Production Growth and Reserve Growth Awards. The PG-PSUs and RG-PSUs vest at the end of the three-year performance period. The performance metrics for each year are set by the compensation committee no later than March 31 of such year. If the performance metric for the applicable period is not met, then the portion is considered forfeited. The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December 31, 2018:


	Number of Units			Weighted Average Grant Date Fair Value of Range Stock
Outstanding at December 31, 2016	—		$	—
Units granted	122,921			25.53
Outstanding at December 31, 2017	122,921			25.53
Units granted ^(a)	440,938			15.22
Forfeited ^(b)	(27,061	)		23.03
Outstanding at December 31, 2018	536,798		$	15.61

^(a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 200% depending on achievement of specifically identified performance targets.

^(b) The first of three tranches of PG-PSUs granted in 2017 was forfeited as the performance metric was not met.

We recorded PG/RG-RSUs compensation expense of $5.4 million in the year ended December 31, 2018 compared to $1.8 million in the year ended December 31, 2017. Accelerated vesting compensation expense of $1.5 million is included in the year ended December 31, 2017. As of December 31, 2018, there was $427,000 of unrecognized compensation related these PSU awards to be recognized over a weighted average period of 1.7 years.

TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three-year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of PSUs granted during the years ended December 31, 2018, 2017 and 2016:

	Year Ended December 31, 2017
	2018			2017			2016
Risk-free interest rate		2.42	%		1.49	%		0.94	%
Expected annual volatility		48	%		44	%		49	%
Grant date fair value per unit	$	18.51		$	26.26		$	36.64

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

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2015		499,943		$	69.95
Granted ^(a)		413,959			36.64
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		871,299			55.29
Granted ^(a)		358,519			26.26
Vested and issued ^(b)		(85,461	)		86.23
Forfeited		(134,515	)		85.24
Outstanding at December 31, 2017		1,009,842			38.38
Granted ^(a)		329,486			18.51
Vested and issued ^(c⁾		(73,985	)		56.81
Forfeited		(197,457	)		55.46
Outstanding at December 31, 2018		1,067,886		$	27.81

^(a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 150% (for TSR-PSUs granted in 2016 and 2017) and may be between zero and 200% (for TSR-PSUs granted in 2018) of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

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

^(c) Includes 73,985 TSR-PSUs awards issued related to the 2015 performance period where the return on our common stock was the 46^th percentile for the February 2015 grant and the 36^th percentile for the May 2015 grant. The remaining 2015 awards are considered to be forfeited.

We recorded TSR-PSU compensation expense of $6.3 million in the year ended December 31, 2018 compared to $24.8 million in the year ended December 31, 2017 and $12.4 million in the year ended December 31, 2016. Accelerated vesting compensation expense of $13.0 million is included in the year ended December 31, 2017. As of December 31, 2018, there was $1.1 million of unrecognized compensation related to these PSU awards to be recognized over a weighted average period of 1.5 years.

SARs

Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2015		1,510,977		$	63.73
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600			69.08
Expired/forfeited		(620,821	)		62.29
Outstanding at December 31, 2017		382,779			76.54
Expired/forfeited		(381,675	)		75.97
Outstanding and exercisable at December 31, 2018		1,104		$	81.74

There were no SARs exercised in 2018, 2017 or 2016. As of December 31, 2018, all of the outstanding awards are exercisable at an exercise price of $81.74 with a weighted average remaining contractual life of less than one year and no aggregate intrinsic value. As of December 31, 2018, there was no recognized compensation cost related to these 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 2018, we contributed $5.8 million to the 401(k) Plan compared to $5.1 million in 2017 and $4.7 million in 2016. Employees have a variety of investment options in the 401(k) benefit plan.

Deferred Compensation Plan

Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market gain of $18.6 million in 2018 compared to a gain of $50.9 million in 2017 and a loss of $19.2 million in 2016. The Rabbi Trust held 2.6 million shares (2.4 million of vested shares) of Range stock at December 31, 2018 compared to 2.9 million (2.8 million of vested shares) at December 31, 2017.

Other Post Retirement Benefits

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

Change in Benefit Obligation	2018			2017

Benefit obligation at beginning of year	$	1,769		$	—
Prior service cost		—			1,769
Service cost		94			—
Interest cost		58			—
Actuarial gain		(526	)		—
Benefits paid		(40	)		—
Benefit obligation at end of year	$	1,355		$	1,769

Amounts recognized in the consolidated balance sheets:
Long-term liabilities	$	1,355		$	1,769

Components of Net Periodic Post Retirement Benefit Cost		2018			2017

Service cost	$	94		$	—
Interest cost		58			—
Amortization of prior service cost		369			—
Net periodic post retirement costs (recognized in general and administrative expense)	$	521		$	—

Other Changes in Benefit Obligations in Other Comprehensive Income (Loss)

Net gain	$	(526	)	$	—
Prior service cost		—			1,769
Amortization of prior service cost		(369	)		—
Total recognized in other comprehensive (loss) income	$	(895	)	$	1,769
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$	(374	)	$	1,769

The following summarizes the assumptions used to determine the benefit obligation at December 31, 2018 and 2017:

	December 31, 2018			December 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate		4.0	%		3.3	%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate		6.5	%		7.0	%
Ultimate trend rate		5.0	%		5.0	%
Year ultimate trend rate reached		2028			2028

The expected future benefit payments under our post retirement benefit plan for the next ten years is $497,000 for the five year period 2019 through 2023 and $534,000 for the five year period 2024 through 2028. The estimated prior service cost that will be amortized from accumulated other comprehensive (loss) income into our statement of operations in 2019 is $369,000.

Capital Stock

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Capital Stock

(13)	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 2016:


	Year Ended December 31,
	2018		2017		2016
Beginning balance		248,129,430		247,144,356		169,316,460
MRD Merger		—		—		77,042,749
Restricted stock grants		865,095		539,096		490,609
Restricted stock units vested		434,046		344,937		266,541
Performance stock units issued		76,149		85,461		—
Shares retired		—		—		(739	)
Treasury shares		5,302		15,580		28,736
Ending balance		249,510,022		248,129,430		247,144,356

Common Stock Dividends

The board of directors declared quarterly dividends of $0.02 per common share for each of the four quarters of 2018, 2017 and 2016. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

(14)	Supplemental Cash Flow Information

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Net cash provided from operating activities included:
Income taxes refunded from taxing authorities	$	7,521		$	1,024		$	102
Interest paid		(207,433	)		(179,431	)		(159,875	)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	28,826		$	20,245		$	(24,064	)
(Decrease) increase in accrued capital expenditures		(119,021	)		71,739			61,419

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

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 including, but not limited to, royalty claims, contract claims and environmental claims. 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.

When deemed necessary, we established reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that include the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible we could incur additional losses with respect to those matters in which reserves have been established.

Lease Commitments

We lease office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. We have subleased part of the office space included in our operating leases for which we receive rental payments. Rent expense under operating leases (including renewable monthly leases) totaled $19.3 million in 2018 compared to $19.1 million in 2017 and $14.0 million in 2016. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):

	Operating Lease Obligations		Sublease Rental Receipts
2019	$	14,669	$	1,876
2020		14,080		1,696
2021		11,801		1,334
2022		7,217		111
2023		6,747		—
Thereafter		22,001		—
	$	76,515	$	5,017

Transportation, Gathering and Processing Contracts

We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of December 31, 2018, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands):

	Transportation, Gathering and Processing Contracts ^(a)
2019	$	960,000
2020		905,162
2021		878,205
2022		834,506
2023		798,629
Thereafter		5,854,692
	$	10,231,194

^(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 modifications and/or construction. The largest agreement has a ten-year term and is expected to begin in 2019. Based on this contract, we will have additional gathering obligations for natural gas volumes of 350,000 mcf per day until 2029. We also have an agreement which has a five-year term, which is expected to begin in 2020, for additional NGLs transportation of 20,000 bbls per day until March 2025.

Delivery Commitments

We have various volume delivery commitments that are related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2018, our delivery commitments through 2031 were as follows:

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2019		347,935	74,000
2020		292,845	71,492
2021		138,011	55,932
2022		83,535	43,000
2023		2,628	35,000
2024—2028		—	35,000
2029—2031		—	20,000

In addition to the amounts included in the above table, we have contracted with a pipeline company through 2035 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 3,000 bbls per day starting in 2021 and increasing to 10,000 bbls per day through 2035. 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 215,000 mcf per day starting in late 2020, decreasing to 151,000 mcf per day in 2024 and decreasing to 100,000 mcf per day in 2026 through early 2029.

Other

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

Office Closing and Exit Costs

12 Months Ended

Dec. 31, 2018

Restructuring And Related Activities [Abstract]

Office Closing and Exit Costs

(16)	Office Closing and Exit Costs

As part of a continuing effort to reduce our general and administrative expenses due to the lower commodity price environment, additional accruals for severance of $2.2 million and accelerated vesting of stock-based compensation of $1.7 million were recorded in the year ended December 31, 2017. The following table details the accrued liability as of December 31, 2018 and December 31, 2017 (in thousands):

		2018			2017
Beginning balance	$	1,855		$	2,460
Accrued severance costs		(356	)		2,176
Accrued building rent		(17	)		(70	)
Payments		(1,482	)		(2,711	)
Ending balance	$	—		$	1,855

The following summarizes our termination costs for three years ended December 31, 2018, 2017 and 2016 (in thousands):

		2018			2017			2016
Severance costs	$	(356	)	$	2,176		$	(822)
Building lease		(17	)		(70	)		303
Stock-based compensation		—			1,664			—
Total termination costs	$	(373	)	$	3,770		$	(519)

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2018

Suspended Exploratory Well Costs

(17)	Suspended Exploratory Well Costs

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2018, 2017 and 2016 (in thousands, except for number of projects):

	2018		2017			2016
Balance at beginning of period	$	—	$	7,412		$	4,161
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		1,388			9,128
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—		—			(5,877	)
Capitalized exploratory well costs charged to expense		—		(8,800	)		—
Balance at end of period		—		—			7,412
Less exploratory well costs that have been capitalized for a period of one year or less		—		—			(7,412	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	—	$	—		$	—
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		—		—			—

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

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. Fourth quarter 2018 includes goodwill impairment expense of $1.6 billion and unproved impairment expense of $441.8 million. Third quarter 2017 includes impairment expense of $63.7 million related to oil and gas properties in Oklahoma and Texas. Fourth quarter 2017 deferred income tax benefit includes the impact of the 2017 Tax Act which was signed into law on December 22, 2017.

	2018
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	696,629		$	661,390		$	736,431		$	756,627		$	2,851,077
Derivative fair value (loss) income		(14,009	)		(103,290	)		(34,591	)		100,698			(51,192	)
Brokered natural gas, marketing and other		59,979			98,084			109,385			215,312			482,760
Total revenue and other income		742,599			656,184			811,225			1,072,637			3,282,645
Costs and expenses:
Direct operating		38,122			35,088			30,926			35,395			139,531
Transportation, gathering, processing and compression		244,628			269,910			304,562			298,716			1,117,816
Production and ad valorem taxes		9,926			10,140			9,427			16,656			46,149
Brokered natural gas and marketing		55,594			102,747			116,080			221,626			496,047
Exploration		7,719			7,499			8,299			10,600			34,117
Abandonment and impairment of unproved properties		11,773			54,922			6,549			441,750			514,994
General and administrative		68,417			47,583			43,722			50,090			209,812
Termination costs		(37	)		—			(336	)		—			(373	)
Deferred compensation plan		(7,397	)		6,615			223			(18,072	)		(18,631	)
Interest		52,385			53,862			54,801			49,161			210,209
Depletion, depreciation and amortization		162,266			161,026			164,266			147,909			635,467
Impairment of proved properties and other		7,312			15,302			—			—			22,614
Impairment of goodwill		—			—			—			1,641,197			1,641,197
(Gain) loss on sale of assets		(23	)		(156	)		30			10,815			10,666
Total costs and expenses		650,685			764,538			738,549			2,905,843			5,059,615

Income (loss) before income taxes		91,914			(108,354	)		72,676			(1,833,206	)		(1,776,970	)
Income tax expense (benefit):
Current		—			—			—			—			—
Deferred		42,676			(28,518	)		24,137			(68,784	)		(30,489	)
		42,676			(28,518	)		24,137			(68,784	)		(30,489	)
Net income (loss)	$	49,238		$	(79,836	)	$	48,539		$	(1,764,422	)	$	(1,746,481	)
Net income (loss) per common share:
Basic	$	0.20		$	(0.32	)	$	0.19		$	(7.15	)	$	(7.10	)
Diluted	$	0.20		$	(0.32	)	$	0.19		$	(7.15	)	$	(7.10	)

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

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

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

12 Months Ended

Dec. 31, 2018

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,
	2018			2017			2016
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	10,974,929		$	10,572,453		$	9,462,350
Unproved properties		2,110,277			2,644,000			2,923,803
Total		13,085,206			13,216,453			12,386,153
Accumulated depreciation, depletion and amortization		(4,062,021	)		(3,649,716	)		(3,129,816	)
Net capitalized costs	$	9,023,185		$	9,566,737		$	9,256,337

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

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

	December 31,
	2018		2017		2016
	(in thousands)
Acquisitions
Acreage purchases	$	62,390	$	62,075	$	33,142
Oil and gas properties		1,683		18,269		3,098,772
Asset retirement obligations and other		—		—		21,908
Development		834,552		1,177,526		497,795
Exploration:
Drilling		1,380		2,030		37,680
Expense		32,196		50,920		30,027
Stock-based compensation expense		1,921		2,742		2,298
Gas gathering facilities:
Development		10,218		15,097		3,595
Subtotal		944,340		1,328,659		3,725,217
Asset retirement obligations		28,826		20,245		(24,064	)
Total costs incurred	$	973,166	$	1,348,904	$	3,701,153

^(a)

Includes cost incurred whether capitalized or expensed.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2018, 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, 2018, our consultants collectively audited approximately 94% 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 President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than thirty-five years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Estimated Quantities of Proved Oil and Gas Reserves

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

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

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

The average realized prices used at December 31, 2018 to estimate reserve information were $59.96 per barrel of oil, $25.22 per barrel of NGLs and $2.98 per mcf for gas using a benchmark (NYMEX) of $65.55 per barrel and $3.10 per Mmbtu. The average realized prices used at December 31, 2017 to estimate reserve information were $45.73 per barrel of oil, $17.84 per barrel of NGLs and $2.60 per mcf for gas using a benchmark (NYMEX) of $51.19 per barrel and $2.98 per Mmbtu. The average realized prices used at December 31, 2016 to estimate reserve information were $37.41 per barrel of oil, $13.44 per barrel of NGLs and $2.07 per mcf for gas using a benchmark (NYMEX) of $42.68 per barrel and $2.48 per Mmbtu.


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) ^(a)
Proved developed and undeveloped reserves:
Balance, December 31, 2015		6,277,697			549,135			53,193			9,891,663
Revisions		(7,441	)		41,402			2,471			255,794
Extensions, discoveries and additions		1,193,154			26,991			6,506			1,394,134
Purchases		943,544			40,724			11,986			1,259,806
Property sales		(160,727	)		(360	)		(295	)		(164,655	)
Production		(375,811	)		(27,826	)		(3,609	)		(564,420	)
Balance, December 31, 2016		7,870,416			630,066			70,252			12,072,322
Revisions		70,222			83,338			(10,555	)		506,919
Extensions, discoveries and additions		2,866,103			87,572			15,997			3,487,519
Purchases		7,738			330			66			10,116
Property sales		(60,278	)		(2,356	)		(1,121	)		(81,133	)
Production		(490,552	)		(35,686	)		(4,785	)		(733,382	)
Balance, December 31, 2017		10,263,649			763,264			69,854			15,262,361
Revisions		178,595			84,993			7,197			731,735
Extensions, discoveries and additions		2,269,427			128,436			17,309			3,143,898
Purchases		—			—			—			—
Property sales		(135,884	)		(16,774	)		(4,276	)		(262,180	)
Production		(548,085	)		(38,325	)		(4,228	)		(803,408	)
Balance, December 31, 2018		12,027,702			921,594			85,856			18,072,406
Proved developed reserves:
December 31, 2016		4,352,141			363,852			39,110			6,769,908
December 31, 2017		5,437,674			448,258			36,808			8,348,074
December 31, 2018		6,451,012			512,318			38,658			9,756,870
Proved undeveloped reserves:
December 31, 2016		3,518,275			266,214			31,143			5,302,414
December 31, 2017		4,825,975			315,006			33,046			6,914,287
December 31, 2018		5,576,690			409,276			47,198			8,315,536

^(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 between oil and natural gas prices.

During 2018, we added approximately 3.1 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 72% of the 2018 reserve additions are attributable to natural gas. Included in 2018 proved reserves is a total of 468.9 Mmbbls of ethane reserves (2,075 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 732 Bcfe include positive pricing and performance revisions of 957 Bcfe and unproved recoveries of 154 Bcfe which were partially offset by 379 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon.

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

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

The following details the changes in proved undeveloped reserves for 2018 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2017	6,914,287
Undeveloped reserves transferred to developed	(1,804,643	)
Revisions^(a)	608,252
Purchases/(sales)	(127,601	)
Extension and discoveries	2,725,240
Ending proved undeveloped reserves at December 31, 2018	8,315,535

^(a) Includes 379 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 $623.3 million was spent during 2018 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $3.3 billion over the next five years. As of December 31, 2018, we have no reserves that have been reported for more than five years from their original date of booking. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2023.

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 2018, 2017 and 2016, 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,
	2018			2017
	(in thousands)
Future cash inflows	$	64,287,737		$	43,500,054
Future costs:
Production		(25,626,373	)		(18,958,695	)
Development^(a)		(3,824,936	)		(3,072,688	)
Future net cash flows before income taxes		34,836,428			21,468,671
Future income tax expense		(7,285,274	)		(3,989,459	)
Total future net cash flows before 10% discount		27,551,154			17,479,212
10% annual discount		(16,435,560	)		(10,313,998	)
Standardized measure of discounted future net cash flows	$	11,115,594		$	7,165,214

^(a) 2018 includes $494.5 million of undiscounted future asset retirement costs estimated as of December 31, 2018, using current estimates of future abandonment costs.

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

	December 31,
	2018			2017			2016
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	2,959,488		$	2,615,825		$	(212,867	)
Revisions in quantities		667,763			445,667			96,615
Changes in future development and abandonment costs		(557,518	)		(497,400	)		(314,864	)
Net change in income taxes		(1,075,867	)		(706,531	)		27,842
Accretion of discount		814,725			372,743			302,920
Purchases of reserves in place		—			6,173			488,959
Additions to proved reserves from extensions, discoveries and improved recovery		2,543,296			2,128,135			541,095
Natural gas, NGLs and oil sales, net of production costs		(1,547,580	)		(1,237,970	)		(509,174	)
Development costs incurred during the period		722,074			885,803			435,928
Sales of reserves in place		(226,953	)		(32,946	)		(65,538	)
Timing and other		(349,048	)		(266,214	)		(64,850	)
Net change for the year		3,950,380			3,713,285			726,066
Beginning of year		7,165,214			3,451,929			2,725,863
End of year	$	11,115,594		$	7,165,214		$	3,451,929

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

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

Use of Estimates

Business Segment Information

Revenue Recognition, Accounts Receivable and Gas Imbalances

Natural Gas and NGLs Sales

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

•

Brokered Natural Gas, Marketing and Other

Cash and Cash Equivalents

Marketable Securities

Inventory

Goodwill

In fourth quarter 2018, we determined goodwill was fully impaired and recorded an impairment charge of $1.6 billion. For more information, see Note 11.

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

Recently Adopted

Pension Accounting Standard

Modification of Share – Based Awards

Revenue Recognition Standard

	Year Ended December 31, 2018
	As Reported					Previous Revenue Recognition Method
		$			$ Per mcfe		$			$ Per mcfe		Increase		$ Per mcfe
Revenues:
Natural gas, NGLs and oil sales	$	2,851,077		$	3.55	$	2,678,278		$	3.33	$	172,799	$	0.22
Costs and expenses:
Transportation, gathering, processing and compression	$	1,117,816		$	1.39	$	945,017		$	1.17	$	172,799	$	0.22
Net loss	$	(1,746,481	)			$	(1,746,481	)			$	—

Goodwill Standard

Inventory Standard

Classification in the Statement of Cash Flows

Definition of a Business

Share-Based Payment Awards

Not Yet Adopted

Lease Accounting Standard

•

a package of practical expedients to not reassess whether a contract contains a lease, lease classification and initial direct costs; and

•

a practical expedient to not reassess certain land easements in existence prior to January 1, 2019.

We have not yet determined the extent of the adjustments that will be required upon implementation of this new standards update.

Financial Instruments – Credit Losses

Fair Value Measurement

Accounting Standards (Tables)

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements And Changes In Accounting Principles [Abstract]

Schedule of Impact of Adoption of New Revenue Recognition Standard

The impact of adoption of the new revenue recognition standard on our current period results is as follows (in thousands):

	Year Ended December 31, 2018
	As Reported					Previous Revenue Recognition Method
		$			$ Per mcfe		$			$ Per mcfe		Increase		$ Per mcfe
Revenues:
Natural gas, NGLs and oil sales	$	2,851,077		$	3.55	$	2,678,278		$	3.33	$	172,799	$	0.22
Costs and expenses:
Transportation, gathering, processing and compression	$	1,117,816		$	1.39	$	945,017		$	1.17	$	172,799	$	0.22
Net loss	$	(1,746,481	)			$	(1,746,481	)			$	—

Revenues from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2018

Revenue From Contract With Customer [Abstract]

Disaggregation of Revenue by Identified Revenue Stream

Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

		Year Ended December 31, 2018
Natural gas sales ^(a)	$	2,137,573
NGLs sales ^(b)		940,378
Crude oil and condensate sales		255,885
Total	$	3,333,836

^(a)

Natural gas sales revenue reported above includes $460.3 million of brokered revenues and $13.4 million of marketing revenue.

^(b)

NGLs sales revenue reported above includes $9.0 million of brokered revenues.

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax


	Year Ended December 31,
	2018		2017			2016
Federal statutory tax rate	21.0	%		35.0	%		35.0	%
Federal rate change	—			(406.7	)		—
State	(0.3	)		(0.7	)		3.0
State rate and law change	0.9			(1.3	)		1.0
Non-deductible executive compensation	—			0.7			(0.2	)
Non-deductible MRD transaction costs	—			—			(0.6	)
Valuation allowances	(0.4	)		36.8			(2.5	)
Equity compensation	(0.1	)		30.2			(0.7	)
Goodwill impairment	(19.4	)		—			—
Other	—			0.3			—
Consolidated effective tax rate	1.7	%		(305.7	%)		35.0	%

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

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

		2018								2017										2016
		Current	Deferred			Total			Current		Deferred			Total				Current					Deferred			Total
U.S. federal	$	—	$	(25,322	)	$	(25,322	)	$	—	$	(302,507	)		$	(302,507	)		$		—	$		(266,105	)		$	(266,105	)
U.S. state and local		—		(5,167	)		(5,167	)		17		51,464				51,481					98			(14,743	)			(14,645	)
Total	$	—	$	(30,489	)	$	(30,489	)	$	17	$	(251,043	)		$	(251,026	)		$		98	$		(280,848	)		$	(280,750	)

Significant Components of Deferred Tax Assets and Liabilities

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

	December 31,
	2018			2017
	(in thousands)
Deferred tax assets:
Net operating loss carryforward	$	542,847		$	413,672
Deferred compensation		19,844			24,704
Equity compensation		8,152			5,269
AMT credits and other credits		3,296			7,264
Asset retirement obligation		78,126			69,398
Other		30,492			18,806
Valuation allowances:
Federal		(18,975	)		(31,308	)
State, net of federal benefit		(101,372	)		(93,826	)
Total deferred tax assets		562,410			413,979
Deferred tax liabilities:
Depreciation, depletion and investments		(1,207,784	)		(1,105,494	)
Cumulative mark-to-market gain		(21,294	)		(1,841	)
Other		—			—
Total deferred tax liabilities		(1,229,078	)		(1,107,335	)
Net deferred tax liability	$	(666,668	)	$	(693,356	)

Changes in Deferred Tax Asset Valuation Allowances

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

		2018			2017			2016
Balance at the beginning of the year	$	(125,134	)	$	(107,174	)	$	(87,623	)
Charged to provision for income taxes:
State net operating loss carryforwards		(23,926	)		(11,612	)		(17,374	)
Federal net operating carryforwards		11,716			15,385			(1,100	)
Other state valuation allowances		16,380			(23,790	)		500
Other federal valuation allowances		494			(247	)		(477	)
Other		123			2,304			(1,100	)
Balance at the end of the year	$	(120,347	)	$	(125,134	)	$	(107,174	)

Net Income (Loss) Per Common Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

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


	Year Ended December 31,
	2018			2017			2016
Net (loss) income, as reported	$	(1,746,481	)	$	333,146		$	(521,388	)
Participating basic earnings ^(a)		(245	)		(3,751	)		(223	)
Basic net (loss) income attributed to common stockholders		(1,746,726	)		329,395			(521,611	)
Reallocation of participating earnings ^(a)		—			5			—
Diluted net (loss) income attributed to common stockholders	$	(1,746,726	)	$	329,400		$	(521,611	)
Net (loss) income per common share:
Basic	$	(7.10	)	$	1.34		$	(2.75	)
Diluted	$	(7.10	)	$	1.34		$	(2.75	)

^(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,
	2018	2017		2016
Denominator:
Weighted average common shares outstanding – basic ⁽¹⁾	246,171		245,091		189,868
Effect of dilutive securities:
Director and employee restricted stock and performance-based equity awards	—		367		—
Weighted average common shares outstanding – diluted	246,171		245,458		189,868

⁽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.

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt Outstanding


		December 31, 2018			December 31, 2017
Bank debt (4.1%)	$	943,000		$	1,211,000
Senior notes
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,531			741,531
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022		329,244			329,244
Other senior notes due 2022		590			590
Total senior notes		2,877,349			2,877,349
Senior subordinated notes
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		3,869,329			4,137,329
Unamortized premium		4,741			6,027
Unamortized debt issuance costs		(37,209	)		(34,550	)
Total debt (net of debt issuance costs)	$	3,836,861		$	4,108,806

Summary of Senior Notes Principal Subsequent to Debt Exchange

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

Schedule for Long-Term Debt Outstanding

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2018 (in thousands):

	Year Ended December 31,
2019	$	—
2020		—
2021		498,166
2022		928,920
2023		1,692,243
Thereafter		750,000
	$	3,869,329

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, 2018

Asset Retirement Obligation

The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2018 and 2017 (in thousands):


	2018			2017
Beginning of period	$	276,855		$	257,943
Liabilities incurred		3,376			7,724
Acquisitions		13,438			—
Liabilities settled		(5,052	)		(7,965	)
Disposition of wells		(13,332	)		(8,078	)
Accretion expense		25,456			14,711
Change in estimate		12,013			12,520
End of period		312,754			276,855
Less current portion		(5,485	)		(6,327	)
Long-term asset retirement obligations	$	307,269		$	270,528

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2019	Swaps	1,318,041 Mmbtu/day	$ 2.86
2019	Swaptions	113,014 Mmbtu/day	$ 2.81 ⁽¹⁾
2020	Swaptions	80,000 Mmbtu/day	$ 2.77 ⁽¹⁾

Crude Oil
2019	Swaps	7,000 bbls/day	$ 55.26
2020	Swaps	1,562 bbls/day	$ 61.05
2019	Collars	1,000 bbls/day	$ 63.00-$ 73.03

NGLs (C3-Propane)
January-June, 2019	Swaps	8,500 bbls/day	$ 0.92/gallon
January-June, 2019	Collars	3,983 bbls/day	$ 0.92-$ 1.02/gallon

NGLs (NC4-Normal Butane)
January-March, 2019	Swaps	2,250 bbls/day	$ 1.22/gallon

NGLs (C5-Natural Gasoline)
2019	Swaps	2,429 bbls/day	$ 1.44/gallon

Combined Fair Value of Derivatives, by Consolidated Balance Sheets

		December 31, 2018
		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	$	20,834	$	(11,748	)	$	9,086
	–swaptions		5,200		(3,883	)		1,317
	–basis swaps		6,468		(2,822	)		3,646
Crude oil	–swaps		26,481		(651	)		25,830
	–collars		5,945		(707	)		5,238
NGLs	–C3 propane swaps		18,719		(589	)		18,130
	–C3 propane collars		8,538		—			8,538
	–C3 propane spread swaps		8,984		(8,868	)		116
	–NC4 butane swaps		4,084		—			4,084
	–C5 natural gasoline swaps		17,371		—			17,371
Freight	–swaps		—		(561	)		(561	)
		$	122,624	$	(29,829	)	$	92,795

		December 31, 2018
		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	$	(18,332	)	$	11,748	$	(6,584	)
	–swaptions		(7,972	)		3,883		(4,089	)
	–basis swaps		(1,702	)		2,822		1,120
Crude oil	–swaps		—			651		651
	–collars		—			707		707
NGLs	–C3 propane swaps		—			589		589
	–C3 propane spread swaps		(8,868	)		8,868		—
Freight	–swaps		(561	)		561		—
		$	(37,435	)	$	29,829	$	(7,606	)

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

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

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 (Loss) Income
	2018			2017			2016
Commodity swaps	$	(57,950	)	$	181,095		$	(265,466	)
Swaptions		(6,556	)		6,534			—
Collars		17,583			18,132			(6,926	)
Basis swaps		(1,104	)		(4,647	)		29,154
Puts		—			10,929			(18,201	)
Calls		(2,653	)		987			(18	)
Freight swaps		(512	)		320			66
Total	$	(51,192	)	$	213,350		$	(261,391	)

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

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

		Fair Value Measurements at December 31, 2018 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, 2018
Trading securities held in the deferred compensation plans		$	57,293	$	—		$	—		$	57,293
Derivatives	–swaps		—		69,156			—			69,156
	–collars		—		5,945			8,538			14,483
	–basis swaps		—		4,883			—			4,883
	–freight swaps		—		(561	)		—			(561	)
	–swaptions		—		—			(2,772	)		(2,772	)

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

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

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

		Year Ended December 31, 2018
Balance at the beginning of period	$	6,658
Total gains (losses):
Included in earnings		5,766
Settlements received		(7,277	)
Transfers in and/or out of Level 3		619
Balance at end of period	$	5,766

Value of Assets Measured at Fair Value on Nonrecurring Basis

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

	Year Ended December 31,
	2018				2017				2016
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	32,516	$	22,614	$	85,597	$	63,679	$	90,150	$	43,040

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, 2018 and 2017 (in thousands):

	December 31, 2018						December 31, 2017
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	92,795		$	92,795		$	58,880		$	58,880
Marketable securities ^(a)		57,293			57,293			67,117			67,117
(Liabilities):
Commodity swaps, options and basis swaps		(7,606	)		(7,606	)		(54,022	)		(54,022	)
Bank credit facility ^(b)		(943,000	)		(943,000	)		(1,211,000	)		(1,211,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(455,972	)		(475,952	)		(493,872	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(519,343	)		(580,032	)		(578,727	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(305,989	)		(329,244	)		(339,200	)
Other senior notes due 2022 ^(b)		(590	)		(581	)		(590	)		(591	)
5.00% senior notes due 2023 ^(b)		(741,531	)		(654,683	)		(741,531	)		(735,614	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(616,313	)		(750,000	)		(733,755	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(21,638	)		(22,214	)		(22,192	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(17,072	)		(19,054	)		(18,741	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(6,690	)		(7,712	)		(7,614	)
Deferred compensation plan ^(c)		(80,092	)		(80,092	)		(114,414	)		(114,414	)

^(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, 2018

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, 2018 (in thousands):

	2018		2017 ⁽¹⁾			2016
Direct operating expense	$	2,109		$	2,060		$	2,302
Brokered natural gas and marketing expense		1,452			1,437			1,725
Exploration expense		1,921			2,742			2,298
General and administrative expense		43,806			74,873			49,293
Termination costs		—			1,664			—
Total	$	49,288		$	82,776		$	55,618

⁽¹⁾

Includes $30.8 million accelerated vesting of equity grants.

Restricted Stock and Restricted Stock Units Outstanding

The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2018:

	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2015		436,764		$	59.74		308,737		$	65.80
Granted		973,491			28.51		540,128			35.92
Vested		(525,617	)		43.83		(374,328	)		51.40
Forfeited		(118,667	)		42.60		(49,519	)		40.33
Outstanding at December 31, 2016		765,971			33.62		425,018			43.48
Granted		888,326			32.61		543,438			25.91
Vested		(698,563	)		34.82		(908,912	)		33.71
Forfeited		(122,676	)		32.91		(4,342	)		31.10
Outstanding at December 31, 2017		833,058			31.64		55,202			32.26
Granted		1,834,883			16.98		891,350			15.30
Vested		(1,037,501	)		23.57		(738,073	)		16.34
Forfeited		(244,352	)		21.59		(23,900	)		19.76
Outstanding at December 31, 2018		1,386,088		$	20.04		184,579		$	15.65

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, 2018, 2017 and 2016:

	Year Ended December 31, 2017
	2018			2017			2016
Risk-free interest rate		2.42	%		1.49	%		0.94	%
Expected annual volatility		48	%		44	%		49	%
Grant date fair value per unit	$	18.51		$	26.26		$	36.64

Summary of Change in Post Retirement Benefit Obligation

The change in our post retirement benefit obligation is as follows (in thousands):

Change in Benefit Obligation	2018			2017

Benefit obligation at beginning of year	$	1,769		$	—
Prior service cost		—			1,769
Service cost		94			—
Interest cost		58			—
Actuarial gain		(526	)		—
Benefits paid		(40	)		—
Benefit obligation at end of year	$	1,355		$	1,769

Amounts recognized in the consolidated balance sheets:
Long-term liabilities	$	1,355		$	1,769

Components of Net Periodic Post Retirement Benefit Cost		2018			2017

Service cost	$	94		$	—
Interest cost		58			—
Amortization of prior service cost		369			—
Net periodic post retirement costs (recognized in general and administrative expense)	$	521		$	—

Other Changes in Benefit Obligations in Other Comprehensive Income (Loss)

Net gain	$	(526	)	$	—
Prior service cost		—			1,769
Amortization of prior service cost		(369	)		—
Total recognized in other comprehensive (loss) income	$	(895	)	$	1,769
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$	(374	)	$	1,769

Summary of Assumptions Used to Determine Benefit Obligation

The following summarizes the assumptions used to determine the benefit obligation at December 31, 2018 and 2017:

	December 31, 2018			December 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate		4.0	%		3.3	%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate		6.5	%		7.0	%
Ultimate trend rate		5.0	%		5.0	%
Year ultimate trend rate reached		2028			2028

Stock Option and SARs Activities

Information with respect to our SARs activities is summarized below.

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2015		1,510,977		$	63.73
Expired/forfeited		(507,377	)		53.16
Outstanding at December 31, 2016		1,003,600			69.08
Expired/forfeited		(620,821	)		62.29
Outstanding at December 31, 2017		382,779			76.54
Expired/forfeited		(381,675	)		75.97
Outstanding and exercisable at December 31, 2018		1,104		$	81.74

Performance-based PG-PSUs and RG-PSUs

Summary of Non-Vested Awards Activities

The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December 31, 2018:


	Number of Units			Weighted Average Grant Date Fair Value of Range Stock
Outstanding at December 31, 2016	—		$	—
Units granted	122,921			25.53
Outstanding at December 31, 2017	122,921			25.53
Units granted ^(a)	440,938			15.22
Forfeited ^(b)	(27,061	)		23.03
Outstanding at December 31, 2018	536,798		$	15.61

^(b) The first of three tranches of PG-PSUs granted in 2017 was forfeited as the performance metric was not met.

Performance Based TSR - PSUs

Summary of Non-Vested Awards Activities

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

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2015		499,943		$	69.95
Granted ^(a)		413,959			36.64
Forfeited		(42,603	)		46.09
Outstanding at December 31, 2016		871,299			55.29
Granted ^(a)		358,519			26.26
Vested and issued ^(b)		(85,461	)		86.23
Forfeited		(134,515	)		85.24
Outstanding at December 31, 2017		1,009,842			38.38
Granted ^(a)		329,486			18.51
Vested and issued ^(c⁾		(73,985	)		56.81
Forfeited		(197,457	)		55.46
Outstanding at December 31, 2018		1,067,886		$	27.81

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Capital Stock

The following is a schedule of changes in the number of common shares outstanding since the beginning of 2016:


	Year Ended December 31,
	2018		2017		2016
Beginning balance		248,129,430		247,144,356		169,316,460
MRD Merger		—		—		77,042,749
Restricted stock grants		865,095		539,096		490,609
Restricted stock units vested		434,046		344,937		266,541
Performance stock units issued		76,149		85,461		—
Shares retired		—		—		(739	)
Treasury shares		5,302		15,580		28,736
Ending balance		249,510,022		248,129,430		247,144,356

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Net cash provided from operating activities included:
Income taxes refunded from taxing authorities	$	7,521		$	1,024		$	102
Interest paid		(207,433	)		(179,431	)		(159,875	)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	28,826		$	20,245		$	(24,064	)
(Decrease) increase in accrued capital expenditures		(119,021	)		71,739			61,419

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments And Contingencies Disclosure [Abstract]

Future Minimum Rental Commitments

	Operating Lease Obligations		Sublease Rental Receipts
2019	$	14,669	$	1,876
2020		14,080		1,696
2021		11,801		1,334
2022		7,217		111
2023		6,747		—
Thereafter		22,001		—
	$	76,515	$	5,017

Schedule of Future Minimum Transportation Fees Due

	Transportation, Gathering and Processing Contracts ^(a)
2019	$	960,000
2020		905,162
2021		878,205
2022		834,506
2023		798,629
Thereafter		5,854,692
	$	10,231,194

Future Delivery Commitments

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane and Propane (bbls per day)
2019		347,935	74,000
2020		292,845	71,492
2021		138,011	55,932
2022		83,535	43,000
2023		2,628	35,000
2024—2028		—	35,000
2029—2031		—	20,000

Office Closing and Exit Costs (Tables)

12 Months Ended

Dec. 31, 2018

Restructuring And Related Activities [Abstract]

Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet

The following table details the accrued liability as of December 31, 2018 and December 31, 2017 (in thousands):

		2018			2017
Beginning balance	$	1,855		$	2,460
Accrued severance costs		(356	)		2,176
Accrued building rent		(17	)		(70	)
Payments		(1,482	)		(2,711	)
Ending balance	$	—		$	1,855

Summary of Termination Costs

The following summarizes our termination costs for three years ended December 31, 2018, 2017 and 2016 (in thousands):

		2018			2017			2016
Severance costs	$	(356	)	$	2,176		$	(822)
Building lease		(17	)		(70	)		303
Stock-based compensation		—			1,664			—
Total termination costs	$	(373	)	$	3,770		$	(519)

Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2018

Suspended Exploratory Well Costs

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2018, 2017 and 2016 (in thousands, except for number of projects):

	2018		2017			2016
Balance at beginning of period	$	—	$	7,412		$	4,161
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		1,388			9,128
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—		—			(5,877	)
Capitalized exploratory well costs charged to expense		—		(8,800	)		—
Balance at end of period		—		—			7,412
Less exploratory well costs that have been capitalized for a period of one year or less		—		—			(7,412	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	—	$	—		$	—
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		—		—			—

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

	2018
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	696,629		$	661,390		$	736,431		$	756,627		$	2,851,077
Derivative fair value (loss) income		(14,009	)		(103,290	)		(34,591	)		100,698			(51,192	)
Brokered natural gas, marketing and other		59,979			98,084			109,385			215,312			482,760
Total revenue and other income		742,599			656,184			811,225			1,072,637			3,282,645
Costs and expenses:
Direct operating		38,122			35,088			30,926			35,395			139,531
Transportation, gathering, processing and compression		244,628			269,910			304,562			298,716			1,117,816
Production and ad valorem taxes		9,926			10,140			9,427			16,656			46,149
Brokered natural gas and marketing		55,594			102,747			116,080			221,626			496,047
Exploration		7,719			7,499			8,299			10,600			34,117
Abandonment and impairment of unproved properties		11,773			54,922			6,549			441,750			514,994
General and administrative		68,417			47,583			43,722			50,090			209,812
Termination costs		(37	)		—			(336	)		—			(373	)
Deferred compensation plan		(7,397	)		6,615			223			(18,072	)		(18,631	)
Interest		52,385			53,862			54,801			49,161			210,209
Depletion, depreciation and amortization		162,266			161,026			164,266			147,909			635,467
Impairment of proved properties and other		7,312			15,302			—			—			22,614
Impairment of goodwill		—			—			—			1,641,197			1,641,197
(Gain) loss on sale of assets		(23	)		(156	)		30			10,815			10,666
Total costs and expenses		650,685			764,538			738,549			2,905,843			5,059,615

Income (loss) before income taxes		91,914			(108,354	)		72,676			(1,833,206	)		(1,776,970	)
Income tax expense (benefit):
Current		—			—			—			—			—
Deferred		42,676			(28,518	)		24,137			(68,784	)		(30,489	)
		42,676			(28,518	)		24,137			(68,784	)		(30,489	)
Net income (loss)	$	49,238		$	(79,836	)	$	48,539		$	(1,764,422	)	$	(1,746,481	)
Net income (loss) per common share:
Basic	$	0.20		$	(0.32	)	$	0.19		$	(7.15	)	$	(7.10	)
Diluted	$	0.20		$	(0.32	)	$	0.19		$	(7.15	)	$	(7.10	)

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

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

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

12 Months Ended

Dec. 31, 2018

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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

	December 31,
	2018			2017			2016
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	10,974,929		$	10,572,453		$	9,462,350
Unproved properties		2,110,277			2,644,000			2,923,803
Total		13,085,206			13,216,453			12,386,153
Accumulated depreciation, depletion and amortization		(4,062,021	)		(3,649,716	)		(3,129,816	)
Net capitalized costs	$	9,023,185		$	9,566,737		$	9,256,337

^(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,
	2018		2017		2016
	(in thousands)
Acquisitions
Acreage purchases	$	62,390	$	62,075	$	33,142
Oil and gas properties		1,683		18,269		3,098,772
Asset retirement obligations and other		—		—		21,908
Development		834,552		1,177,526		497,795
Exploration:
Drilling		1,380		2,030		37,680
Expense		32,196		50,920		30,027
Stock-based compensation expense		1,921		2,742		2,298
Gas gathering facilities:
Development		10,218		15,097		3,595
Subtotal		944,340		1,328,659		3,725,217
Asset retirement obligations		28,826		20,245		(24,064	)
Total costs incurred	$	973,166	$	1,348,904	$	3,701,153

^(a)

Includes cost incurred whether capitalized or expensed.

Proved Developed and Undeveloped Reserves


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) ^(a)
Proved developed and undeveloped reserves:
Balance, December 31, 2015		6,277,697			549,135			53,193			9,891,663
Revisions		(7,441	)		41,402			2,471			255,794
Extensions, discoveries and additions		1,193,154			26,991			6,506			1,394,134
Purchases		943,544			40,724			11,986			1,259,806
Property sales		(160,727	)		(360	)		(295	)		(164,655	)
Production		(375,811	)		(27,826	)		(3,609	)		(564,420	)
Balance, December 31, 2016		7,870,416			630,066			70,252			12,072,322
Revisions		70,222			83,338			(10,555	)		506,919
Extensions, discoveries and additions		2,866,103			87,572			15,997			3,487,519
Purchases		7,738			330			66			10,116
Property sales		(60,278	)		(2,356	)		(1,121	)		(81,133	)
Production		(490,552	)		(35,686	)		(4,785	)		(733,382	)
Balance, December 31, 2017		10,263,649			763,264			69,854			15,262,361
Revisions		178,595			84,993			7,197			731,735
Extensions, discoveries and additions		2,269,427			128,436			17,309			3,143,898
Purchases		—			—			—			—
Property sales		(135,884	)		(16,774	)		(4,276	)		(262,180	)
Production		(548,085	)		(38,325	)		(4,228	)		(803,408	)
Balance, December 31, 2018		12,027,702			921,594			85,856			18,072,406
Proved developed reserves:
December 31, 2016		4,352,141			363,852			39,110			6,769,908
December 31, 2017		5,437,674			448,258			36,808			8,348,074
December 31, 2018		6,451,012			512,318			38,658			9,756,870
Proved undeveloped reserves:
December 31, 2016		3,518,275			266,214			31,143			5,302,414
December 31, 2017		4,825,975			315,006			33,046			6,914,287
December 31, 2018		5,576,690			409,276			47,198			8,315,536

^(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 between oil and natural gas prices.

Changes in Proved Undeveloped Reserves

The following details the changes in proved undeveloped reserves for 2018 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2017	6,914,287
Undeveloped reserves transferred to developed	(1,804,643	)
Revisions^(a)	608,252
Purchases/(sales)	(127,601	)
Extension and discoveries	2,725,240
Ending proved undeveloped reserves at December 31, 2018	8,315,535

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2018			2017
	(in thousands)
Future cash inflows	$	64,287,737		$	43,500,054
Future costs:
Production		(25,626,373	)		(18,958,695	)
Development^(a)		(3,824,936	)		(3,072,688	)
Future net cash flows before income taxes		34,836,428			21,468,671
Future income tax expense		(7,285,274	)		(3,989,459	)
Total future net cash flows before 10% discount		27,551,154			17,479,212
10% annual discount		(16,435,560	)		(10,313,998	)
Standardized measure of discounted future net cash flows	$	11,115,594		$	7,165,214

^(a) 2018 includes $494.5 million of undiscounted future asset retirement costs estimated as of December 31, 2018, 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,
	2018			2017			2016
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	2,959,488		$	2,615,825		$	(212,867	)
Revisions in quantities		667,763			445,667			96,615
Changes in future development and abandonment costs		(557,518	)		(497,400	)		(314,864	)
Net change in income taxes		(1,075,867	)		(706,531	)		27,842
Accretion of discount		814,725			372,743			302,920
Purchases of reserves in place		—			6,173			488,959
Additions to proved reserves from extensions, discoveries and improved recovery		2,543,296			2,128,135			541,095
Natural gas, NGLs and oil sales, net of production costs		(1,547,580	)		(1,237,970	)		(509,174	)
Development costs incurred during the period		722,074			885,803			435,928
Sales of reserves in place		(226,953	)		(32,946	)		(65,538	)
Timing and other		(349,048	)		(266,214	)		(64,850	)
Net change for the year		3,950,380			3,713,285			726,066
Beginning of year		7,165,214			3,451,929			2,725,863
End of year	$	11,115,594		$	7,165,214		$	3,451,929

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) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Net brokered margin gain (losses)					$ (16,300,000)	$ (5,700,000)	$ (2,800,000)
Allowance for doubtful accounts on accounts receivable	$ 6,118,000				6,118,000	7,111,000
Bad debt (income) expense					(1,000,000)	1,550,000	800,000
Inventory and other	22,964,000				22,964,000	21,346,000
Goodwill from MRD merger							1,700,000,000
Purchase adjustment, decrease in goodwill						13,100,000
Goodwill impairment charge	1,641,197,000	$ 0	$ 0	$ 0	1,641,197,000	0	$ 0
Materials and supplies inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory and other	8,000,000				8,000,000	12,100,000
Commodity inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory and other	$ 965,000				$ 965,000	$ 508,000

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net book value of unproved properties

^[1]

$ 2,110,277,000

$ 2,644,000,000

$ 2,110,277,000

$ 2,644,000,000

$ 2,923,803,000

Abandonment and impairment of unproved properties

441,750,000

$ 6,549,000

$ 54,922,000

$ 11,773,000

217,544,000

$ 42,568,000

$ 5,193,000

$ 4,420,000

514,994,000

269,725,000

30,076,000

Depreciation expense

6,000,000

7,700,000

8,400,000

Marketable securities held in deferred compensation plans

57,300,000

67,100,000

57,300,000

67,100,000

Other investments including surface acreage

$ 9,100,000

$ 9,600,000

9,100,000

9,600,000

MRD Merger

Summary Of Significant Accounting Policies [Line Items]

Abandonment and impairment of unproved properties

436,000,000

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

$ 9,800,000

$ 158,000

$ 1,900,000

Other property and equipment | Minimum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

3 years

Other property and equipment | Maximum

Summary Of Significant Accounting Policies [Line Items]

Useful life of assets

10 years

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

Summary of Significant Accounting Policies - Additional Information 2 (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) Customer Counterparty	Dec. 31, 2017 USD ($) Customer	Dec. 31, 2016 Customer
Accounting Policies [Abstract]
Allowance for doubtful accounts on accounts receivable \| $	$ 6,118	$ 7,111
Number of customers accounted more than 10% of total oil and gas revenues \| Customer	1	1	1
Net derivative asset \| $	$ 9,700
Number of counterparties \| Counterparty	4
Number of financial institutions included in counter parties \| Counterparty	20

Accounting Standards - Schedule of Impact of Adoption of New Revenue Recognition Standard (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) $ / Mcfe	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Revenues:
Revenues									$ 3,333,836
Natural gas, NGLs and oil sales \| $ / Mcfe									3.55
Costs and expenses:
Transportation, gathering, processing and compression \| $ / Mcfe									1.39
Net loss	$ (1,764,422)	$ 48,539	$ (79,836)	$ 49,238	$ 221,185	$ (127,700)	$ 69,550	$ 170,111	$ (1,746,481)	$ 333,146	$ (521,388)
Accounting Standards Update 2014-09 \| Previous Revenue Recognition
Revenues:
Natural gas, NGLs and oil sales \| $ / Mcfe									3.33
Costs and expenses:
Transportation, gathering, processing and compression \| $ / Mcfe									1.17
Net loss									$ (1,746,481)
Accounting Standards Update 2014-09 \| Increase
Revenues:
Natural gas, NGLs and oil sales \| $ / Mcfe									0.22
Costs and expenses:
Transportation, gathering, processing and compression \| $ / Mcfe									0.22
Natural Gas, NGLs and Oil Sales
Revenues:
Revenues	756,627	736,431	661,390	696,629	603,159	507,541	506,137	559,450	$ 2,851,077	2,176,287	1,197,215
Natural Gas, NGLs and Oil Sales \| Accounting Standards Update 2014-09 \| Previous Revenue Recognition
Revenues:
Revenues									2,678,278
Natural Gas, NGLs and Oil Sales \| Accounting Standards Update 2014-09 \| Increase
Revenues:
Revenues									172,799
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 298,716	$ 304,562	$ 269,910	$ 244,628	$ 200,300	$ 191,645	$ 191,590	$ 177,648	1,117,816	$ 761,183	$ 565,209
Transportation, Gathering, Processing and Compression \| Accounting Standards Update 2014-09 \| Previous Revenue Recognition
Costs and expenses:
Costs and expenses									945,017
Transportation, Gathering, Processing and Compression \| Accounting Standards Update 2014-09 \| Increase
Costs and expenses:
Costs and expenses									$ 172,799

Accounting Standards - Additional Information (Detail) - Accounting Standards Update 2016-09 $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Cumulative-effect adjustments to retained earnings (deficit) and reduced deferred tax liability	$ 101.1
Recognition of an excess tax deficiency in provision for income taxes rather than paid-in capital	$ 2.1

Dispositions and Acquisitions - Dispositions - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets	$ (10,815,000)	$ (30,000)	$ 156,000	$ 23,000	$ 207,000	$ 102,000	$ 807,000	$ 22,600,000	$ (10,666,000)	$ 23,716,000	$ (7,074,000)
Northern Oklahoma
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets		(39,000)
Proceeds from sale of oil and gas properties		$ 23,300,000
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									(448,000)	870,000	302,000
Proceeds from sale of oil and gas properties									$ 1,200,000	1,300,000	3,700,000
Texas Panhandle Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets					(989,000)
Proceeds from sale of oil and gas properties					$ 40,400,000
Western Oklahoma Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets										23,800,000	(5,300,000)
Proceeds from sale of oil and gas properties										$ 30,800,000	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
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
Pennsylvania
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets	$ (10,200,000)
Percentage of royalty disposed	1.00%								1.00%
Proceeds from leases	$ 300,000,000

Dispositions and Acquisitions - Acquisitions - Additional Information (Detail) $ in Thousands, shares in Millions		4 Months Ended	12 Months Ended
	Sep. 16, 2016 USD ($) shares	Dec. 31, 2016 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Merger-related expenses			$ 0	$ 0	$ 37,225
MRD
Business Acquisition [Line Items]
Business merger date			Sep. 16, 2016
Common stock issued in connection with exchange of outstanding shares \| shares	77.0
Exchange ratio of common shares for acquired company	0.375
Merger-related expenses	$ 37,200
Revenues		$ 146,600		477,400
Net operating income		$ 94,900		$ 278,800

Revenues from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) Stream	Dec. 31, 2017 USD ($)
Disaggregation of Revenue [Line Items]
Number of revenue streams \| Stream	3
Revenue Contract with Customer
Disaggregation of Revenue [Line Items]
Accounts receivable \| $	$ 438.3	$ 305.7

Revenues from Contracts with Customers - Disaggregation of Revenue by Identified Revenue Stream (Detail)
$ in Thousands

12 Months Ended

Dec. 31, 2018

USD ($)

$ 3,333,836

Natural gas sales

2,137,573

^[1]

NGLs sales

Crude oil and condensate sales

940,378

^[2]

$ 255,885

[1]	Natural gas sales revenue reported above includes $460.3 million of brokered revenues and $13.4 million of marketing revenue.
[2]	NGLs sales revenue reported above includes $9.0 million of brokered revenues.

Revenues from Contracts with Customers - Disaggregation of Revenue by Identified Revenue Stream (Parenthetical) (Detail)
$ in Thousands

12 Months Ended

Dec. 31, 2018

USD ($)

$ 3,333,836

Natural gas sales

2,137,573

^[1]

NGLs sales

Brokered | Natural gas sales

940,378

^[2]

460,300

Brokered | NGLs sales

Marketing | Natural gas sales

9,000

Earnings Per Share Reconciliation [Abstract]

$ 13,400

[1]	Natural gas sales revenue reported above includes $460.3 million of brokered revenues and $13.4 million of marketing revenue.
[2]	NGLs sales revenue reported above includes $9.0 million of brokered revenues.

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Income tax benefit	$ (68,784,000)	$ 24,137,000	$ (28,518,000)	$ 42,676,000	$ (349,080,000)	$ (71,992,000)	$ 57,651,000	$ 112,395,000	$ (30,489,000)	$ (251,026,000)	$ (280,750,000)
Corporate tax rate									21.00%	35.00%	35.00%
Deferred tax liabilities	666,668,000				$ 693,356,000				$ 666,668,000	$ 693,356,000
Accrued interest or penalties related to tax amounts	0								$ 0
Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2019
Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2037
Amendment on Internal Revenue Code of 1986
Income Taxes [Line Items]
Corporate tax rate									21.00%	35.00%
One-time tax benefit related to tax law changes										$ 334,000,000
Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia
Income Taxes [Line Items]
Valuation allowances	101,400,000								$ 101,400,000
Federal
Income Taxes [Line Items]
Valuation allowances	19,000,000								19,000,000
Federal and State
Income Taxes [Line Items]
Net operating loss carryforwards	2,000,000,000								2,000,000,000
Unexpired net operating loss carryforwards	520,100,000								520,100,000
Pennsylvania
Income Taxes [Line Items]
Net operating loss carryforwards	882,700,000								$ 882,700,000
Pennsylvania \| Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2025
Pennsylvania \| Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2038
Louisiana
Income Taxes [Line Items]
Net operating loss carryforwards	$ 338,600,000								$ 338,600,000
Louisiana \| Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2034
Louisiana \| Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2038

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Federal statutory tax rate	21.00%	35.00%	35.00%
Federal rate change	0.00%	(406.70%)	0.00%
State	(0.30%)	(0.70%)	3.00%
State rate and law change	0.90%	(1.30%)	1.00%
Non-deductible executive compensation	0.00%	0.70%	(0.20%)
Valuation allowances	(0.40%)	36.80%	(2.50%)
Equity compensation	(0.10%)	30.20%	(0.70%)
Goodwill impairment	(19.40%)	0.00%	0.00%
Other	0.00%	0.30%	0.00%
Consolidated effective tax rate	1.70%	(305.70%)	35.00%
MRD
Income Taxes [Line Items]
Non-deductible MRD transaction costs	0.00%	0.00%	(0.60%)

Income Taxes - Income Tax (Benefit) Expense Attributable to (Loss) Income Before Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current									$ 0	$ 0	$ 0
U.S. state and local, Current									0	17	98
Total, Current	$ 0	$ 0	$ 0	$ 0	$ 17	$ 0	$ 0	$ 0	0	17	98
U.S. federal, Deferred									(25,322)	(302,507)	(266,105)
U.S. state and local, Deferred									(5,167)	51,464	(14,743)
Total, Deferred	(68,784)	24,137	(28,518)	42,676	(349,097)	(71,992)	57,651	112,395	(30,489)	(251,043)	(280,848)
U.S. federal, Total									(25,322)	(302,507)	(266,105)
U.S. state and local, Total									(5,167)	51,481	(14,645)
Total (benefit) expense for income taxes	$ (68,784)	$ 24,137	$ (28,518)	$ 42,676	$ (349,080)	$ (71,992)	$ 57,651	$ 112,395	$ (30,489)	$ (251,026)	$ (280,750)

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Net operating loss carryforward	$ 542,847	$ 413,672
Deferred compensation	19,844	24,704
Equity compensation	8,152	5,269
AMT credits and other credits	3,296	7,264
Asset retirement obligation	78,126	69,398
Other	30,492	18,806
Valuation allowances:
Total deferred tax assets	562,410	413,979
Deferred tax liabilities:
Depreciation, depletion and investments	(1,207,784)	(1,105,494)
Cumulative mark-to-market gain	(21,294)	(1,841)
Other	0	0
Total deferred tax liabilities	(1,229,078)	(1,107,335)
Net deferred tax liability	(666,668)	(693,356)
Federal
Valuation allowances:
Valuation allowances	(18,975)	(31,308)
State, net of federal benefit
Valuation allowances:
Valuation allowances	$ (101,372)	$ (93,826)

Income Taxes - Changes in Deferred Tax Asset Valuation Allowances (Detail) - Valuation Allowance of Deferred Tax Assets - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Balance at the beginning of the year	$ (125,134)	$ (107,174)	$ (87,623)
Charged to provision for income taxes:
Other state valuation allowances	16,380	(23,790)	500
Other federal valuation allowances	494	(247)	(477)
Other	123	2,304	(1,100)
Balance at the end of the year	(120,347)	(125,134)	(107,174)
State
Charged to provision for income taxes:
Net operating loss carryforwards	(23,926)	(11,612)	(17,374)
Federal
Charged to provision for income taxes:
Net operating loss carryforwards	$ 11,716	$ 15,385	$ (1,100)

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Net (loss) income

$ (1,764,422)

$ 48,539

$ (79,836)

$ 49,238

$ 221,185

$ (127,700)

$ 69,550

$ 170,111

$ (1,746,481)

$ 333,146

$ (521,388)

Participating basic earnings

^[1]

(245)

(3,751)

(223)

Basic net (loss) income attributed to common stockholders

(1,746,726)

329,395

(521,611)

Reallocation of participating earnings

^[1]

Diluted net (loss) income attributed to common stockholders

$ (1,746,726)

$ 329,400

$ (521,611)

Net (loss) income per common share:

Basic

$ (7.15)

$ 0.19

$ (0.32)

$ 0.20

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (7.10)

$ 1.34

$ (2.75)

Diluted

$ (7.15)

$ 0.19

$ (0.32)

$ 0.20

$ 0.89

$ (0.52)

$ 0.28

$ 0.69

$ (7.10)

$ 1.34

$ (2.75)

[1]

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

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The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

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The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Weighted average common shares outstanding – basic

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Denominator:

^[1]

246,171

245,091

189,868

Effect of dilutive securities:

Director and employee restricted stock and performance-based equity awards

367

Weighted average common shares outstanding – diluted

246,171

245,458

189,868

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

Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Parenthetical) (Detail) shares in Millions	Sep. 16, 2016 shares
MRD
Earnings Per Share Basic [Line Items]
Common stock issued in connection with exchange of outstanding shares	77.0

Net Income (Loss) Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	3,100,000	2,800,000	2,800,000
Equity Grants
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation		702,000

Indebtedness - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Senior notes	$ 2,877,349	$ 2,877,349
Senior subordinated notes	48,980	48,980
Total debt	3,869,329	4,137,329
Unamortized premium	4,741	6,027
Unamortized debt issuance costs	(37,209)	(34,550)
Total debt (net of debt issuance costs)	3,836,861	4,108,806
4.1% Bank Debt \| Notes Payable to Banks
Debt Instrument [Line Items]
Bank debt (4.1%)	943,000	1,211,000
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Senior notes	750,000	750,000
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	741,531	741,531
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	580,032	580,032
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes	475,952	475,952
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	329,244	329,244
Other Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes	590	590
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Senior subordinated notes	7,712	7,712
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Senior subordinated notes	19,054	19,054
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Senior subordinated notes	$ 22,214	$ 22,214

Indebtedness - Debt Outstanding (Parenthetical) (Detail)	Dec. 31, 2018	Dec. 31, 2017	Oct. 05, 2017	Sep. 30, 2016
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%	4.875%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%
5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%
5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%
Other Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.875%	5.875%
Notes Payable to Banks \| 4.1% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage	4.10%	4.10%

Indebtedness - Bank Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 USD ($) CommercialBank	Dec. 31, 2017 USD ($)	Dec. 31, 2016
Debt Instrument [Line Items]
Bank debt	$ 932,018,000	$ 1,208,467,000
Bank Credit Facility
Debt Instrument [Line Items]
Bank Credit facility, maximum amount	4,000,000,000
Bank Credit facility, borrowing base	3,000,000,000
Bank commitments	$ 2,000,000,000
Percentage holding of commercial banks, Maximum	5.80%
Number of commercial banks included in current bank group \| CommercialBank	27
Maturity date of loan	Apr. 13, 2023
Bank debt	$ 943,000,000
Undrawn letters of credit	281,400,000
Borrowing capacity available under the commitment amount	$ 775,600,000
Weighted average interest rate on the bank credit facility	3.70%	2.70%	2.20%
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Alternate Base Rate
Debt Instrument [Line Items]
Interest rate margin	0.50%
Bank Credit Facility \| LIBOR Rate
Debt Instrument [Line Items]
Interest rate margin	1.50%
Bank Credit Facility \| Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Minimum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.15%
Bank Credit Facility \| Minimum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	0.25%
Bank Credit Facility \| Minimum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.125%
Bank Credit Facility \| Minimum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility \| Minimum \| LIBOR Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.125%
Bank Credit Facility \| Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Bank Credit Facility \| Maximum \| Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Bank Credit Facility \| Maximum \| Alternate Base Rate
Debt Instrument [Line Items]
Base rate on debt	1.25%
Bank Credit Facility \| Maximum \| Alternate Base Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	0.75%
Bank Credit Facility \| Maximum \| LIBOR Rate
Debt Instrument [Line Items]
Base rate on debt	2.25%
Bank Credit Facility \| Maximum \| LIBOR Rate \| Credit Facility
Debt Instrument [Line Items]
Base rate on debt	1.75%

Indebtedness - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 05, 2017
Senior Notes
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount		101.00%
5.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes		5.875%	5.875%	5.875%
5.875% Senior Notes Due 2022 \| Senior Notes Exchange Offer \| Unsecured Debt
Debt Instrument [Line Items]
Senior notes exchange amount	$ 329,200
Interest rate on notes	5.875%
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes exchange amount	$ 741,531
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes exchange amount	$ 580,032
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes exchange amount	$ 475,952
Interest rate on notes	5.75%	5.75%	5.75%	5.75%

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

Indebtedness - Summary of Debt Exchange Offer to Exchange Senior Subordinated Notes (Parenthetical) (Detail)	Dec. 31, 2018	Dec. 31, 2017	Oct. 05, 2017	Sep. 30, 2016
5.00% Senior Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.00% Senior Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.75% Senior Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%

Indebtedness - Senior Subordinated Notes - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount	101.00%

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2018
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, 2018.
Minimum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	250.00%
Current ratio	100.00%
Present value of proved reserves to total debt	150.00%

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Debt Disclosure [Abstract]
2019	$ 0
2020	0
2021	498,166
2022	928,920
2023	1,692,243
Thereafter	750,000
Total debt	$ 3,869,329

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
Beginning of period	$ 276,855	$ 257,943
Liabilities incurred	3,376	7,724
Acquisitions	13,438
Liabilities settled	(5,052)	(7,965)
Disposition of wells	(13,332)	(8,078)
Accretion expense	25,456	14,711
Change in estimate	12,013	12,520
End of period	312,754	276,855
Less current portion	(5,485)	(6,327)
Long-term asset retirement obligations	$ 307,269	$ 270,528

Derivative Activities - Additional Information (Detail)	Dec. 31, 2018 USD ($) t_per_M MMBTU
Derivatives Excluding Basis Swaps and Freight Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 80,900,000
Commodity \| Natural Gas Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 4,800,000
Volume Hedged \| MMBTU	70,940,000
Commodity \| Propane Spread Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 117,000
Commodity \| Swaps \| Freight \| Level 2
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ (561,000)
Volume Hedged \| t_per_M	10,000

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

Dec. 31, 2018

MMBTU / d

bbl / d

$ / MMBTU

$ / bbl

$ / gal

2019 Commodity Contract | Swaps | Natural Gas

Volume Hedged | MMBTU / d

1,318,041

Weighted Average Hedge Price | $ / MMBTU

2.86

2019 Commodity Contract | Swaps | Crude Oil

Weighted Average Hedge Price | $ / bbl

7,000

55.26

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

2,429

2019 Commodity Contract | Swaptions | Natural Gas

1.44

Volume Hedged | MMBTU / d

113,014

Weighted Average Hedge Price | $ / MMBTU

2.81

^[1]

2019 Commodity Contract | Collars | Crude Oil

2019 Commodity Contract | Collars | Crude Oil | Minimum

1,000

2019 Commodity Contract | Collars | Crude Oil | Maximum

63.00

2020 Commodity Contract | Swaps | Crude Oil

73.03

Weighted Average Hedge Price | $ / bbl

1,562

61.05

2020 Commodity Contract | Swaptions | Natural Gas

Volume Hedged | MMBTU / d

80,000

Weighted Average Hedge Price | $ / MMBTU

2.77

^[1]

January-June, 2019 Commodity Contract | Swaps | NGLs (C3-Propane)

8,500

January-June, 2019 Commodity Contract | Collars | NGLs (C3-Propane)

0.92

January-June, 2019 Commodity Contract | Collars | NGLs (C3-Propane) | Minimum

3,983

January-June, 2019 Commodity Contract | Collars | NGLs (C3-Propane) | Maximum

0.92

January-March, 2019 Commodity Contract | Swaps | NGLs (NC4-Normal Butane)

1.02

2,250

1.22

[1]

Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volume. In 2019, we have swaps in place for 150,000 Mmbtu per day on which the counterparty can elect to extend the contract through December 2020 at a weighted average price of $2.81. In 2020, if the counterparty elects to double the volume, we would have additional swaps covering 80,000 Mmbtu per day at a weighted average price of $2.77.

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Swaps - Natural Gas	Dec. 31, 2018 MMBTU / d $ / MMBTU
2019 Commodity Contract
Derivative [Line Items]
Volume Hedged \| MMBTU / d	1,318,041
Weighted average price of hedge \| $ / MMBTU	2.86
2019 Commodity Contract \| Counterparty Can Elect to Extend Contract
Derivative [Line Items]
Volume Hedged \| MMBTU / d	150,000
Weighted average price of hedge \| $ / MMBTU	2.81
2020 Commodity Contract \| Counterparty Can Elect to Double The Volume
Derivative [Line Items]
Volume Hedged \| MMBTU / d	80,000
Weighted average price of hedge \| $ / MMBTU	2.77

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 122,624	$ 124,647
Gross Amounts Offset in the Balance Sheet	(29,829)	(65,767)
Net Amounts of Assets Presented in the Balance Sheet	92,795	58,880
Gross Amounts of Recognized (Liabilities)	(37,435)	(119,789)
Gross Amounts Offset in the Balance Sheet	29,829	65,767
Net Amounts of (Liabilities) Presented in the Balance Sheet	(7,606)	(54,022)
Commodity \| Swaps \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	20,834	87,794
Gross Amounts Offset in the Balance Sheet	(11,748)	(4,106)
Net Amounts of Assets Presented in the Balance Sheet	9,086	83,688
Gross Amounts of Recognized (Liabilities)	(18,332)	(216)
Gross Amounts Offset in the Balance Sheet	11,748	4,106
Net Amounts of (Liabilities) Presented in the Balance Sheet	(6,584)	3,890
Commodity \| Swaps \| Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	26,481	2
Gross Amounts Offset in the Balance Sheet	(651)	(7,928)
Net Amounts of Assets Presented in the Balance Sheet	25,830	(7,926)
Gross Amounts of Recognized (Liabilities)	0	(24,726)
Gross Amounts Offset in the Balance Sheet	651	7,928
Net Amounts of (Liabilities) Presented in the Balance Sheet	651	(16,798)
Commodity \| Swaps \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	18,719	0
Gross Amounts Offset in the Balance Sheet	(589)	(12,556)
Net Amounts of Assets Presented in the Balance Sheet	18,130	(12,556)
Gross Amounts of Recognized (Liabilities)	0	(34,325)
Gross Amounts Offset in the Balance Sheet	589	12,556
Net Amounts of (Liabilities) Presented in the Balance Sheet	589	(21,769)
Commodity \| Swaps \| NGLs (NC4-Normal Butane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	4,084	0
Gross Amounts Offset in the Balance Sheet	0	(6,051)
Net Amounts of Assets Presented in the Balance Sheet	4,084	(6,051)
Gross Amounts of Recognized (Liabilities)		(11,188)
Gross Amounts Offset in the Balance Sheet		6,051
Net Amounts of (Liabilities) Presented in the Balance Sheet		(5,137)
Commodity \| Swaps \| NGLs (C5-Natural Gasoline)
Derivative [Line Items]
Gross Amounts of Recognized Assets	17,371	0
Gross Amounts Offset in the Balance Sheet	0	(6,727)
Net Amounts of Assets Presented in the Balance Sheet	17,371	(6,727)
Gross Amounts of Recognized (Liabilities)		(13,488)
Gross Amounts Offset in the Balance Sheet		6,727
Net Amounts of (Liabilities) Presented in the Balance Sheet		(6,761)
Commodity \| Swaps \| Freight
Derivative [Line Items]
Gross Amounts of Recognized Assets	0	276
Gross Amounts Offset in the Balance Sheet	(561)	(276)
Net Amounts of Assets Presented in the Balance Sheet	(561)	0
Gross Amounts of Recognized (Liabilities)	(561)	0
Gross Amounts Offset in the Balance Sheet	561	276
Net Amounts of (Liabilities) Presented in the Balance Sheet	0	276
Commodity \| Swaps \| NGLs (C2-Ethane)
Derivative [Line Items]
Gross Amounts of Recognized Assets		57
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		57
Commodity \| Swaptions \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	5,200	18,817
Gross Amounts Offset in the Balance Sheet	(3,883)	(8,103)
Net Amounts of Assets Presented in the Balance Sheet	1,317	10,714
Gross Amounts of Recognized (Liabilities)	(7,972)	(12,283)
Gross Amounts Offset in the Balance Sheet	3,883	8,103
Net Amounts of (Liabilities) Presented in the Balance Sheet	(4,089)	(4,180)
Commodity \| Basis Swaps \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets	6,468	1,815
Gross Amounts Offset in the Balance Sheet	(2,822)	(6,673)
Net Amounts of Assets Presented in the Balance Sheet	3,646	(4,858)
Gross Amounts of Recognized (Liabilities)	(1,702)	(9,580)
Gross Amounts Offset in the Balance Sheet	2,822	6,673
Net Amounts of (Liabilities) Presented in the Balance Sheet	1,120	(2,907)
Commodity \| Collars \| Natural Gas
Derivative [Line Items]
Gross Amounts of Recognized Assets		3,039
Gross Amounts Offset in the Balance Sheet		(500)
Net Amounts of Assets Presented in the Balance Sheet		2,539
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		500
Net Amounts of (Liabilities) Presented in the Balance Sheet		500
Commodity \| Collars \| Crude Oil
Derivative [Line Items]
Gross Amounts of Recognized Assets	5,945
Gross Amounts Offset in the Balance Sheet	(707)
Net Amounts of Assets Presented in the Balance Sheet	5,238
Gross Amounts of Recognized (Liabilities)	0
Gross Amounts Offset in the Balance Sheet	707
Net Amounts of (Liabilities) Presented in the Balance Sheet	707
Commodity \| Collars \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	8,538	85
Gross Amounts Offset in the Balance Sheet	0	(85)
Net Amounts of Assets Presented in the Balance Sheet	8,538	0
Gross Amounts of Recognized (Liabilities)		0
Gross Amounts Offset in the Balance Sheet		85
Net Amounts of (Liabilities) Presented in the Balance Sheet		85
Commodity \| Spread Swaps \| NGLs (C3-Propane)
Derivative [Line Items]
Gross Amounts of Recognized Assets	8,984	12,762
Gross Amounts Offset in the Balance Sheet	(8,868)	(12,762)
Net Amounts of Assets Presented in the Balance Sheet	116	0
Gross Amounts of Recognized (Liabilities)	(8,868)	(13,983)
Gross Amounts Offset in the Balance Sheet	8,868	12,762
Net Amounts of (Liabilities) Presented in the Balance Sheet	$ 0	$ (1,221)

Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Fair Value (Loss) Income	$ 100,698	$ (34,591)	$ (103,290)	$ (14,009)	$ 25,024	$ (88,426)	$ 111,195	$ 165,557	$ (51,192)	$ 213,350	$ (261,391)
Swaptions
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(6,556)	6,534	0
Collars
Derivative [Line Items]
Derivative Fair Value (Loss) Income									17,583	18,132	(6,926)
Basis Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(1,104)	(4,647)	29,154
Puts
Derivative [Line Items]
Derivative Fair Value (Loss) Income									0	10,929	(18,201)
Calls
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(2,653)	987	(18)
Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									(57,950)	181,095	(265,466)
Freight \| Commodity \| Swaps
Derivative [Line Items]
Derivative Fair Value (Loss) Income									$ (512)	$ 320	$ 66

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 57,293	$ 67,117
Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	69,156	3,910
Swaps \| Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(561)	276
Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	14,483	3,124
Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	4,883	(8,986)
Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(2,772)	6,534
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	57,293	67,117
Level 2 \| Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	69,156	3,910
Level 2 \| Swaps \| Freight
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	(561)	276
Level 2 \| Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	5,945	3,039
Level 2 \| Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	4,883	(9,025)
Fair Value, Inputs, Level 3 \| Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	8,538	85
Fair Value, Inputs, Level 3 \| Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		39
Fair Value, Inputs, Level 3 \| Swaptions
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	$ (2,772)	$ 6,534

Fair Value Measurements - Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy (Detail) - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Balance at the beginning of period	$ 6,658
Total gains (losses) included in earnings	5,766
Settlements received	(7,277)
Transfers in and/or out of Level 3	619
Balance at end of period	$ 5,766

Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends					$ 1,100,000	$ 4,100,000	$ 972,000
Mark-to-market gain (loss)					$ (7,900,000)	4,200,000	3,100,000
Closing stock price	$ 9.57				$ 9.57
Impairment of goodwill	$ 1,641,197,000	$ 0	$ 0	$ 0	$ 1,641,197,000	0	0
Northwest Pennsylvania
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, fair value	$ 0				0
Impairment on natural gas and oil properties				$ 7,300,000	$ 15,300,000
Oklahoma And Texas Panhandle
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties						$ 63,700,000
Western Oklahoma
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties							$ 43,000,000

Fair Value Measurements - Value of Assets Measured at Fair Value on Nonrecurring Basis (Detail) - Fair Value, Measurements, Nonrecurring - Natural Gas and Oil Properties - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value	$ 32,516	$ 85,597	$ 90,150
Impairment of proved properties	$ 22,614	$ 63,679	$ 43,040

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

Dec. 31, 2018

Dec. 31, 2017

Assets:

Marketable securities

$ 57,300

$ 67,100

Carrying Value

Assets:

92,795

58,880

Marketable securities

^[1]

57,293

67,117

Deferred compensation plan

(7,606)

(54,022)

Bank credit facility

^[2]

(943,000)

(1,211,000)

^[3]

(80,092)

(114,414)

Fair Value

Assets:

92,795

58,880

Marketable securities

^[1]

57,293

67,117

Deferred compensation plan

(7,606)

(54,022)

Bank credit facility

^[2]

(943,000)

(1,211,000)

^[3]

(80,092)

(114,414)

5.75% Senior Notes Due 2021 | Carrying Value

5.75% Senior Notes Due 2021 | Fair Value

^[2]

(475,952)

5.00% Senior Notes Due 2022 | Carrying Value

^[2]

(455,972)

(493,872)

5.00% Senior Notes Due 2022 | Fair Value

^[2]

(580,032)

5.875% Senior Notes Due 2022 | Carrying Value

^[2]

(519,343)

(578,727)

5.875% Senior Notes Due 2022 | Fair Value

^[2]

(329,244)

5.00% Senior Notes Due 2023 | Carrying Value

^[2]

(305,989)

(339,200)

5.00% Senior Notes Due 2023 | Fair Value

^[2]

(741,531)

Other Senior Notes Due 2022 | Carrying Value

^[2]

(654,683)

(735,614)

Other Senior Notes Due 2022 | Fair Value

^[2]

(590)

5.75% Senior Subordinated Notes Due 2021 | Carrying Value

^[2]

(581)

(591)

5.75% Senior Subordinated Notes Due 2021 | Fair Value

^[2]

(22,214)

4.875% Senior Notes Due 2025 | Carrying Value

^[2]

(21,638)

(22,192)

4.875% Senior Notes Due 2025 | Fair Value

^[2]

(750,000)

5.00% Senior Subordinated Notes Due 2023 | Carrying Value

^[2]

(616,313)

(733,755)

5.00% Senior Subordinated Notes Due 2023 | Fair Value

^[2]

(7,712)

5.00% Senior Subordinated Notes Due 2022 | Carrying Value

^[2]

(6,690)

(7,614)

5.00% Senior Subordinated Notes Due 2022 | Fair Value

^[2]

(19,054)

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

^[2]

$ (17,072)

$ (18,741)

[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, 2018	Dec. 31, 2017	Oct. 05, 2017	Sep. 30, 2016
5.75% Senior Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%	5.75%	5.75%	5.75%
5.00% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
5.875% Senior Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.875%	5.875%	5.875%
5.00% Senior Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%	5.00%	5.00%
4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	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%
5.00% 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% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%	5.00%

Stock-based Compensation Plans - Additional Information (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Accelerated vesting of equity grants					$ 30,800					$ 30,800
Vesting period									1 year
Income tax benefit	$ (68,784)	$ 24,137	$ (28,518)	$ 42,676	$ (349,080)	$ (71,992)	$ 57,651	$ 112,395	$ (30,489)	(251,026)	$ (280,750)
Equity Compensation
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Income tax benefit									$ 3,600	$ 5,300	$ 5,700
2005 Equity Based Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares issued under the plans									5.6

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

^[1]

Dec. 31, 2016

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

$ 49,288

$ 82,776

$ 55,618

Direct Operating Expense

Brokered Natural Gas and Marketing Expense

2,109

2,060

2,302

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

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

1,452

1,437

1,725

Exploration Expense

General and Administrative Expense

1,921

2,742

2,298

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

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

$ 43,806

74,873

49,293

Termination Costs

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

$ 1,664

$ 0

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

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

Stock-based Compensation Plans - Additional Information 1 (Detail)	12 Months Ended
	Dec. 31, 2018 Award shares	Dec. 31, 2017 shares	Dec. 31, 2016 shares	Dec. 31, 2015 shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	1 year
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years	3 years	3 years
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	3
Performance Share \| Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of share value each unit represents at grant date \| shares	1
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	2
Performance-based PG-PSUs and RG-PSUs \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Performance-based PG-PSUs and RG-PSUs \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Number of awards available for grant	1
Performance Based TSR - PSUs \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%	0.00%	0.00%
Performance Based TSR - PSUs \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%	150.00%	150.00%
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of stock option outstanding \| shares	1,104	382,779	1,003,600	1,510,977

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		1 year
Unrecognized compensation related to Awards		$ 427,000
Weighted average period		1 year 8 months 12 days
Accelerated vesting of equity grants	$ 30,800,000		$ 30,800,000
Proceeds from the sales of common stock held by the deferred compensation plan		$ 9,747,000	$ 4,482,000	$ 13,102,000
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted		1,834,883	888,326	973,491
Vesting period		3 years	3 years	3 years
Stock-based compensation expense		$ 24,200,000	$ 23,400,000	$ 22,800,000
Unrecognized compensation related to Awards		$ 25,800,000
Weighted average period		1 year 8 months 12 days
Granted, weighted average grant date fair value		$ 16.98	$ 32.61	$ 28.51
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted		891,350	543,438	540,128
Stock-based compensation expense		$ 11,700,000	$ 30,400,000	$ 18,600,000
Unrecognized compensation related to Awards		$ 2,400,000
Weighted average period		1 year 9 months 18 days
Granted, weighted average grant date fair value		$ 15.30	$ 25.91	$ 35.92
Accelerated vesting of equity grants			$ 15,400,000
Restricted Stock Liability Awards \| Non Employee Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted		146,000	90,000	59,000
Restricted Stock Liability Awards \| Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted		745,000	453,000	481,000
Vesting period		3 years	3 years	3 years

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	833,058	765,971	436,764
Granted	1,834,883	888,326	973,491
Vested	(1,037,501)	(698,563)	(525,617)
Forfeited	(244,352)	(122,676)	(118,667)
Outstanding, Ending Balance	1,386,088	833,058	765,971
Outstanding, Beginning Balance, weighted average grant date fair value	$ 31.64	$ 33.62	$ 59.74
Granted, weighted average grant date fair value	16.98	32.61	28.51
Vested, weighted average grant date fair value	23.57	34.82	43.83
Forfeited, weighted average grant date fair value	21.59	32.91	42.60
Outstanding, Ending Balance, weighted average grant date fair value	$ 20.04	$ 31.64	$ 33.62
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	55,202	425,018	308,737
Granted	891,350	543,438	540,128
Vested	(738,073)	(908,912)	(374,328)
Forfeited	(23,900)	(4,342)	(49,519)
Outstanding, Ending Balance	184,579	55,202	425,018
Outstanding, Beginning Balance, weighted average grant date fair value	$ 32.26	$ 43.48	$ 65.80
Granted, weighted average grant date fair value	15.30	25.91	35.92
Vested, weighted average grant date fair value	16.34	33.71	51.40
Forfeited, weighted average grant date fair value	19.76	31.10	40.33
Outstanding, Ending Balance, weighted average grant date fair value	$ 15.65	$ 32.26	$ 43.48

Stock-based Compensation Plans - Additional Information 3 (Detail)	3 Months Ended	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		1 year
Accelerated vesting of equity grants	$ 30,800,000		$ 30,800,000
Unrecognized compensation related to Awards		$ 427,000
Weighted average period		1 year 8 months 12 days
Performance-based PG-PSUs and RG-PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		3 years
Stock-based compensation expense		$ 5,400,000	1,800,000
Accelerated vesting of equity grants			1,500,000
Performance Based TSR - PSUs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		3 years
Stock-based compensation expense		$ 6,300,000	24,800,000	$ 12,400,000
Accelerated vesting of equity grants			$ 13,000,000
Performance Share
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		3 years
Unrecognized compensation related to Awards		$ 1,100,000
Weighted average period		1 year 6 months
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense		$ 0
Number of awards exercised \| shares		0	0	0
Outstanding awards exercisable, exercise price \| $ / shares		81.74
Outstanding awards exercisable, aggregate intrinsic value		$ 0
Stock Appreciation Rights (SARs) \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding awards exercisable, weighted average remaining contractual life		1 year

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Outstanding, Beginning Balance

122,921

Granted

440,938

^[1]

122,921

Outstanding, Ending Balance

536,798

122,921

Forfeited

^[2]

(27,061)

Outstanding, Beginning Balance, weighted average grant date fair value

$ 25.53

Granted, weighted average grant date fair value

15.22

^[1]

$ 25.53

Outstanding, Ending Balance, weighted average grant date fair value

15.61

$ 25.53

Forfeited, weighted average grant date fair value

^[2]

$ 23.03

[1]	Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 200% depending on achievement of specifically identified performance targets.
[2]	The first of three tranches of PG-PSUs granted in 2017 was forfeited as the performance metric was not met.

Stock-based Compensation Plans - PG/RG-PSUs Activities (Parenthetical) (Detail) - Performance-based PG-PSUs and RG-PSUs - Tranche	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total Number of tranches in PSU		3
Number of tranches forfeited		1
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Potential payout of shares granted	200.00%

Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	2.42%	1.49%	0.94%
Expected annual volatility	48.00%	44.00%	49.00%
Grant date fair value per unit	$ 18.51	$ 26.26	$ 36.64

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Summary of Performance Share Unit Awards outstanding, Number of Units

Outstanding, Beginning Balance

1,009,842

871,299

499,943

Granted

^[1]

329,486

358,519

413,959

Vested and issued

(73,985)

^[2]

(85,461)

^[3]

Forfeited

(197,457)

(134,515)

(42,603)

Outstanding, Ending Balance

1,067,886

1,009,842

871,299

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

Outstanding, Beginning Balance, weighted average grant date fair value

$ 38.38

$ 55.29

$ 69.95

Granted, weighted average grant date fair value

^[1]

18.51

26.26

36.64

Vested, weighted average grant date fair value

56.81

^[2]

86.23

^[3]

Forfeited, weighted average grant date fair value

55.46

85.24

46.09

Outstanding, Ending Balance, weighted average grant date fair value

$ 27.81

$ 38.38

$ 55.29

[1]	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 150% (for TSR-PSUs granted in 2016 and 2017) and may be between zero and 200% (for TSR-PSUs granted in 2018) of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.
[2]	Includes 73,985 TSR-PSUs awards issued related to the 2015 performance period where the return on our common stock was the 46th percentile for the February 2015 grant and the 36th percentile for the May 2015 grant. The remaining 2015 awards are considered to be forfeited.
[3]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

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

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

73,985

^[1]

85,461

^[2]

February 2014 Grant

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

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

67.00%

May 2014 Grant

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

56.00%

February 2015 Grant

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

46.00%

May 2015 Grant

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

36.00%

Minimum

Potential payout of shares on performance units granted

0.00%

Maximum

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

Potential payout of shares on performance units granted

200.00%

150.00%

[1]	Includes 73,985 TSR-PSUs awards issued related to the 2015 performance period where the return on our common stock was the 46th percentile for the February 2015 grant and the 36th percentile for the May 2015 grant. The remaining 2015 awards are considered to be forfeited.
[2]	Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited.

Stock-based Compensation Plans - Stock Option and SARs Activities (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Beginning Balance, Shares	382,779	1,003,600	1,510,977
Expired/forfeited, Shares	(381,675)	(620,821)	(507,377)
Ending Balance, Shares	1,104	382,779	1,003,600
Ending Balance, outstanding and exercisable, Shares	1,104
Beginning Balance, Weighted Average Exercise Price	$ 76.54	$ 69.08	$ 63.73
Expired/forfeited, Weighted Average Exercise Price	$ 75.97	62.29	53.16
Ending Balance, Weighted Average Exercise Price		$ 76.54	$ 69.08
Ending Balance, Outstanding and exercisable, Weighted Average Exercise Price	81.74

Stock-based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Maximum percentage of employees contribution									75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer contribution									$ 5,800	$ 5,100	$ 4,700
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ 18,072	$ (223)	$ (6,615)	$ 7,397	$ 14,077	$ 9,203	$ 14,466	$ 13,169	$ 18,631	$ 50,915	$ (19,153)
Shares held in rabbi trust total	2.6				2.9				2.6	2.9
Vested shares held in rabbi trust	2.4				2.8				2.4	2.8

Stock-based Compensation Plans - Summary of Change in Post Retirement Benefit Obligation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss)
Net gain	$ (526)
Prior service cost		$ 1,769
Amortization of prior service cost	(369)
Other Post Retirement Benefits
Change in Benefit Obligation
Benefit obligation at beginning of year	1,769
Prior service cost		1,769
Service cost	94
Interest cost	58
Actuarial gain	(526)
Benefits paid	(40)
Benefit obligation at end of year	1,355	1,769
Amounts recognized in the consolidated balance sheets:
Long-term liabilities	1,355	1,769
Components of Net Periodic Post Retirement Benefit Cost
Service cost	94
Interest cost	58
Amortization of prior service cost	369
Net periodic post retirement costs (recognized in general and administrative expense)	521
Other Changes in Benefit Obligations in Other Comprehensive Income (Loss)
Net gain	(526)
Prior service cost		1,769
Amortization of prior service cost	(369)
Total recognized in other comprehensive (loss) income	(895)	1,769
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$ (374)	$ 1,769

Stock-based Compensation Plans - Summary of Assumptions Used to Determine Benefit Obligation (Detail) - Other Post Retirement Benefits	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Weighted average assumptions used to determine benefit obligation:
Discount rate	4.00%	3.30%
Assumed weighted average healthcare cost trend rates:
Initial healthcare trend rate	6.50%	7.00%
Ultimate trend rate	5.00%	5.00%
Year ultimate trend rate reached	2028	2028

Stock-based Compensation Plans - Additional Information 5 (Detail) - Other Post Retirement Benefit Plan	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Expected future benefit payments for the five year period 2019 through 2023	$ 497,000
Expected future benefit payments for the five year period 2024 through 2028	534,000
Estimated prior service cost amortized from accumulated other comprehensive (loss) income into statement of operation in 2019	$ 369,000

Capital Stock - Additional Information (Detail) - $ / shares	3 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Class Of Stock Disclosures [Abstract]
Common dividends declared per share	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02	$ 0.02
Authorized capital stock	485,000,000				485,000,000
Common stock, shares authorized	475,000,000				475,000,000
Preferred stock, shares authorized	10,000,000				10,000,000

Capital Stock (Detail) - shares	12 Months Ended
Capital Stock (Detail) - shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class Of Stock [Line Items]
Beginning balance	248,129,430	247,144,356	169,316,460
Restricted stock grants	865,095	539,096	490,609
Shares retired			(739)
Treasury shares	5,302	15,580	28,736
Ending balance	249,510,022	248,129,430	247,144,356
MRD
Class Of Stock [Line Items]
MRD Merger			77,042,749
Restricted Stock
Class Of Stock [Line Items]
Restricted stock units vested	434,046	344,937	266,541
Performance Share
Class Of Stock [Line Items]
Performance stock units issued	76,149	85,461

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Net cash provided from operating activities included:

Income taxes refunded from taxing authorities

$ 7,521

$ 1,024

$ 102

Interest paid

(207,433)

(179,431)

(159,875)

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net

^[1]

28,826

20,245

(24,064)

(Decrease) increase in accrued capital expenditures

$ (119,021)

$ 71,739

$ 61,419

[1]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) bbl / d Mcf / d	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Commitments And Contingencies Disclosure [Line Items]
Rent expense under operating leases \| $	$ 19.3	$ 19.1	$ 14.0
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
2021
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day \| bbl / d	3,000
2035
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day \| bbl / d	10,000
Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	10 years
Natural Gas \| 2029
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	350,000
Natural Gas \| Late 2020
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	215,000
Natural Gas \| 2024
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	151,000
Natural Gas \| 2026 through Early 2029
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	100,000
NGLs
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	5 years
NGLs \| March 2025
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification \| bbl / d	20,000

Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Commitments And Contingencies Disclosure [Abstract]
2019	$ 14,669
2020	14,080
2021	11,801
2022	7,217
2023	6,747
Thereafter	22,001
Operating Lease Obligations	76,515
2019	1,876
2020	1,696
2021	1,334
2022	111
2023	0
Thereafter	0
Sublease Rental Receipts	$ 5,017

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

Dec. 31, 2018

USD ($)

^[1]

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

$ 960,000

905,162

878,205

834,506

798,629

5,854,692

Transportation, Gathering and Processing Contracts

$ 10,231,194

[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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Accrued severance costs	$ (356)	$ 2,176	$ (822)
Stock-based compensation expense (gain)	$ 0	$ 1,664	$ 0

Office Closing and Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	$ 1,855	$ 2,460
Accrued severance costs	(356)	2,176	$ (822)
Accrued building rent	(17)	(70)
Payments	(1,482)	(2,711)
Ending balance	$ 0	$ 1,855	$ 2,460

Office Closing and Exit Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring And Related Activities [Abstract]
Severance costs									$ (356)	$ 2,176	$ (822)
Building lease									(17)	(70)	303
Stock-based compensation									0	1,664	0
Total termination costs	$ 0	$ (336)	$ 0	$ (37)	$ (279)	$ (47)	$ (96)	$ 4,192	$ (373)	$ 3,770	$ (519)

Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) Project	Dec. 31, 2017 USD ($) Project	Dec. 31, 2016 USD ($) Project
Extractive Industries [Abstract]
Balance at beginning of period	$ 0	$ 7,412	$ 4,161
Additions to capitalized exploratory well costs pending the determination of proved reserves	0	1,388	9,128
Reclassifications to wells, facilities and equipment based on determination of proved reserves	0	0	(5,877)
Capitalized exploratory well costs charged to expense	0	(8,800)	0
Balance at end of period	0	0	7,412
Less exploratory well costs that have been capitalized for a period of one year or less	0	0	(7,412)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 0	$ 0	$ 0
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| Project	0	0	0

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Goodwill impairment expense	$ 1,641,197	$ 0	$ 0	$ 0					$ 1,641,197	$ 0	$ 0
Unproved impairment expense	441,750	6,549	54,922	11,773	$ 217,544	$ 42,568	$ 5,193	$ 4,420	514,994	269,725	30,076
Impairment of proved properties and other	$ 0	$ 0	$ 15,302	$ 7,312	$ 0	63,679	$ 0	$ 0	$ 22,614	$ 63,679	$ 43,040
Oklahoma and Texas Properties
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other						$ 63,700

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Revenues and other income									$ 3,333,836
Derivative fair value (loss) income	$ 100,698	$ (34,591)	$ (103,290)	$ (14,009)	$ 25,024	$ (88,426)	$ 111,195	$ 165,557	(51,192)	$ 213,350	$ (261,391)
Total revenues and other income	1,072,637	811,225	656,184	742,599	679,032	482,232	673,111	776,655	3,282,645	2,611,030	1,099,939
Costs and expenses:
Production and ad valorem taxes	16,656	9,427	10,140	9,926	11,757	11,993	9,969	9,163	46,149	42,882	25,443
Brokered natural gas and marketing	221,626	116,080	102,747	55,594	51,131	59,773	55,857	53,550	496,047	220,311	168,576
Exploration	10,600	8,299	7,499	7,719	7,893	22,767	14,498	8,504	34,117	53,662	32,325
Abandonment and impairment of unproved properties	441,750	6,549	54,922	11,773	217,544	42,568	5,193	4,420	514,994	269,725	30,076
General and administrative	50,090	43,722	47,583	68,417	80,553	53,035	52,322	47,496	209,812	233,406	184,772
Termination costs	0	(336)	0	(37)	(279)	(47)	(96)	4,192	(373)	3,770	(519)
Deferred compensation plan	(18,072)	223	6,615	(7,397)	(14,077)	(9,203)	(14,466)	(13,169)	(18,631)	(50,915)	19,153
Interest	49,161	54,801	53,862	52,385	51,473	49,179	47,926	47,101	210,209	195,679	168,213
Depletion, depreciation and amortization	147,909	164,266	161,026	162,266	162,918	159,749	152,504	149,821	635,467	624,992	524,102
Impairment of proved properties and other	0	0	15,302	7,312	0	63,679	0	0	22,614	63,679	43,040
Impairment of goodwill	1,641,197	0	0	0					1,641,197	0	0
(Gain) loss on sale of assets	10,815	30	(156)	(23)	(207)	(102)	(807)	(22,600)	10,666	(23,716)	7,074
Total costs and expenses	2,905,843	738,549	764,538	650,685	806,927	681,924	545,910	494,149	5,059,615	2,528,910	1,902,077
(Loss) income before income taxes	(1,833,206)	72,676	(108,354)	91,914	(127,895)	(199,692)	127,201	282,506	(1,776,970)	82,120	(802,138)
Income tax expense (benefit):
Current	0	0	0	0	17	0	0	0	0	17	98
Deferred	(68,784)	24,137	(28,518)	42,676	(349,097)	(71,992)	57,651	112,395	(30,489)	(251,043)	(280,848)
Total (benefit) expense for income taxes	(68,784)	24,137	(28,518)	42,676	(349,080)	(71,992)	57,651	112,395	(30,489)	(251,026)	(280,750)
Net (loss) income	$ (1,764,422)	$ 48,539	$ (79,836)	$ 49,238	$ 221,185	$ (127,700)	$ 69,550	$ 170,111	$ (1,746,481)	$ 333,146	$ (521,388)
Net income (loss) per common share:
Basic	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (7.10)	$ 1.34	$ (2.75)
Diluted	$ (7.15)	$ 0.19	$ (0.32)	$ 0.20	$ 0.89	$ (0.52)	$ 0.28	$ 0.69	$ (7.10)	$ 1.34	$ (2.75)
Natural Gas, NGLs and Oil Sales
Revenues and other income:
Revenues and other income	$ 756,627	$ 736,431	$ 661,390	$ 696,629	$ 603,159	$ 507,541	$ 506,137	$ 559,450	$ 2,851,077	$ 2,176,287	$ 1,197,215
Brokered Natural Gas, Marketing and Other
Revenues and other income:
Revenues and other income	215,312	109,385	98,084	59,979	50,849	63,117	55,779	51,648	482,760	221,393	164,115
Direct Operating
Costs and expenses:
Costs and expenses	35,395	30,926	35,088	38,122	37,921	36,888	31,420	28,023	139,531	134,252	97,388
Transportation, Gathering, Processing and Compression
Costs and expenses:
Costs and expenses	$ 298,716	$ 304,562	$ 269,910	$ 244,628	$ 200,300	$ 191,645	$ 191,590	$ 177,648	$ 1,117,816	$ 761,183	$ 565,209

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, 2018

Dec. 31, 2017

Dec. 31, 2016

Natural gas and oil properties:

Properties subject to depletion

^[1]

$ 10,974,929

$ 10,572,453

$ 9,462,350

Unproved properties

^[1]

2,110,277

2,644,000

2,923,803

Total

^[1]

13,085,206

13,216,453

12,386,153

Accumulated depletion and depreciation

^[1]

(4,062,021)

(3,649,716)

(3,129,816)

Natural gas and oil properties, successful efforts method, net

^[1]

$ 9,023,185

$ 9,566,737

$ 9,256,337

[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, 2018

Dec. 31, 2017

Dec. 31, 2016

Acquisitions

Acreage purchases

^[1]

$ 62,390

$ 62,075

$ 33,142

Oil and gas properties

^[1]

1,683

18,269

3,098,772

Asset retirement obligations and other

^[1]

21,908

Development

^[1]

834,552

1,177,526

497,795

Exploration:

Exploration drilling costs incurred

^[1]

1,380

2,030

37,680

Gas gathering facilities:

Development

^[1]

10,218

15,097

3,595

Subtotal

^[1]

944,340

1,328,659

3,725,217

Asset retirement obligations

^[1]

28,826

20,245

(24,064)

Total costs incurred

^[1]

973,166

1,348,904

3,701,153

Expense

Exploration:

Exploration costs incurred

^[1]

32,196

50,920

30,027

^[1]

$ 1,921

$ 2,742

$ 2,298

[1]	Includes cost incurred whether capitalized or expensed.

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

12 Months Ended

Dec. 31, 2018

USD ($)

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2017

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2016

MMcfe

$ / MMBTU

$ / bbl

$ / Mcf

MMcf

MBbls

Dec. 31, 2015

MMcfe

MMcf

MBbls

Percentage of proved resources reviewed by consultants

94.00%

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

72.00%

82.00%

86.00%

Revision of positive pricing and performance

957,000

Revisions of positive pricing

154,000

46,000

Improved recoveries

597,000

393,000

Proved undeveloped reserves dropped

379,000

668,000

269,000

Cost spent on undeveloped reserves transferred to developed reserves | $

$ 623.3

Estimated future development costs over next five years | $

$ 3,300.0

Crude Oil and NGL

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

65.55

51.19

42.68

Crude Oil and Condensate

Estimate reserve information average realized prices | $ / bbl

59.96

45.73

37.41

Proved developed and undeveloped reserves | MBbls

85,856

69,854

70,252

53,193

NGLs

Estimate reserve information average realized prices | $ / bbl

25.22

17.84

13.44

Proved developed and undeveloped reserves | MBbls

921,594

763,264

630,066

549,135

Natural Gas

Estimate reserve information average realized prices | $ / Mcf

2.98

2.60

2.07

Proved developed and undeveloped reserves | MMcf

12,027,702

10,263,649

7,870,416

6,277,697

Natural Gas, Per Thousand Cubic Feet

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

3.10

2.98

2.48

Natural Gas Equivalents

Proved reserves from drilling activities and evaluations of proved areas

^[1]

3,143,898

3,487,519

1,394,134

Proved developed and undeveloped reserve balances

^[1]

18,072,406

15,262,361

12,072,322

9,891,663

Revisions of previous estimates

^[1]

731,735

506,919

255,794

Revisions of positive performance

532,000

154,000

Ethane and Natural Gas Equivalents

Proved developed and undeveloped reserve balances

2,075,000

1,596,000

1,367,000

Ethane Reserves and NGLs

Proved developed and undeveloped reserves | MBbls

468,900

360,600

308,900

Maximum

Statement That Reserve Estimates Differ From Auditors

0.10

[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 between 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, 2018

MMcfe

MMcf

MBbls

Dec. 31, 2017

MMcfe

MMcf

MBbls

Dec. 31, 2016

MMcfe

MMcf

MBbls

Proved undeveloped reserves | MMcfe

8,315,535

6,914,287

Natural Gas

Extensions, discoveries and additions | MMcf

Beginning Balance | MMcf

10,263,649

7,870,416

6,277,697

Revisions | MMcf

178,595

70,222

(7,441)

2,269,427

2,866,103

1,193,154

Purchases | MMcf

7,738

943,544

Property sales | MMcf

(135,884)

(60,278)

(160,727)

Production | MMcf

(548,085)

(490,552)

(375,811)

Ending Balance | MMcf

12,027,702

10,263,649

7,870,416

Proved developed reserves | MMcf

6,451,012

5,437,674

4,352,141

Proved undeveloped reserves | MMcf

5,576,690

4,825,975

3,518,275

NGLs

Extensions, discoveries and additions

Beginning Balance

763,264

630,066

549,135

Revisions

84,993

83,338

41,402

128,436

87,572

26,991

Purchases

330

40,724

Property sales

(16,774)

(2,356)

(360)

Production

(38,325)

(35,686)

(27,826)

Ending Balance

921,594

763,264

630,066

Proved developed reserves

512,318

448,258

363,852

Proved undeveloped reserves

409,276

315,006

266,214

Crude Oil and Condensate

Extensions, discoveries and additions

Beginning Balance

69,854

70,252

53,193

Revisions

7,197

(10,555)

2,471

17,309

15,997

6,506

Purchases

11,986

Property sales

(4,276)

(1,121)

(295)

Production

(4,228)

(4,785)

(3,609)

Ending Balance

85,856

69,854

70,252

Proved developed reserves

38,658

36,808

39,110

Proved undeveloped reserves

47,198

33,046

31,143

Natural Gas Equivalents

Proved developed reserves | MMcfe

^[1]

9,756,870

8,348,074

6,769,908

Proved undeveloped reserves | MMcfe

^[1]

8,315,536

6,914,287

5,302,414

Beginning Balance | MMcfe

^[1]

15,262,361

12,072,322

9,891,663

Revisions | MMcfe

^[1]

731,735

506,919

255,794

Extensions, discoveries and additions | MMcfe

^[1]

3,143,898

3,487,519

1,394,134

Purchases | MMcfe

^[1]

10,116

1,259,806

Property sales | MMcfe

^[1]

(262,180)

(81,133)

(164,655)

Production | MMcfe

^[1]

(803,408)

(733,382)

(564,420)

Ending Balance | MMcfe

^[1]

18,072,406

15,262,361

12,072,322

[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 between 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, 2018

MMcfe

Beginning proved undeveloped reserves at December 31, 2017

6,914,287

Undeveloped reserves transferred to developed

(1,804,643)

Revisions

608,252

^[1]

Purchases/(sales)

(127,601)

Extension and discoveries

2,725,240

Ending proved undeveloped reserves at December 31, 2018

8,315,535

[1]	Includes 379 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Proved undeveloped reserves dropped	379	668	269

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, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015