Ultra Petroleum 10-K 8 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 28, 2019	Jun. 29, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	ULTRA PETROLEUM CORP.
Entity Central Index Key	1,022,646
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 369,920,487
Entity Common Stock, Shares Outstanding		197,383,295
Trading Symbol	UPL

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 17,014	$ 16,631
Restricted cash	2,291	1,638
Oil and gas revenue receivable	133,042	86,487
Joint interest billing and other receivables, net	11,348	16,616
Derivative asset	23,374	16,865
Income tax receivable	6,431	10,091
Inventory	18,757	13,450
Other current assets	2,473	5,647
Total current assets	214,730	167,425
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,497,727	1,325,068
Property, plant and equipment	11,635	9,569
Other	9,196	10,920
Total assets	1,733,288	1,512,982
Current liabilities:
Accounts payable	36,923	59,951
Accrued liabilities	58,574	80,268
Production taxes payable	58,365	51,352
Current portion of long-term debt	7,313
Interest payable	28,672	24,406
Capital cost accrual	15,014	32,513
Derivative liability	62,350
Total current liabilities	267,211	248,490
Long-term debt
Long-term debt	2,036,722	2,175,000
Add: Premium on exchange transaction	228,096
Less: Unamortized deferred financing costs and discount	(56,650)	(58,789)
Total long-term debt, net	2,208,168	2,116,211
Deferred gain on sale of liquids gathering system	94,636	105,189
Other long-term obligations	211,895	197,728
Total liabilities	2,781,910	2,667,618
Commitments and contingencies (Note 12)
Shareholders’ equity:
Common stock — no par value; authorized — 750,000,000; issued and outstanding shares — 197,383,295 and 196,346,736 at December 31, 2018 and 2017, respectively	2,137,443	2,116,018
Treasury stock	(49)	(49)
Retained loss	(3,186,016)	(3,270,605)
Total shareholders’ deficit	(1,048,622)	(1,154,636)
Total liabilities and shareholders’ equity	$ 1,733,288	$ 1,512,982

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Common stock, No par value
Common stock, Shares authorized	750,000,000	750,000,000
Common stock, Shares issued	197,383,295	196,346,736
Common stock, Shares outstanding	197,383,295	196,346,736

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total operating revenues	$ 892,499	$ 891,873	$ 721,091
Expenses:
Lease operating expenses	90,290	92,326	89,134
Facility lease expense	25,947	21,749	20,686
Production taxes	93,322	91,067	69,737
Gathering fees	89,806	86,953	86,809
Transportation charges			20,049
Depletion, depreciation and amortization	204,255	161,945	125,121
General and administrative	25,005	39,548	9,179
Other expenses	9,118
Total operating expenses	537,743	493,588	420,715
Operating income	354,756	398,285	300,376
Other (expense) income, net:
Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016)	(148,316)	(361,367)	(66,565)
Gain (loss) on commodity derivatives	(145,212)	28,412
Deferred gain on sale of liquids gathering system	10,553	10,553	10,553
Restructuring expenses			(7,176)
Contract settlement income (expense), net	12,656	(52,707)	(131,106)
Other income (expense), net	1,212	(237)	(3,082)
Total other (expense) income, net	(269,107)	(375,346)	(197,376)
Reorganization items, net		140,907	(47,503)
Income before income tax expense (benefit)	85,649	163,846	55,497
Income tax expense (benefit)	442	(13,294)	(654)
Net income	$ 85,207	$ 177,140	$ 56,151
Basic Earnings per Share:
Net income per common share — basic	$ 0.43	$ 1.08	$ 0.70
Fully Diluted Earnings per Share:
Net income per common share — fully diluted	$ 0.43	$ 1.08	$ 0.70
Weighted average common shares outstanding — basic	196,964	163,824	79,996
Weighted average common shares outstanding — fully diluted	197,541	163,976	80,363
Natural Gas Sales
Revenues:
Total operating revenues	$ 722,313	$ 748,682	$ 609,756
Oil Sales
Revenues:
Total operating revenues	153,534	133,368	$ 111,335
Other Revenues
Revenues:
Total operating revenues	$ 16,652	$ 9,823

Consolidated Statement of Ope_2

Consolidated Statement of Operations (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Income Statement [Abstract]
Contractual interest expense on prepetition liabilities not recognized in statement of operations	$ 141.5

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Retained Loss	Treasury Stock
Beginning Balances at Dec. 31, 2015	$ (2,991,937)	$ 502,050	$ (3,493,811)	$ (176)
Beginning Balances, Shares at Dec. 31, 2015		79,933
Employee stock plan grants, Shares		145
Shares re-issued from treasury			(127)	127
Net share settlements	(378)		(378)
Net share settlements, Shares		(61)
Fair value of employee stock plan grants	8,013	$ 8,013
Net income	56,151		56,151
Ending Balances at Dec. 31, 2016	(2,928,151)	$ 510,063	(3,438,165)	(49)
Ending Balances, Shares at Dec. 31, 2016		80,017
Equitization of Holdco Notes	978,230	$ 978,230
Equitization of Holdco Notes, Shares		70,579
Rights Offering, including Backstop	573,774	$ 573,774
Rights Offering, including Backstop, Shares		44,390
Employee stock plan grants, Shares		10
Stock plan grants	26,673	$ 26,673
Stock plan grants, Shares		2,191
Net share settlements	(9,580)		(9,580)
Net share settlements, Shares		(840)
Fair value of employee stock plan grants	27,278	$ 27,278
Net income	177,140		177,140
Ending Balances at Dec. 31, 2017	(1,154,636)	$ 2,116,018	(3,270,605)	(49)
Ending Balances, Shares at Dec. 31, 2017		196,347
Employee stock plan grants, Shares		1,770
Net share settlements	(2,379)		(2,379)
Net share settlements, Shares		(734)
Issuance of warrants	5,786	$ 5,786
Fair value of employee stock plan grants	15,639	15,639
Initial adoption of ASC 606	1,761		1,761
Net income	85,207		85,207
Ending Balances at Dec. 31, 2018	$ (1,048,622)	$ 2,137,443	$ (3,186,016)	$ (49)
Ending Balances, Shares at Dec. 31, 2018		197,383

Consolidated Statements of Sh_2

Consolidated Statements of Shareholders' Equity (Parenthetical)	Apr. 12, 2017shares
Conversion ratio	0.521562
Common Stock
Conversion ratio	0.521562
New equity issued, Shares	194,991,656
Equitization of Holdco Notes, Shares	70,579,367
New equity issued to holders of existing common shares, Shares	80,022,410
New equity issued to commitment parties in respect of backstop commitment premium, Shares	2,512,623
New equity issued to commitment parties in connection with backstop commitment obligation, Shares	18,844,363
New equity issued to participants in rights offering, Shares	23,032,893

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities:
Net income for the period	$ 85,207	$ 177,140	$ 56,151
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization	204,255	161,945	125,121
Unrealized (gain) loss on commodity derivatives	59,799	(16,966)
Deferred gain on sale of liquids gathering system	(10,553)	(10,553)	(10,553)
Stock compensation	11,825	39,977	5,562
Non-cash reorganization items, net		(453,909)	42,523
Amortization of premium on restructuring	(1,083)
Amortization of deferred financing costs	11,210	7,483	4,194
Other	3,501	(1,047)	2,676
Net changes in operating assets and liabilities:
Accounts receivable	(46,276)	(14,483)	(19,635)
Other current and non-current assets	5,630	14,615	(16,186)
Accounts payable	(13,206)	34,349	(63,924)
Accrued liabilities	(20,294)	89,935	133,144
Production taxes payable	7,098	7,023	(7,944)
Interest payable	4,266	36,220	57,117
Other long-term obligations	2,674	4,737	276
Current taxes payable/receivable	6,844	(11,198)	2,548
Net cash provided by operating activities	310,897	65,268	311,070
Investing Activities:
Oil and gas property expenditures	(426,166)	(557,029)	(269,314)
Sale of oil and gas properties	61,304	114,263
Change in capital cost accrual and accounts payable	(27,322)	20,076	(8,134)
Inventory	(5,335)	(8,916)	(1,123)
Proceeds from sale of property, plant and equipment	2,872
Purchase of property, plant and equipment	(7,063)	(3,705)	(329)
Net cash used in investing activities	(401,710)	(435,311)	(278,900)
Financing activities:
Extinguishment of long-term debt (chapter 11)		(2,459,000)
Proceeds from issuance of Senior Notes		1,200,000
Deferred financing costs	(9,773)	(73,092)
Shares issued, net of transaction costs		573,774
Repurchased shares/net share settlements	(2,378)	(9,581)	(379)
Debt extinguishment costs		(223,838)
Net cash provided by (used in) financing activities	91,849	(16,737)	368,621
(Decrease)/Increase in cash during the period	1,036	(386,780)	400,791
Cash, cash equivalents, and restricted cash at beginning of period	18,269	405,049	4,258
Cash, cash equivalents, and restricted cash end of period	19,305	18,269	405,049
Cash paid for:
Interest	135,230	317,120	4,793
Income taxes			94
Supplemental non-cash investing and financing activities
Premium on Exchange Transaction	229,179
Principal reduction from exchange transaction	(229,179)
Credit Agreement
Financing activities:
Borrowings under Credit / Term Loan Agreement	1,020,000	773,000	$ 369,000
Payments under Credit Agreement	$ (916,000)	(773,000)
Term Loan Agreement
Financing activities:
Borrowings under Credit / Term Loan Agreement		$ 975,000

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of the Business	DESCRIPTION OF THE BUSINESS: Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, or “us”)is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

Debt Exchange

Debt Exchange	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
2018 Debt Exchange	2018 Debt Exchange In December 2018, the Company exchanged (i) $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022 Notes”) and (ii) $275 million aggregate principal amount, or 55.0%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022 Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of the Company, for (a) $545.0 million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “Second Lien Notes”), and (b) an aggregate of 10,919,499 new $0.01 warrants of the Company entitling the holder thereof to purchase one common share of the Company (each a “Warrant” and collectively, the “Warrants”) (such transaction, the “Exchange Transaction”). The Exchange Transaction reduced indebtedness by approximately $235 million. Refer to Note 6 for additional details and the accounting treatment on the Exchange Transaction.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	1. Basis of presentation and principles of consolidation : The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated. Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. The Company adopted Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash and reports the change in cash, cash equivalents, and restricted cash in total on the Consolidated Statement of Cash Flows as of December 31, 2017. The Consolidated Statement of Cash Flows as of December 31, 2016 has been adjusted to conform to the new standard. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Financial Statements: Current Presentation December 31, 2018 December 31, 2017 December 31, 2016 Cash and Cash Equivalents $ 17,014 $ 16,631 $ 401,478 Restricted Cash 2,291 1,638 3,571 Total cash, cash equivalents, and restricted cash $ 19,305 $ 18,269 $ 405,049 Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. Included in the Other expenses on the Consolidated Statements of Operations is the provision for uncollectible accounts of $4.9 million. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. While the Company does not have any material amounts as described in this paragraph at the current time, it has been a larger consideration in prior years. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation in 2018, 2017 or 2016. Inventories: Inventory includes $17.6 million in pipe and production equipment and miscellaneous materials and supplies that will be utilized during the 2019 drilling program, as well as $1.1 million in crude oil inventory. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 8). Deferred Financing Costs: The Company follows ASU No. 2015-03, for its Term Loan Facility, Second Lien Notes, and the Unsecured Notes and includes the costs for issuing debt including issuance discounts, as a direct deduction from the carrying amount of the related debt liability. Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. Warrants: On December 21, 2018, in connection with the consummation of the Exchange Transaction, the Company issued 10,919,499 new Warrants. The Warrants are initially exercisable for one common share of the Company, no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the Common Shares is at least $2.50 per Common Share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof from the December 21, 2018 until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase Common Shares will terminate. Earnings Per Share: Basic earnings per share is computed by dividing net earnings (attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect. In conjunction with our emergence from chapter 11 proceedings, on April 12, 2017, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred as of the earliest period presented. Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator using the treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. For the years ended December 31, 2018 and 2017, the Company had 14.2 million and 3.9 million, respectively, of contingently issuable shares that are not included in the diluted earnings per share denominator. There were no contingently issuable shares outstanding for the year ended December 31, 2016. The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2018 2017 2016 Net income $ 85,207 $ 177,140 $ 56,151 Weighted average common shares outstanding during the period 196,964 163,824 79,996 Effect of dilutive instruments 577 152 367 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,541 163,976 80,363 Net income per common share — basic $ 0.43 $ 1.08 $ 0.70 Net income per common share — fully diluted $ 0.43 $ 1.08 $ 0.70 Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — 749 Use of Estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 9 for additional information. Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets. Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosures related to the Company’s adoption of this standard. Other revenues: Other revenues are comprised of fees paid to us by operators of the gas processing plants where our gas is processed in exchange for the liquids removed from our production. Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the reported results of operations. Recent Accounting Pronouncements: In May 2014, the FASB issued ASU 2014-09, and in 2016, the FASB issued ASU 2016-08, , and ASU 2016-10, , which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the cumulative impact of adopting the new revenue standard, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. Stock Compensation: In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s consolidated financial statements. Leases: In February 2016, the FASB established Topic 842, Leases, by issuing issued ASU 2016-02, Leases (“ASU No. 2016-02”), which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. On January 1, 2019, we adopted the new standard. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leases also apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financial statements and provide the disclosures required by the new standard for the comparative periods. We adopted the new standard on January 1, 2019 and will use the effective date as our date of initial application. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The new standard provides a number of optional practical expedients in transition. We expect to elect the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We also expect to adopt the practical expedient pertaining to land easements. We do not expect to elect the use-of-hindsight. The new standard also provides practical expedients for an entity’s ongoing accounting. We expect to elect the short-term lease recognition exemption for all leases that qualify. For those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We will continue to evaluate the practical expedients related to lease and non-lease components. We expect that this standard will have a material effect on our financial statements. While we continue to assess all of the effects of adoption, we currently believe the most significant effects relate to (1) the recognition of new ROU assets and lease liabilities on our balance sheet for our office and equipment operating leases; and (2) the requirement to provide significant new disclosures about our leasing activities. These ROU assets and liabilities are not deemed to be debt within the definitions of our debt covenants. On adoption, we currently expect to recognize additional operating liabilities, with corresponding ROU assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. Derivatives: In August 2017, the FASB issued ASU 2017-12, (“ASU No. 2017-12”), which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements as the Company does not elect hedge accounting. Fair Value Measurements . In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements.

Impact of ASC 606 Adoption - Re

Impact of ASC 606 Adoption - Revenue Recognition	12 Months Ended
	Dec. 31, 2018
Revenue From Contract With Customer [Abstract]
Impact of ASC 606 Adoption - Revenue Recognition	2. IMPACT OF ASC 606 ADOPTION – REVENUE RECOGNITION In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for twelve months ended December 31, 2018 is as follows: For the Twelve Months Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 722,313 $ 722,365 $ (52 ) Oil sales 153,534 153,534 — Other revenues 16,652 16,652 — Costs and expenses: Production taxes $ 93,322 $ 93,326 $ (4 ) Gathering fees 89,806 89,812 (6 ) Net income: $ 85,207 $ 85,249 $ (42 ) The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method. The Company evaluated the contracts for sales of oil and natural gas utilizing the principal versus agent indicators, noting no change in revenue recognition resulted from the analysis. Revenue Recognition Revenue from Contracts with Customers Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies. Natural gas sales We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes, provided they are in compliance with the terms of the joint operating agreements. The Company may act as an agent and market the other partners’ share of the natural gas production. If it does so, the Company is considered the agent and revenue continues to be recorded at the Company’s net revenue interest in the production, and the portion related to partners’ interest is not recognized as revenue. Oil sales We sell oil production at (a) the lease automatic custody transfer (“LACT”) meter for Wyoming condensate, (b) the tank battery for Utah wax/condensate, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. In conjunction with the adoption of ASC 606, for the twelve months ended December 31, 2018, there was no change to the method used to recognize oil sales and there was no impact to the consolidated financial statements for oil sales. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the oil production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Other revenues Our other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred upon completion of the processing service. The Company is considered the principal, and revenue is recognized at the point in time that the control is transferred. In conjunction with the adoption of ASC 606, for the twelve months ended December 31, 2018, there was no change to the method used to recognize other processing revenues and there was no impact to the consolidated financial statements for other revenues. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas imbalances, which is no longer allowed under ASC 606. In conjunction with the adoption of ASC 606, for the twelve months ended December 31, 2018, there was no material impact to the consolidated financial statements due to this change in accounting for our production imbalances. 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 in ASC 606-10-50-14 exempting the Company 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 utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is 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. Contract balances Under our product 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 under ASC 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not 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 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 received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the twelve months ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	3 . The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended: December 31, 2018 2017 Asset retirement obligations at beginning of period $ 173,100 $ 157,173 Accretion expense 12,342 11,689 Liabilities incurred 3,558 8,174 Liabilities divested (1) (2) (9,372 ) (4,812 ) Liabilities acquired - 1,456 Liabilities settled (70 ) (598 ) Revisions of estimated liabilities (96 ) 18 Asset retirement obligations at end of period 179,462 173,100 Less: current asset retirement obligations (193 ) (263 ) Long-term asset retirement obligations (3) $ 179,269 $ 172,837 (1) During the year ended December 31, 2018, the Company divested certain non-core properties in Utah. (2) During the year ended December 31, 2017, the Company divested certain non-core properties in north-central Pennsylvania. (3) Included in Other long-term obligations in the Consolidated Balance Sheet.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2018
Oil And Gas Property [Abstract]
Oil and Gas Properties	4 . OIL AND GAS PROPERTIES: December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,577,281 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (10,079,554 ) (9,890,495 ) Total Oil and gas properties, net 1,497,727 1,325,068 On a unit basis, DD&A was $0.74, $0.59 and $0.44 per Mcfe for the years ended December 31, 2018, 2017 and 2016, respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	5 . December 31, 2018 2017 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,828 (2,209 ) 619 554 Office equipment 265 (200 ) 65 95 Leasehold improvements 264 (178 ) 86 120 Land 2,437 — 2,437 4,637 Production and other equipment 20,232 (11,804 ) 8,428 4,163 Property, plant and equipment, net $ 26,026 $ (14,391 ) $ 11,635 $ 9,569

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2018
Long Term Liabilities [Abstract]
Long Term Debt	6 . December 31, 2018 Principal Unamortized Deferred Financing Costs and Discounts (1) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement $ 104,000 $ — $ — $ 104,000 Term Loan, secured, due 2024 975,000 (26,874 ) — 948,126 Second Lien Notes, secured, due 2024 545,000 — 228,096 773,096 6.875% Unsecured Notes due 2022 195,035 (15,168 ) — 179,867 7.125% Unsecured Notes due 2025 225,000 (14,608 ) — 210,392 $ 2,044,035 $ (56,650 ) $ 228,096 $ 2,215,481 Less: Current maturities 7,313 — — 7,313 Total Long-term debt $ 2,036,722 $ (56,650 ) $ 228,096 $ 2,208,168 December 31, 2017 Principal Unamortized Deferred Financing Costs and Discounts (1) Carrying Value Credit Agreement $ — $ — $ — Term Loan, secured, due 2024 975,000 (23,357 ) 951,643 6.875% Unsecured Notes due 2022 700,000 (19,084 ) 680,916 7.125% Unsecured Notes due 2025 500,000 (16,348 ) 483,652 $ 2,175,000 $ (58,789 ) $ 2,116,211 Less: Current maturities — — — Total Long-term debt $ 2,175,000 $ (58,789 ) $ 2,116,211 (1) Deferred financing costs related to the Revolving Credit Facility are reported within Other assets on the consolidated balance sheet, rather than as a reduction of the carrying amount of long-term debt. Aggregate maturities of debt at December 31, 2019 $ 7,313 2020 $ 9,750 2021 $ 9,750 2022 $ 308,785 2023 $ 9,750 Beyond 5 years $ 1,698,687 Total $ 2,044,035 Ultra Resources, Inc. Credit Agreement. On April 12, 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto (collectively, the “RBL Lenders”) from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) subject to a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (as defined below). In September 2018, the borrowing base was reduced from $1.4 million to $1.3 billion in connection with the semi-annual determination, with $975.0 million allocated to the Company’s Term Loan Facility (as defined below) and $325.0 million allocated to the Revolving Credit Facility. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into the Third Amendment to the Credit Agreement (the “Third Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Third Amendment, the parties agreed, among other things, to amend the Credit Agreement to permit the issuance of the Second Lien Notes and the Exchange Transaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to: • increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Credit Agreement); • removing the ability to create, invest in and utilize unrestricted subsidiaries that are not guarantors under the Revolving Credit Facility; • further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Third Amendment; and • providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Third Amendment. In conjunction with the Exchange Transaction, the Third Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications and Extinguishments On February 14, 2019, Ultra Resources entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto The Fourth Amendment also revises certain covenants and other provisions of the Credit Agreement, including, but not limited to: • Amending the Consolidated Net Leverage Ratio financial covenant as described below. In addition, the consolidated net debt component of the consolidated net leverage ratio may be reduced upon receipt of proceeds from the make-whole litigation as described in Note 12; • Revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that represent an accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to senior management changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debt restructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of an accrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certain noncash charges that Ultra Resources chose to add back (as described in clause (i)); and • Amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, current required amortization payments under the Term Loan Agreement. At December 31, 2018, Ultra Resources had $104.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million, and a borrowing base of $1.3 billion. Given the Revolving Credit Agreement was amended in February 2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is October 1, 2019. The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022. Under the Fourth Amendment, Ultra Resources is required to maintain (i) a minimum interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility of a minimum of 1.00 to 1.00; and (iii) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. In addition, as of the last day of , Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.25 to 1.0 As of December 31, 2018, Ultra Resources’ consolidated net leverage ratio was 3.95 to 1.00 and it was in compliance with each of its debt covenants under the Credit Agreement. Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its proved developed producing (“PDP”) reserves; and during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projected volumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement. Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees. The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants. The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated. Term Loan. On April 12, 2017 , Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement (the “Term Loan Agreement”) with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent (the “Term Loan Administrative Agent”), and the other lenders party thereto (collectively, the “Term Loan Lenders”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of the initial term loan. In September 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under the Term Loan Agreement to $975.0 million (the “Term Loan Facility”). As part of the Term Loan Agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in deferred financing costs. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources and the parent guarantors entered into the First Amendment to the Term Loan Agreement (the “Term Loan Amendment”) with the Term Loan Administrative Agent and the Term Loan Lenders party thereto. Pursuant to the Term Loan Amendment, the parties agreed, among other things, to amend the Term Loan Agreement to permit the issuance of the Second Lien Notes and the Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payable in cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to: • introducing call protection of 102% until the first anniversary of the Exchange Transaction and 101% until the second anniversary of the Exchange Transaction (defined below); • introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility as more thoroughly described in the Term Loan Amendment; • deleting the ability to increase commitments under the Term Loan; • increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement); • removing the ability to create, invest in and utilize unrestricted subsidiaries; • further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Term Loan Amendment; and • providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term Loan Amendment. At December 31, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Facility. Following the Exchange Transaction, the Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable in-kind (“PIK”) upon election by Ultra Resources. The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Facility matures on April 12, 2024. In conjunction with the Exchange Transaction, the Term Loan Amendment was evaluated under FASB ASC 470-50-40, Debt Modifications and Extinguishments The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan Facility. The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At December 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement. The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement. Second Lien Notes . On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources issued $545.0 million aggregate principal amount of Second Lien Notes and entered into an Indenture, dated as of December 21, 2018 (the “Second Lien Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent. In January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for $27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions. Such Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. The Company will evaluate the treatment of the follow-on exchanges under the same accounting literature used in the Exchange Transaction . The Second Lien Notes will mature on July 12, 2024. Interest on the Second Lien Notes will accrue at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019. The Second Lien Notes are senior secured obligations of Ultra Resources and rank senior in right of payment to all of its existing and future unsecured senior debt, to the extent of the value of the collateral pledged under the Second Lien Notes Indenture and related collateral arrangements, senior in right of payment to all of its future subordinated debt, and junior in right of payment to all of its existing and future secured debt of senior priority, to the extent of the value of the collateral pledged thereby. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company. Payment by Ultra Resources of all amounts due on or in respect of the Second Lien Notes and the performance of Ultra Resources under the Indenture are initially guaranteed by the Company. Prior to December 21, 2021, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the Second Lien Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 111.000% of the principal amount of the Second Lien Notes, plus accrued and unpaid interest (including PIK interest), if any, to the date of redemption, if at least 65% of the original principal amount of the Second Lien Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before December 21, 2019, Ultra Resources may redeem all or a part of the Second Lien Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest (including PIK interest), if any, to the redemption date. In addition, on or after December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to 105.500% for the twelve-month period beginning on December 21, 2021, 102.750% for the twelve-month period beginning December 21, 2022, and 100.000% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plus accrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes. If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second Lien Notes may require the Issuer to repurchase all or a portion of its Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount of such Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase. The Second Lien Notes Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur or redeem indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) pay cash dividends, (vi) change the nature of its business or operations, (vii) make certain types of investments, (ix) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (x) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Second Lien Notes Indenture); and (xi) create unrestricted and foreign subsidiaries. The covenants in the Second Lien Notes Indenture are subject to important exceptions and qualifications. Subject to conditions, the Second Lien Notes Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Second Lien Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. The Second Lien Notes Indenture contains customary events of default. Unless otherwise noted in the Second Lien Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to the Company and the Trustee, may declare the Second Lien Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) or group of Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Second Lien Notes to become due and payable. In conjunction with the Exchange Transaction, the portion of the senior Unsecured Notes which were exchanged for Second Lien Notes was accounted for as a TDR. The Company evaluated the quantitative and qualitative factors in the accounting literature and concluded that concessions were granted as the future The Exchange Transaction for the Second Lien Notes resulted in recognition of $4.7 million in expenses for the year ended December 31, 2018. The exchanged debt resulted in a calculation of cancellation of debt income for tax purposes. Our current tax attributes are expected to offset any potential cash tax impacts from the Exchange Transaction. For additional details on the Company’s income taxes, refer to Note 10. Senior Unsecured Notes . On April 12, 2017, Ultra Resources issued $700.0 million of its 2022 Notes and $500.0 million of its 2025 Notes and entered into an Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as Trustee . The Unsecured Notes are treated as a single class of securities under the Unsecured Notes Indenture. On December 21, 2018, the Company completed the Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principal amount, or 55.0%, of the issued and outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes and (b) an aggregate of 10,919,499 new warrants of the Company each entitling the holder thereof to purchase one common share of the Company. As a result of the Exchange Transaction, at December 31, 2018, the aggregate principal amounts outstanding under the Unsecured Notes were approximately $195.0 million with respect to the 2022 Notes and $225.0 million with respect to the 2025 Notes. The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity. On December 21, 2018, in connection with the consummation of the Exchange Transaction, Ultra Resources, the Company and its other subsidiaries, as guarantors, and the Trustee entered into the First Supplement Indenture to the Unsecured Indenture (the “Supplemental Indenture”). Pursuant to the Supplemental Indenture, the parties amended the Unsecured Indenture to, among other things, eliminate or amend substantially all of the restrictive covenants contained in the Unsecured Indenture, other than those relating to the payment of principal and interest. The Supplemental Indenture is binding on all Unsecured Notes that remain outstanding. The Unsecured Notes Indenture contains customary events of default. Unless otherwise noted in the Unsecured Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Unsecured Notes Indenture) or group of Restricted Subsidiaries (as defined in the Unsecured Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable.

Share Based Compensation

Share Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share Based Compensation	Valuation and Expense Information Year Ended December 31, 2018 2017 2016 Total cost of share-based payment plans $ 15,639 $ 53,952 $ 8,013 Amounts capitalized in oil and gas properties and equipment $ 3,814 $ 13,975 $ 2,451 Amounts charged against income, before income tax benefit $ 11,825 $ 39,977 $ 5,562 Amount of related income tax benefit recognized in income before valuation allowances $ 2,483 $ 15,927 $ 2,216 Securities Authorized for Issuance Under Equity Compensation Plans As of December 31, 2018, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury. Plan Category Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (000’s) Equity compensation plans approved by security holders 14,457 Equity compensation plans not approved by security holders n/a Total 14,457 Performance Share Plans : 2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan was established by our board of directors (the “Board”) pursuant to which 7.5% of the equity of the Company (on a fully-diluted/fully distributed basis) is reserved for grants to be made from time-to-time to the directors, officers, and other employees of the Company (the “Reserve”). During 2017, management incentive grants (the “Initial MIP Grants”) were made to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, such Initial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time. In June 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of the Ultra Petroleum Corp. 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends and restates the 2017 Stock Incentive Plan to, among other things: • provide that consultants, independent contractors and advisors are eligible to participate and receive equity awards in the A&R Stock Incentive Plan; • limit the aggregate incentive awards available to be granted to any outside director during a single calendar year to a maximum of $750,000; • revise the definition of a Change of Control to exclude a change in a majority of the members on the Board; • provide that, with respect to awards granted on or after June 8, 2018, no such awards will vest solely as a result of a Change of Control (as defined in the A&R Stock Incentive Plan) unless expressly provided otherwise in the applicable grant agreement or unless otherwise determined by the Committee; and • make certain other changes related to revisions to the U.S. Internal Revenue Code. In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvested portion of their Initial MIP Grants for new equity awards of time-based restricted stock units (the “2018 RSUs”) effective July 31, 2018 on a one-for-one basis. All 2018 RSUs are time-based awards and vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation Long Term Incentive Awards. In 2018, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The awards cover a performance period of three years and includes time-based and performance-based measures established by the Committee at the beginning of the three-year period. Stock-Based Compensation Cost: Market-Based Condition Awards. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’s total equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an award that is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the awards that include a market condition. FASB ASC 718 requires the expense for an award of stock-based compensation that is subject to a market condition that can be attained at any point during the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and (b) award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on which the market condition is satisfied. The duration is the period of time from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is actually satisfied. Expense. For the year ended December 31, 2018, the Company recognized $11.8 million in pre-tax compensation expense, of which $10.9 million related to the Initial MIP Grants. For the year ended December 31, 2017, the Company recognized $40.0 million in pre-tax compensation expense, of which $38.5 million related to the Initial MIP Grants. For the year ended December 31, 2016, the Company recognized $5.6 million in pre-tax compensation expense, of which $4.7 million related to the Company’s 2015 and 2014 long-term incentive plan awards. The Company expects the total expense associated with the portion of the Initial MIP Grants that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $21.3 million and the portion of the Initial MIP grants that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $19.6 million, respectively.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	8 . Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program. These types of instruments may include fixed price swaps, costless collars, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices. The Company’s Revolving Credit Facility requires the Company to hedge 65% of forecast proved producing natural gas production, based on its most recent reserve report for 18 months from the end of the given quarter. This requirement is in effect through September 30, 2019. After that time, the requirement decreases to 50% of the estimated proved producing forecast for natural gas through March 31, 2020. This means the Company may unwind hedges after September 30, 2019 at its discretion providing the Company remains hedged at the 50% level for natural gas. Additionally, the Revolving Credit Facility limits the amount of hedging to 85% of forecast production for all products within a given quarter. Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Consolidated Statements of Cash Flows. Commodity Derivative Contracts: At December 31, 2018, the Company had the following open commodity derivative contracts to manage commodity price risk. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable to the counterparty. For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period. For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below the floor on a notional quantity. The reference prices of these commodity derivative contracts are typically referenced to index prices published by independent third parties. Type Index Total Volumes (in millions) Weighted Average Price Per Unit Fair Value - December 31, 2018 Asset (Liability) Natural Gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 NYMEX-Henry Hub 185.9 $ 2.81 $ (12,832 ) 2020 NYMEX-Henry Hub 22.8 $ 2.76 $ (4,506 ) Natural Gas basis swaps (Mmbtu) ($/Mmbtu) 2019 NW Rockies Basis Swap 105.9 $ 0.67 $ (41,286 ) Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 NYMEX-WTI 1.4 $ 58.45 $ 15,143 2020 NYMEX-WTI 0.1 $ 60.05 $ 994 Type Index Total Volumes (in millions) Weighted Average Floor Price Weighted Average Ceiling Price Fair Value - December 31, 2018 Asset (Liability) Natural Gas collars 2020 NYMEX 9.1 $ 2.75 $ 3.19 $ (346 ) Subsequent to December 31, 2018, the Company entered into commodity derivative contracts to manage commodity price risk as detailed and described in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016: For the Year Ended December 31, Commodity Derivatives: 2018 2017 2016 Realized gain (loss) on commodity derivatives-natural gas (1) $ (77,031 ) $ 11,446 $ — Realized gain (loss) on commodity derivatives-crude oil(1) (8,382 ) — — Unrealized gain (loss) on commodity derivatives (1) (59,799 ) 16,966 — Total gain (loss) on commodity derivatives $ (145,212 ) $ 28,412 $ — (1) Included in Gain (loss) on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	9 . As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories: Level 1 : Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Level 2 : Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps. Level 3 : Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 23,374 $ — $ 23,374 Long-term derivative asset (1) — 1,203 — 1,203 Total derivative instruments $ — $ 24,577 $ — $ 24,577 Liabilities: Current derivative liability $ — $ 62,350 $ — $ 62,350 Long-term derivative liability (2) — 5,060 — 5,060 Total derivative instruments $ — $ 67,410 $ — $ 67,410 (1) Included in Other assets in the Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Consolidated Balance Sheet. Assets and Liabilities Measured on a Non-Recurring Basis The Company uses fair value to determine the value of its asset retirement obligations. The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs. Fair Value of Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt and the fair values presented in the tables below reflect original maturity dates for each of the debt instruments. The inputs utilized to estimate the fair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows. For the Year Ended December 31, 2018 2017 Principal Estimated Fair Value Principal Estimated Fair Value Credit Agreement, secured $ 104,000 $ 104,000 $ — $ — Term Loan, secured due 2024 975,000 858,000 975,000 975,000 Second Lien Notes, secured due 2024 (1) 545,000 395,125 — — 6.875% Senior, unsecured Notes, due 2022 195,035 68,262 700,000 701,750 7.125% Senior, unsecured Notes, due 2025 225,000 69,750 500,000 505,000 Total debt $ 2,044,035 $ 1,495,137 $ 2,175,000 $ 2,181,750 (1) The fair value on Second Lien Notes is priced as of January 8, 2019, the first available trade date.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	10 . Income before income tax benefit is as follows: Year Ended December 31, 2018 2017 2016 United States $ 86,242 $ (197,136 ) $ 134,959 Foreign (593 ) 360,982 (79,462 ) Total $ 85,649 $ 163,846 $ 55,497 The consolidated income tax provision (benefit) is comprised of the following: Year Ended December 31, 2018 2017 2016 Current tax: U.S. federal, state and local $ 433 $ (13,296 ) $ (72 ) Foreign 9 2 (583 ) Total current tax provision (benefit) 442 (13,294 ) (655 ) Deferred tax: Foreign — — 1 Total deferred tax expense — — 1 Total income tax provision (benefit) $ 442 $ (13,294 ) $ (654 ) The income tax provision (benefit) from operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 21% to pretax income as a result of the following: Year Ended December 31, 2018 2017 2016 Income tax provision computed at the U.S. statutory rate $ 17,986 $ 57,346 $ 19,424 State income tax (benefit) provision net of federal effect — (25,519 ) (2,335 ) Valuation allowance (30,723 ) (562,491 ) (31,083 ) Tax effect of rate change — 463,113 — Sale of non-core assets 5,863 130,552 — Foreign rate differential (36 ) (3,150 ) 17,388 Reorganization items 216 (89,327 ) — Equity compensation 2,689 10,778 1,599 Other, net 4,447 5,404 (5,647 ) Total income tax provision (benefit) $ 442 $ (13,294 ) $ (654 ) The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows: December 31, 2018 2017 Deferred tax assets: Property and equipment 33,953 181,524 Deferred gain 19,874 22,256 U.S. federal tax credit carryforwards 512 987 U.S. interest carryforwards 5,931 — U.S. net operating loss carryforwards 462,401 450,623 U.S. state net operating loss carryforwards — 4,038 Non-U.S. net operating loss carryforwards 7,048 6,556 Asset retirement obligations 37,687 36,624 Derivative instruments, net 8,995 — Debt financing 92,706 — Incentive compensation 5,370 6,585 Other, net 2,148 1,723 Total deferred tax assets, gross 676,625 710,916 Valuation allowance (676,625 ) (707,348 ) Net deferred tax assets $ — $ 3,568 Deferred tax liabilities: Derivative instruments, net — 3,568 Net tax liabilities $ — $ 3,568 Net tax asset $ — $ — In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible or before the attributes expire unused. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies. At December 31, 2018 and 2017, the Company recorded a valuation allowance against certain deferred tax assets of $0.7 billion and $0.7 billion, respectively. Some or all of this valuation allowance may be reversed in future periods if future taxable income of the appropriate character is available to recognize certain deferred tax assets. The Company has a U.S. federal tax net operating loss carryforward of $2.2 billion as of December 31, 2018, which will be carried forward to offset taxable income generated in future years, and if unutilized, will expire between 2033 and 2037 for net operating losses generated in tax years 2017 and earlier. Federal net operating losses generated in tax years 2018 and later carry forward indefinitely and are limited to 80% of taxable income, if utilized. The Company has immaterial Canadian Federal and Provincial and U.S. State tax net operating loss carry forwards that it does not expect to utilize before they expire, as the Company has minimal or no activity in these jurisdictions. The ownership change that occurred as a result of the Company’s chapter 11 restructuring did not significantly impair the ability to utilize the net operating loss carryforwards to offset future taxable income. Without regard to the recorded valuation allowance, if the Company experiences an additional ownership change as determined under Section 382 of the Internal Revenue Code, our ability to utilize our substantial net operating loss carryforwards and other tax attributes may be limited, if we can use them at all. The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2018. Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits. The Company files a consolidated federal income tax return in the United States, as well as an income tax return in Canada. With certain exceptions, the income tax years 2015 through 2018 remain open to examination by the major taxing jurisdictions in which the Company has business activity. The Company has been notified that Canada intends to audit tax years 2015 and 2016. Management does not expect the results of the audit to materially impact the Company’s financial statements. The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. It is not practical to estimate the amount of unrecognized deferred tax liability related to undistributed foreign earnings at this time. No provision for Canadian income taxes and/or withholding taxes has been provided thereon. On December 22, 2017, the Tax Act was enacted into law. The new legislation decreased the U.S. corporate federal income tax rate from 35% to 21% effective January 1, 2018. The Company did not have any impact on recorded deferred tax balances as the re-measurement of net deferred tax assets was offset by a change in the valuation allowance. The Tax Act also included a number of other provisions including the elimination of loss carrybacks and limitations on the use of future loss carryforwards, repeal of the “alternative minimum tax” regime, limitations on the deductibility of certain expenses, including net interest expense, and changes in the way capital costs are recovered. These provisions are not expected to have an immediate effect on the Company. The Tax Act did not make significant changes to the Company’s ability to deduct intangible development costs or depletion. The Company’s significant net operating loss carryforwards generated in 2017 and before are grandfathered under the provisions of the Tax Act and should not be subject to the new limitations imposed by the Tax Act. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue to be issued at times. The Company will continue to monitor these new regulations and analyze their applicability and impact on the Company. The SAB 118 period expired, and no adjustments were made to the provisional accounting adjustments reporting in 2017.

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Employee Benefits	1 1 . EMPLOYEE BENEFITS: The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $2.5 million, $2.4 million and $2.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	1 2 . COMMITMENTS AND CONTINGENCIES: Leases Pinedale LGS During December 2012, the Company sold a system of pipelines and central gathering facilities (the “Pinedale LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Pinedale Lease Agreement”) relating to the use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the Pinedale LGS at the sole discretion of the Company. Annual rent for the initial term under the Pinedale Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase when certain volume thresholds are exceeded. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Pinedale Lease Agreement will total approximately $195.7 million. All of the Company’s lease obligations are related to leases that are classified as operating leases under ASC 840. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases. Office space lease The Company maintains office space in Colorado and Wyoming, with total remaining commitments for office leases of $3.9 million at December 31, 2018; ($1.2 million in 2019; $1.1 million in 2020; $1 million in 2021; and $0.6 million in 2022. During the years ended December 31, 2018, 2017 and 2016, the Company recognized expense associated with its office leases in the amount of $1.6 million, $1.6 million, and $1.5 million, respectively. Delivery Commitments With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Part I. Item 1A. “Risk Factors.” If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments. Litigation Matters Pending Claims – Ultra Resources Indebtedness Claims The Plan provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Annual Report on Form 10-K, the claims resolution process associated with chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time. Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest dates, unpaid post-petition interest (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Company’s emergence from bankruptcy, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and post-petition interest at the default rates provided for in the debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, $399.0 million was distributed from the Reserve Fund to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above, which are included in reorganization items in the Consolidated Statements of Operations as of December 31, 2017, and $175.2 million representing the postpetition interest at the default rate, as described above, which is included in interest expense in the Consolidated Statements of Operations as of December 31, 2017. The Company appealed the court order denying its objections to these claims to the United States Court of Appeals for the Fifth Circuit (the “Appellate Court”). During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company. On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to the asserted make-whole and post-petition interest claims and remanding the matter and those determinations to the Bankruptcy Court for further reconsideration. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimate disposition of these matters at this time. Royalties On April 19, 2016, the Company received a preliminary determination notice from the Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under Federal oil and gas leases for the 2010, 2011, and 2012 time periods (the “Audit Period”). ONRR also filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims related to these matters. We disputed the preliminary determination and the proof of claim. We notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice and the Company continues to believe that natural gas sold during this period was in marketable condition and, therefore, no disallowances were necessary in the calculation of royalties. This claim could ultimately result in us being required to pay additional royalties to ONRR with respect to the Audit Period as well as additional royalties in respect of the years following the Audit Period. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material. Oil Sales Contract On April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) the Company had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and on December 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of the contract by SPMT during the prepetition period (as amended, the “Sunoco Adversary”). In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters addressed in its proof of claim. On October 16, 2018, the Company reached a settlement agreement with SPMT. Under the terms of the agreement, the Company will pay SPMT a total of $2.0 million, of which $1.0 million was paid as of December 31, 2018. Other Claims The Company is party to disputes with respect to overriding royalty interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, and as no damage claim amount has been asserted by the claimants, we cannot reasonably estimate the potential impact of these claims. We are defending these cases vigorously, and expect these claims to be resolved in our chapter 11 proceedings. The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2018
Risks And Uncertainties [Abstract]
Concentration of Credit Risk	1 3 . CONCENTRATION OF CREDIT RISK: The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivative contracts associated with the Company’s hedging program. The Company’s revenues related to natural gas and oil sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time. The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2018. A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2018, the Company had no single customer that represented more than 10% of its total revenues.

2016_2017 Chapter 11 Proceeding

2016/2017 Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2018
Reorganizations [Abstract]
2016/2017 Chapter 11 Proceedings	14. 2016/2017 CHAPTER 11 PROCEEDINGS Voluntary Reorganization Under Chapter 11 and Ability to Continue as a Going Concern On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, “the Debtors”) filed voluntary petitions under chapter 11 of title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization Plan of Reorganization Pursuant to the Plan, the significant transactions that occurred upon our emergence from chapter 11 proceedings were as follows : • On November 21, 2016, we entered into a Plan Support Agreement (as amended, the “PSA”) with certain holders of the Company’s prepetition indebtedness and outstanding common stock as well as a Backstop Commitment Agreement (“BCA”). Pursuant to the BCA, we agreed to conduct a rights offering for new common stock in the Company to be issued upon the effectiveness of the Plan for an aggregate purchase price of $580.0 million (the “Rights Offering”). • On February 8, 2017, we entered into a commitment letter with Barclays Bank PLC (“Barclays”) (as amended, the “Commitment Letter”) pursuant to which, in connection with the consummation of the Plan, Barclays agreed to • On the Effective Date, the principal obligations outstanding of $999.0 million under the prepetition credit agreement and $1.46 billion under the prepetition senior notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under the prepetition credit agreement and the prepetition senior notes were cancelled and extinguished as provided in the Plan. • On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 million related to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full, each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan. • On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy. Fresh Start Accounting We were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims. Bankruptcy Claims Resolution Process The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained. As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed. Costs of Reorganization During 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below. The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: For the Twelve Months Ended December 31, 2017 2016 Professional fees $ (66,529 ) $ (11,781 ) Gains (losses) (1) 431,107 — Deferred financing costs — (18,742 ) Contract settlements — (17,350 ) Make-whole fees (223,838 ) — Other (2) 167 370 Total Reorganization items, net $ 140,907 $ (47,503 ) ( 1 ) Gains (losses) represent the net gain on the debt to equity exchange related to the Company’s prepetition senior notes. ( 2 ) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	1 5 . SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to December 31, 2018 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below: 2019 Debt Exchanges As previously noted, in January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for $27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions. Such Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. Make-Whole and Postpetition Interest Claims As previously disclosed, during the Company’s bankruptcy proceedings, many holders of the Company’s prepetition indebtedness filed proofs of claim with the Bankruptcy Court, asserting various claims against the Company, including claims for unpaid postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. The Company disputed the claims made by the holders of Company’s prepetition indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the prepetition debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. Further, on October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, the Company distributed $399.0 million from a $400.0 million reserve fund set up in connection with its emergence from chapter 11 proceedings to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate. During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company. On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to the asserted make-whole and postpetition interest claims and remanding the matter and those determinations to the Bankruptcy Court for further reconsideration. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimate disposition of these matters at this time. Revolving Credit Facility Amendment As described in Note 6, Ultra Resources entered into a Fourth Amendment to Credit Agreement with the Agent and the Lenders party thereto on February 14, 2019. Pursuant to the Fourth Amendment, the Borrowing Base was reaffirmed at $1.3 billion for the spring 2019 period, providing $325 million of availability to the Company as a result of the semi-annual borrowing base redetermination. The next scheduled semi-annual borrowing base redetermination is scheduled for the fall of 2019. The Fourth Amendment also revises certain covenants and other provisions of the Credit Agreement, including, but not limited to: • amending the Consolidated Net Leverage Ratio financial covenant to provide that, as of the last day of (i) the fiscal quarter ending December 31, 2018, Ultra Resources will not permit the Consolidated Net Leverage Ratio (as defined in the Credit Agreement) to exceed 4.50 to 1.0, (ii) each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019, Ultra Resources will not permit the Consolidated Net Leverage Ratio to exceed 4.75 to 1.0, (iii) each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020, Ultra Resources will not permit the Consolidated Net Leverage Ratio to exceed 4.90 to 1.0, (iv) the fiscal quarter ending September 30, 2020, Ultra Resources will not permit the Consolidated Net Leverage Ratio to exceed 4.5 to 1.0, and (v) the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter, Ultra Resources will not permit the Consolidated Net Leverage Ratio to exceed 4.25 to 1.0. In addition, the consolidated net debt component of the Consolidated Net Leverage Ratio may be reduced if, among other things, any Credit Party (as defined in the Credit Agreement) receives certain settlement proceeds; • revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that represent an accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to senior management changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debt restructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of an accrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certain noncash charges that Ultra Resources chose to add back (as described in clause (i)); and • amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, current required amortization payments under the Term Loan Credit Agreement (as defined in the Credit Agreement).

Summarized Quarterly Financial

Summarized Quarterly Financial Information	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Information (Unaudited)	1 6 . SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 225,374 $ 190,138 $ 203,776 $ 273,211 $ 892,499 Operating expenses 137,686 127,679 126,872 145,506 537,743 Other income (expense), net: Interest expense (35,837 ) (37,715 ) (38,382 ) (36,382 ) (148,316 ) Loss on commodity derivatives (6,530 ) (47,271 ) (21,804 ) (69,607 ) (145,212 ) Contract settlement — — (2,676 ) 15,332 12,656 Other income (expense), net 2,606 1,981 4,521 2,657 11,765 Total other (expense) income, net (39,761 ) (83,005 ) (58,341 ) (88,000 ) (269,107 ) Income (loss) before income tax provision (benefit) 47,927 (20,546 ) 18,563 39,705 85,649 Income tax provision (benefit) 434 9 — (1 ) 442 Net (loss) income $ 47,493 $ (20,555 ) $ 18,563 $ 39,706 $ 85,207 Net income (loss) per common share — basic $ 0.24 $ (0.10 ) $ 0.09 $ 0.20 $ 0.43 Net income (loss) per common share — fully diluted $ 0.24 $ (0.10 ) $ 0.09 $ 0.20 $ 0.43 2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 220,958 $ 212,657 $ 217,631 $ 240,627 $ 891,873 Operating expenses 104,227 134,393 122,394 132,574 493,588 Other income (expense), net: Interest expense (85,447 ) (29,425 ) (210,107 ) (36,388 ) (361,367 ) Gain (loss) on commodity derivatives (13,218 ) 20,717 4,650 16,263 28,412 Contract settlement (52,707 ) — — — (52,707 ) Other income, net 2,491 2,665 2,730 2,430 10,316 Total other (expense) income, net (148,881 ) (6,043 ) (202,727 ) (17,695 ) (375,346 ) Reorganization items, net (57,546 ) 426,816 (227,123 ) (1,240 ) 140,907 Income (loss) before income tax (benefit) provision (89,696 ) 499,037 (334,613 ) 89,118 163,846 Income tax provision (benefit) 2 — (6,886 ) (6,410 ) (13,294 ) Net (loss) income $ (89,698 ) $ 499,037 $ (327,727 ) $ 95,528 $ 177,140 Net income (loss) per common share — basic $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 Net income (loss) per common share — fully diluted $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08

Disclosure About Oil and Gas Pr

Disclosure About Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2018
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Disclosure About Oil and Gas Producing Activities (Unaudited)	1 7 . DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures: OIL AND GAS RESERVES: Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. Our Director of Reservoir and Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates and has a Bachelor of Science degree in Petroleum Engineering with over 14 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. The estimates of proved reserves and future net revenue as of December 31, 2018, are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment. The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years. The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the years ended December 31, 2018, 2017 and 2016 in this annual report. Our internal professional staff works closely with NSAI to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report. The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over seven years of prior industry experience. He graduated from graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA. The following unaudited tables as of December 31, 2018, 2017 and 2016 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2018, 2017 and 2016. All such reserves were located in the Green River Basin in Wyoming for the year ended December 31, 2018, in the Green River Basin in Wyoming and the Uinta Basin in Utah for the year ended December 31, 2017, and in the Green River Basin in Wyoming, the Appalachian Basin in Pennsylvania and the Uinta Basin in Utah for the year ended December 31, 2016. ANALYSES OF CHANGES IN PROVEN RESERVES: United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Reserves, December 31, 2015 2,336,280 22,175 9,840 Extensions, discoveries and additions 251,634 3,519 530 Sales — — — Acquisitions — — — Production (264,278 ) (2,912 ) — Revisions (2,023 ) (1,307 ) (467 ) Reserves, December 31, 2016 2,321,613 21,475 9,903 Extensions, discoveries and additions 50,312 1,117 — Sales (89,315 ) — — Acquisitions 22,400 153 — Production (260,009 ) (2,775 ) — Revisions 910,991 7,148 (9,832 ) Reserves, December 31, 2017 2,955,992 27,118 71 Extensions, discoveries and additions 85,180 1,086 — Sales (4,033 ) (3,573 ) (71 ) Acquisitions — — — Production (260,406 ) (2,442 ) — Revisions 145,100 1,256 — Reserves, December 31, 2018 2,921,833 23,445 — United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Proved: Developed 2,336,280 22,175 9,840 Undeveloped — — — Total Proved — 2015 2,336,280 22,175 9,840 Developed 2,321,613 21,475 9,903 Undeveloped — — — Total Proved — 2016 2,321,613 21,475 9,903 Developed 2,261,289 21,652 71 Undeveloped 694,703 5,466 — Total Proved — 2017 2,955,992 27,118 71 Developed 2,243,956 17,876 — Undeveloped 677,877 5,569 — Total Proved — 2018 2,921,833 23,445 — Changes in proved developed reserves : During 2018, substantially all of the changes were attributable to wells drilled in 2018. Changes in proved undeveloped reserves : The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years. Development plan : The development plan underlying the Company’s proved undeveloped reserves, if any, adopted each year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data, and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions of previously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders. STANDARDIZED MEASURE: The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2018, 2017 and 2016 was $2.59, $2.59 and $2.07 per Mcf, respectively, for natural gas, and $63.49, $48.05 and $37.90 per barrel, respectively, for oil and condensate. In 2014, the Company acquired contracts related to NGLs providing an annual election to process NGLs beginning in 2017. In 2017, the Company renegotiated its existing gas processing contracts in Wyoming. The new gas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include the NGL volumes in its reserves. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers. As of December 31, 2018 2017 2016 Future cash inflows $ 9,195,725 $ 8,965,949 $ 5,812,234 Future production costs (3,337,779 ) (3,587,581 ) (2,665,082 ) Future development costs (1,133,103 ) (1,001,024 ) (355,923 ) Future income taxes (180,057 ) — — Future net cash flows 4,544,786 4,377,344 2,791,229 Discount at 10% (2,139,303 ) (1,993,016 ) (1,100,283 ) Standardized measure of discounted future net cash flows $ 2,405,483 $ 2,384,328 $ 1,690,946 The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: December 31, 2018 2017 2016 Standardized measure, beginning $ 2,384,328 $ 1,690,946 $ 1,865,649 Net revisions of previous quantity estimates 160,405 840,505 (9,623 ) Extensions, discoveries and other changes 90,609 53,549 209,603 Sales of reserves in place (34,768 ) (83,887 ) — Acquisition of reserves — 21,903 — Changes in future development costs (235,205 ) (329,635 ) 11,556 Sales of oil and gas, net of production costs (593,134 ) (589,621 ) (454,725 ) Net change in prices and production costs 362,084 572,224 (72,939 ) Development costs incurred during the period that reduce future development costs 251,621 8,007 22,523 Accretion of discount 238,433 169,095 186,565 Net changes in production rates and other (189,017 ) 31,242 (67,663 ) Net change in income taxes (29,873 ) — — Aggregate changes 21,155 693,382 (174,703 ) Standardized measure, ending $ 2,405,483 $ 2,384,328 $ 1,690,946 There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES: Years Ended December 31, 2018 2017 2016 United States Property Acquisitions: Unproved $ 1,468 $ 1,399 $ 983 Proved 1,090 9,147 — Exploration* 156,718 510,710 224,277 Development 266,905 35,934 44,300 Total $ 426,181 $ 557,190 $ 269,560 * Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: Years Ended December 31, 2018 2017 2016 United States Oil and gas revenue $ 892,499 $ 891,873 $ 721,091 Production expenses (299,365 ) (292,095 ) (266,366 ) Depletion and depreciation (204,255 ) (161,945 ) (125,121 ) Income tax benefit (expense) (2 ) (168,355 ) 83,112 Total $ 388,877 $ 269,478 $ 412,716 CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,577,281 $ 11,215,563 Less: accumulated depletion, depreciation and amortization (10,079,554 ) (9,890,495 ) Total Oil and gas properties, net $ 1,497,727 $ 1,325,068

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2018
Supplemental Financial Statement Information [Abstract]
Supplemental Financial Statement Information	1 8 . SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: Following are the financial statements of Ultra Petroleum Corp. (the “Parent Company”), which are included to provide additional information with respect to the Parent Company’s results of operations, financial position and cash flows on a stand-alone basis: CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2018 2017 2016 General and administrative expense $ 549 $ 428 $ 650 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) — (71,876 ) (26,590 ) Income (loss) from unconsolidated affiliates 85,809 (183,840 ) 157,450 Guarantee fee income — — 6,073 Other expense (44 ) 90 (64,888 ) Reorganization items, net — 433,196 (15,827 ) Income before income taxes 85,216 177,142 55,568 Income tax provision (benefit) 9 2 (583 ) Net income $ 85,207 $ 177,140 $ 56,151 CONDENSED BALANCE SHEET December 31, 2018 December 31, 2017 ASSETS Current Assets: Cash and cash equivalents $ 570 $ 803 Accounts receivable from related companies 29,939 29,940 Other current assets — — Total current assets 30,509 30,743 Other non-current assets — — Total assets $ 30,509 $ 30,743 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ — $ 21 Total current liabilities — 21 Advances from unconsolidated affiliates 1,079,131 1,185,359 Total liabilities 1,079,131 1,185,380 Total shareholders’ deficit (1,048,622 ) (1,154,637 ) Total liabilities and shareholders’ equity $ 30,509 $ 30,743 CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2018 2017 2016 Net cash (used in) operating activities $ (234 ) $ (2,206 ) $ (21,309 ) Investing Activities: Investment in subsidiaries (3,293 ) (588,677 ) — Dividends received — — 24,089 Net cash (used in) provided by investing activities (3,293 ) (588,677 ) 24,089 Financing activities: Deferred financing costs — — — Shares issued 3,294 573,774 — Repurchased shares/net share settlements — 14,903 43 Shares re-issued from treasury — — (337 ) Net cash provided by (used in) financing activities 3,294 588,677 (294 ) (Decrease) increase in cash during the period (233 ) (2,206 ) 2,486 Cash and cash equivalents, beginning of period 803 3,009 523 Cash and cash equivalents, end of period $ 570 $ 803 $ 3,009

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of presentation and principles of consolidation	Basis of presentation and principles of consolidation : The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated.
Cash and Cash Equivalents	Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash	Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. The Company adopted Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash and reports the change in cash, cash equivalents, and restricted cash in total on the Consolidated Statement of Cash Flows as of December 31, 2017. The Consolidated Statement of Cash Flows as of December 31, 2016 has been adjusted to conform to the new standard. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Financial Statements: Current Presentation December 31, 2018 December 31, 2017 December 31, 2016 Cash and Cash Equivalents $ 17,014 $ 16,631 $ 401,478 Restricted Cash 2,291 1,638 3,571 Total cash, cash equivalents, and restricted cash $ 19,305 $ 18,269 $ 405,049
Accounts Receivable	Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. Included in the Other expenses on the Consolidated Statements of Operations is the provision for uncollectible accounts of $4.9 million. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.
Property, Plant and Equipment	Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.
Oil and Natural Gas Properties	Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. While the Company does not have any material amounts as described in this paragraph at the current time, it has been a larger consideration in prior years. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation in 2018, 2017 or 2016.
Inventories	Inventories: Inventory includes $17.6 million in pipe and production equipment and miscellaneous materials and supplies that will be utilized during the 2019 drilling program, as well as $1.1 million in crude oil inventory. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 8).
Deferred Financing Costs	Deferred Financing Costs: The Company follows ASU No. 2015-03, for its Term Loan Facility, Second Lien Notes, and the Unsecured Notes and includes the costs for issuing debt including issuance discounts, as a direct deduction from the carrying amount of the related debt liability. Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements
Income Taxes	Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.
Warrants	Warrants: On December 21, 2018, in connection with the consummation of the Exchange Transaction, the Company issued 10,919,499 new Warrants. The Warrants are initially exercisable for one common share of the Company, no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the Common Shares is at least $2.50 per Common Share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof from the December 21, 2018 until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase Common Shares will terminate.
Earnings Per Share	Earnings Per Share: Basic earnings per share is computed by dividing net earnings (attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect. In conjunction with our emergence from chapter 11 proceedings, on April 12, 2017, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred as of the earliest period presented. Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator using the treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. For the years ended December 31, 2018 and 2017, the Company had 14.2 million and 3.9 million, respectively, of contingently issuable shares that are not included in the diluted earnings per share denominator. There were no contingently issuable shares outstanding for the year ended December 31, 2016. The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2018 2017 2016 Net income $ 85,207 $ 177,140 $ 56,151 Weighted average common shares outstanding during the period 196,964 163,824 79,996 Effect of dilutive instruments 577 152 367 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,541 163,976 80,363 Net income per common share — basic $ 0.43 $ 1.08 $ 0.70 Net income per common share — fully diluted $ 0.43 $ 1.08 $ 0.70 Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — 749
Use of Estimates	Use of Estimates: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Accounting for Share-Based Compensation	Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.
Fair Value Accounting	Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 9 for additional information.
Asset Retirement Obligation	Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.
Revenue Recognition	Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosures related to the Company’s adoption of this standard.
Other Revenues	Other revenues: Other revenues are comprised of fees paid to us by operators of the gas processing plants where our gas is processed in exchange for the liquids removed from our production.
Capital Cost Accrual	Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.
Reclassifications	Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the reported results of operations.
Recent Accounting Pronouncements	Recent Accounting Pronouncements: In May 2014, the FASB issued ASU 2014-09, and in 2016, the FASB issued ASU 2016-08, , and ASU 2016-10, , which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the cumulative impact of adopting the new revenue standard, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. Stock Compensation: In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s consolidated financial statements. Leases: In February 2016, the FASB established Topic 842, Leases, by issuing issued ASU 2016-02, Leases (“ASU No. 2016-02”), which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. On January 1, 2019, we adopted the new standard. A modified retrospective transition approach is required, applying the new standard to all leases existing at the date of initial application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. If an entity chooses the second option, the transition requirements for existing leases also apply to leases entered into between the date of initial application and the effective date. The entity must also recast its comparative period financial statements and provide the disclosures required by the new standard for the comparative periods. We adopted the new standard on January 1, 2019 and will use the effective date as our date of initial application. Consequently, financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. The new standard provides a number of optional practical expedients in transition. We expect to elect the ‘package of practical expedients’, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. We also expect to adopt the practical expedient pertaining to land easements. We do not expect to elect the use-of-hindsight. The new standard also provides practical expedients for an entity’s ongoing accounting. We expect to elect the short-term lease recognition exemption for all leases that qualify. For those leases that qualify, we will not recognize ROU assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. We will continue to evaluate the practical expedients related to lease and non-lease components. We expect that this standard will have a material effect on our financial statements. While we continue to assess all of the effects of adoption, we currently believe the most significant effects relate to (1) the recognition of new ROU assets and lease liabilities on our balance sheet for our office and equipment operating leases; and (2) the requirement to provide significant new disclosures about our leasing activities. These ROU assets and liabilities are not deemed to be debt within the definitions of our debt covenants. On adoption, we currently expect to recognize additional operating liabilities, with corresponding ROU assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. Derivatives: In August 2017, the FASB issued ASU 2017-12, (“ASU No. 2017-12”), which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements as the Company does not elect hedge accounting. Fair Value Measurements . In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Reconciliation of Cash, Cash Equivalents, and Restricted Cash	See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Financial Statements: Current Presentation December 31, 2018 December 31, 2017 December 31, 2016 Cash and Cash Equivalents $ 17,014 $ 16,631 $ 401,478 Restricted Cash 2,291 1,638 3,571 Total cash, cash equivalents, and restricted cash $ 19,305 $ 18,269 $ 405,049
Reconciliation of Components of Basic and Diluted Net Income Per Common Share	The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2018 2017 2016 Net income $ 85,207 $ 177,140 $ 56,151 Weighted average common shares outstanding during the period 196,964 163,824 79,996 Effect of dilutive instruments 577 152 367 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,541 163,976 80,363 Net income per common share — basic $ 0.43 $ 1.08 $ 0.70 Net income per common share — fully diluted $ 0.43 $ 1.08 $ 0.70 Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — 749

Impact of ASC 606 Adoption - _2

Impact of ASC 606 Adoption - Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Standards Update 2014-09
Schedule of Impact of Adoption on Consolidated Income Statement	In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for twelve months ended December 31, 2018 is as follows: For the Twelve Months Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 722,313 $ 722,365 $ (52 ) Oil sales 153,534 153,534 — Other revenues 16,652 16,652 — Costs and expenses: Production taxes $ 93,322 $ 93,326 $ (4 ) Gathering fees 89,806 89,812 (6 ) Net income: $ 85,207 $ 85,249 $ (42 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the activities for the Company’s asset retirement obligations for the years ended: December 31, 2018 2017 Asset retirement obligations at beginning of period $ 173,100 $ 157,173 Accretion expense 12,342 11,689 Liabilities incurred 3,558 8,174 Liabilities divested (1) (2) (9,372 ) (4,812 ) Liabilities acquired - 1,456 Liabilities settled (70 ) (598 ) Revisions of estimated liabilities (96 ) 18 Asset retirement obligations at end of period 179,462 173,100 Less: current asset retirement obligations (193 ) (263 ) Long-term asset retirement obligations (3) $ 179,269 $ 172,837 (1) During the year ended December 31, 2018, the Company divested certain non-core properties in Utah. (2) During the year ended December 31, 2017, the Company divested certain non-core properties in north-central Pennsylvania. (3) Included in Other long-term obligations in the Consolidated Balance Sheet.

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2018
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties	December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,577,281 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (10,079,554 ) (9,890,495 ) Total Oil and gas properties, net 1,497,727 1,325,068

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property Plant And Equipment [Abstract]
Schedule of Property, Plant and Equipment	December 31, 2018 2017 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,828 (2,209 ) 619 554 Office equipment 265 (200 ) 65 95 Leasehold improvements 264 (178 ) 86 120 Land 2,437 — 2,437 4,637 Production and other equipment 20,232 (11,804 ) 8,428 4,163 Property, plant and equipment, net $ 26,026 $ (14,391 ) $ 11,635 $ 9,569

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Outstanding Debt And Other Long Term Obligations Tables [Abstract]
Summary of Long Term Debt	December 31, 2018 Principal Unamortized Deferred Financing Costs and Discounts (1) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement $ 104,000 $ — $ — $ 104,000 Term Loan, secured, due 2024 975,000 (26,874 ) — 948,126 Second Lien Notes, secured, due 2024 545,000 — 228,096 773,096 6.875% Unsecured Notes due 2022 195,035 (15,168 ) — 179,867 7.125% Unsecured Notes due 2025 225,000 (14,608 ) — 210,392 $ 2,044,035 $ (56,650 ) $ 228,096 $ 2,215,481 Less: Current maturities 7,313 — — 7,313 Total Long-term debt $ 2,036,722 $ (56,650 ) $ 228,096 $ 2,208,168 December 31, 2017 Principal Unamortized Deferred Financing Costs and Discounts (1) Carrying Value Credit Agreement $ — $ — $ — Term Loan, secured, due 2024 975,000 (23,357 ) 951,643 6.875% Unsecured Notes due 2022 700,000 (19,084 ) 680,916 7.125% Unsecured Notes due 2025 500,000 (16,348 ) 483,652 $ 2,175,000 $ (58,789 ) $ 2,116,211 Less: Current maturities — — — Total Long-term debt $ 2,175,000 $ (58,789 ) $ 2,116,211 (1) Deferred financing costs related to the Revolving Credit Facility are reported within Other assets on the consolidated balance sheet, rather than as a reduction of the carrying amount of long-term debt.
Summary of Aggregate Maturities of Debt	Aggregate maturities of debt at December 31, 2019 $ 7,313 2020 $ 9,750 2021 $ 9,750 2022 $ 308,785 2023 $ 9,750 Beyond 5 years $ 1,698,687 Total $ 2,044,035

Share Based Compensation (Table

Share Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Valuation and Expense Information	Valuation and Expense Information Year Ended December 31, 2018 2017 2016 Total cost of share-based payment plans $ 15,639 $ 53,952 $ 8,013 Amounts capitalized in oil and gas properties and equipment $ 3,814 $ 13,975 $ 2,451 Amounts charged against income, before income tax benefit $ 11,825 $ 39,977 $ 5,562 Amount of related income tax benefit recognized in income before valuation allowances $ 2,483 $ 15,927 $ 2,216
Securities Authorized for Issuance Under Equity Compensation Plans	Plan Category Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (000’s) Equity compensation plans approved by security holders 14,457 Equity compensation plans not approved by security holders n/a Total 14,457

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	At December 31, 2018, the Company had the following open commodity derivative contracts to manage commodity price risk. Type Index Total Volumes (in millions) Weighted Average Price Per Unit Fair Value - December 31, 2018 Asset (Liability) Natural Gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 NYMEX-Henry Hub 185.9 $ 2.81 $ (12,832 ) 2020 NYMEX-Henry Hub 22.8 $ 2.76 $ (4,506 ) Natural Gas basis swaps (Mmbtu) ($/Mmbtu) 2019 NW Rockies Basis Swap 105.9 $ 0.67 $ (41,286 ) Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 NYMEX-WTI 1.4 $ 58.45 $ 15,143 2020 NYMEX-WTI 0.1 $ 60.05 $ 994 Type Index Total Volumes (in millions) Weighted Average Floor Price Weighted Average Ceiling Price Fair Value - December 31, 2018 Asset (Liability) Natural Gas collars 2020 NYMEX 9.1 $ 2.75 $ 3.19 $ (346 ) Subsequent to December 31, 2018, the Company entered into commodity derivative contracts to manage commodity price risk as detailed and described in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”
Summary of Pre-tax Realized and Unrealized Gains and Losses Recognized Related to Natural Gas Derivative Instruments	The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016: For the Year Ended December 31, Commodity Derivatives: 2018 2017 2016 Realized gain (loss) on commodity derivatives-natural gas (1) $ (77,031 ) $ 11,446 $ — Realized gain (loss) on commodity derivatives-crude oil(1) (8,382 ) — — Unrealized gain (loss) on commodity derivatives (1) (59,799 ) 16,966 — Total gain (loss) on commodity derivatives $ (145,212 ) $ 28,412 $ — (1) Included in Gain (loss) on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 23,374 $ — $ 23,374 Long-term derivative asset (1) — 1,203 — 1,203 Total derivative instruments $ — $ 24,577 $ — $ 24,577 Liabilities: Current derivative liability $ — $ 62,350 $ — $ 62,350 Long-term derivative liability (2) — 5,060 — 5,060 Total derivative instruments $ — $ 67,410 $ — $ 67,410 (1) Included in Other assets in the Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Consolidated Balance Sheet.
Carrying Values and Estimated Fair Values of Financial Instruments	For the Year Ended December 31, 2018 2017 Principal Estimated Fair Value Principal Estimated Fair Value Credit Agreement, secured $ 104,000 $ 104,000 $ — $ — Term Loan, secured due 2024 975,000 858,000 975,000 975,000 Second Lien Notes, secured due 2024 (1) 545,000 395,125 — — 6.875% Senior, unsecured Notes, due 2022 195,035 68,262 700,000 701,750 7.125% Senior, unsecured Notes, due 2025 225,000 69,750 500,000 505,000 Total debt $ 2,044,035 $ 1,495,137 $ 2,175,000 $ 2,181,750 (1) The fair value on Second Lien Notes is priced as of January 8, 2019, the first available trade date.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Summary of Income Before Income Tax Benefit	Income before income tax benefit is as follows: Year Ended December 31, 2018 2017 2016 United States $ 86,242 $ (197,136 ) $ 134,959 Foreign (593 ) 360,982 (79,462 ) Total $ 85,649 $ 163,846 $ 55,497
Summary of Consolidated Income Tax Provision (Benefit)	The consolidated income tax provision (benefit) is comprised of the following: Year Ended December 31, 2018 2017 2016 Current tax: U.S. federal, state and local $ 433 $ (13,296 ) $ (72 ) Foreign 9 2 (583 ) Total current tax provision (benefit) 442 (13,294 ) (655 ) Deferred tax: Foreign — — 1 Total deferred tax expense — — 1 Total income tax provision (benefit) $ 442 $ (13,294 ) $ (654 )
Summary of Income Tax Provision (Benefit) from Operations	The income tax provision (benefit) from operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 21% to pretax income as a result of the following: Year Ended December 31, 2018 2017 2016 Income tax provision computed at the U.S. statutory rate $ 17,986 $ 57,346 $ 19,424 State income tax (benefit) provision net of federal effect — (25,519 ) (2,335 ) Valuation allowance (30,723 ) (562,491 ) (31,083 ) Tax effect of rate change — 463,113 — Sale of non-core assets 5,863 130,552 — Foreign rate differential (36 ) (3,150 ) 17,388 Reorganization items 216 (89,327 ) — Equity compensation 2,689 10,778 1,599 Other, net 4,447 5,404 (5,647 ) Total income tax provision (benefit) $ 442 $ (13,294 ) $ (654 )
Summary of Deferred Tax Assets and Liabilities	The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows: December 31, 2018 2017 Deferred tax assets: Property and equipment 33,953 181,524 Deferred gain 19,874 22,256 U.S. federal tax credit carryforwards 512 987 U.S. interest carryforwards 5,931 — U.S. net operating loss carryforwards 462,401 450,623 U.S. state net operating loss carryforwards — 4,038 Non-U.S. net operating loss carryforwards 7,048 6,556 Asset retirement obligations 37,687 36,624 Derivative instruments, net 8,995 — Debt financing 92,706 — Incentive compensation 5,370 6,585 Other, net 2,148 1,723 Total deferred tax assets, gross 676,625 710,916 Valuation allowance (676,625 ) (707,348 ) Net deferred tax assets $ — $ 3,568 Deferred tax liabilities: Derivative instruments, net — 3,568 Net tax liabilities $ — $ 3,568 Net tax asset $ — $ —

2016_2017 Chapter 11 Proceedi_2

2016/2017 Chapter 11 Proceedings (Tables)	12 Months Ended
	Dec. 31, 2018
Reorganizations [Abstract]
Schedule of Reorganization Items	The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended December 31, 2017 and 2016: For the Twelve Months Ended December 31, 2017 2016 Professional fees $ (66,529 ) $ (11,781 ) Gains (losses) (1) 431,107 — Deferred financing costs — (18,742 ) Contract settlements — (17,350 ) Make-whole fees (223,838 ) — Other (2) 167 370 Total Reorganization items, net $ 140,907 $ (47,503 ) ( 1 ) Gains (losses) represent the net gain on the debt to equity exchange related to the Company’s prepetition senior notes. ( 2 ) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Summarized Quarterly Financia_2

Summarized Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Summary of Quarterly Financial Information	2018 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 225,374 $ 190,138 $ 203,776 $ 273,211 $ 892,499 Operating expenses 137,686 127,679 126,872 145,506 537,743 Other income (expense), net: Interest expense (35,837 ) (37,715 ) (38,382 ) (36,382 ) (148,316 ) Loss on commodity derivatives (6,530 ) (47,271 ) (21,804 ) (69,607 ) (145,212 ) Contract settlement — — (2,676 ) 15,332 12,656 Other income (expense), net 2,606 1,981 4,521 2,657 11,765 Total other (expense) income, net (39,761 ) (83,005 ) (58,341 ) (88,000 ) (269,107 ) Income (loss) before income tax provision (benefit) 47,927 (20,546 ) 18,563 39,705 85,649 Income tax provision (benefit) 434 9 — (1 ) 442 Net (loss) income $ 47,493 $ (20,555 ) $ 18,563 $ 39,706 $ 85,207 Net income (loss) per common share — basic $ 0.24 $ (0.10 ) $ 0.09 $ 0.20 $ 0.43 Net income (loss) per common share — fully diluted $ 0.24 $ (0.10 ) $ 0.09 $ 0.20 $ 0.43 2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 220,958 $ 212,657 $ 217,631 $ 240,627 $ 891,873 Operating expenses 104,227 134,393 122,394 132,574 493,588 Other income (expense), net: Interest expense (85,447 ) (29,425 ) (210,107 ) (36,388 ) (361,367 ) Gain (loss) on commodity derivatives (13,218 ) 20,717 4,650 16,263 28,412 Contract settlement (52,707 ) — — — (52,707 ) Other income, net 2,491 2,665 2,730 2,430 10,316 Total other (expense) income, net (148,881 ) (6,043 ) (202,727 ) (17,695 ) (375,346 ) Reorganization items, net (57,546 ) 426,816 (227,123 ) (1,240 ) 140,907 Income (loss) before income tax (benefit) provision (89,696 ) 499,037 (334,613 ) 89,118 163,846 Income tax provision (benefit) 2 — (6,886 ) (6,410 ) (13,294 ) Net (loss) income $ (89,698 ) $ 499,037 $ (327,727 ) $ 95,528 $ 177,140 Net income (loss) per common share — basic $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 Net income (loss) per common share — fully diluted $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Analyses of Changes in Proven Reserves	United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Reserves, December 31, 2015 2,336,280 22,175 9,840 Extensions, discoveries and additions 251,634 3,519 530 Sales — — — Acquisitions — — — Production (264,278 ) (2,912 ) — Revisions (2,023 ) (1,307 ) (467 ) Reserves, December 31, 2016 2,321,613 21,475 9,903 Extensions, discoveries and additions 50,312 1,117 — Sales (89,315 ) — — Acquisitions 22,400 153 — Production (260,009 ) (2,775 ) — Revisions 910,991 7,148 (9,832 ) Reserves, December 31, 2017 2,955,992 27,118 71 Extensions, discoveries and additions 85,180 1,086 — Sales (4,033 ) (3,573 ) (71 ) Acquisitions — — — Production (260,406 ) (2,442 ) — Revisions 145,100 1,256 — Reserves, December 31, 2018 2,921,833 23,445 — United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Proved: Developed 2,336,280 22,175 9,840 Undeveloped — — — Total Proved — 2015 2,336,280 22,175 9,840 Developed 2,321,613 21,475 9,903 Undeveloped — — — Total Proved — 2016 2,321,613 21,475 9,903 Developed 2,261,289 21,652 71 Undeveloped 694,703 5,466 — Total Proved — 2017 2,955,992 27,118 71 Developed 2,243,956 17,876 — Undeveloped 677,877 5,569 — Total Proved — 2018 2,921,833 23,445 —
Standardized Measure	As of December 31, 2018 2017 2016 Future cash inflows $ 9,195,725 $ 8,965,949 $ 5,812,234 Future production costs (3,337,779 ) (3,587,581 ) (2,665,082 ) Future development costs (1,133,103 ) (1,001,024 ) (355,923 ) Future income taxes (180,057 ) — — Future net cash flows 4,544,786 4,377,344 2,791,229 Discount at 10% (2,139,303 ) (1,993,016 ) (1,100,283 ) Standardized measure of discounted future net cash flows $ 2,405,483 $ 2,384,328 $ 1,690,946
Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows	December 31, 2018 2017 2016 Standardized measure, beginning $ 2,384,328 $ 1,690,946 $ 1,865,649 Net revisions of previous quantity estimates 160,405 840,505 (9,623 ) Extensions, discoveries and other changes 90,609 53,549 209,603 Sales of reserves in place (34,768 ) (83,887 ) — Acquisition of reserves — 21,903 — Changes in future development costs (235,205 ) (329,635 ) 11,556 Sales of oil and gas, net of production costs (593,134 ) (589,621 ) (454,725 ) Net change in prices and production costs 362,084 572,224 (72,939 ) Development costs incurred during the period that reduce future development costs 251,621 8,007 22,523 Accretion of discount 238,433 169,095 186,565 Net changes in production rates and other (189,017 ) 31,242 (67,663 ) Net change in income taxes (29,873 ) — — Aggregate changes 21,155 693,382 (174,703 ) Standardized measure, ending $ 2,405,483 $ 2,384,328 $ 1,690,946
Costs Incurred in Oil and Gas Exploration and Development Activities	Years Ended December 31, 2018 2017 2016 United States Property Acquisitions: Unproved $ 1,468 $ 1,399 $ 983 Proved 1,090 9,147 — Exploration* 156,718 510,710 224,277 Development 266,905 35,934 44,300 Total $ 426,181 $ 557,190 $ 269,560 * Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.
Results of operations for oil and gas producing activities	RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: Years Ended December 31, 2018 2017 2016 United States Oil and gas revenue $ 892,499 $ 891,873 $ 721,091 Production expenses (299,365 ) (292,095 ) (266,366 ) Depletion and depreciation (204,255 ) (161,945 ) (125,121 ) Income tax benefit (expense) (2 ) (168,355 ) 83,112 Total $ 388,877 $ 269,478 $ 412,716
Capitalized Costs Relating to Oil and Gas Producing Activities	CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,577,281 $ 11,215,563 Less: accumulated depletion, depreciation and amortization (10,079,554 ) (9,890,495 ) Total Oil and gas properties, net $ 1,497,727 $ 1,325,068

Supplemental Financial Statem_2

Supplemental Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2018
Parent Company Financial Statements [Abstract]
Supplemental Statement Of Operations Disclosures Parent Company	CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2018 2017 2016 General and administrative expense $ 549 $ 428 $ 650 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) — (71,876 ) (26,590 ) Income (loss) from unconsolidated affiliates 85,809 (183,840 ) 157,450 Guarantee fee income — — 6,073 Other expense (44 ) 90 (64,888 ) Reorganization items, net — 433,196 (15,827 ) Income before income taxes 85,216 177,142 55,568 Income tax provision (benefit) 9 2 (583 ) Net income $ 85,207 $ 177,140 $ 56,151
Supplemental Balance Sheet Disclosures Parent Company	CONDENSED BALANCE SHEET December 31, 2018 December 31, 2017 ASSETS Current Assets: Cash and cash equivalents $ 570 $ 803 Accounts receivable from related companies 29,939 29,940 Other current assets — — Total current assets 30,509 30,743 Other non-current assets — — Total assets $ 30,509 $ 30,743 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ — $ 21 Total current liabilities — 21 Advances from unconsolidated affiliates 1,079,131 1,185,359 Total liabilities 1,079,131 1,185,380 Total shareholders’ deficit (1,048,622 ) (1,154,637 ) Total liabilities and shareholders’ equity $ 30,509 $ 30,743
Supplemental Cash Flow Statement Disclosures Parent Company	CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2018 2017 2016 Net cash (used in) operating activities $ (234 ) $ (2,206 ) $ (21,309 ) Investing Activities: Investment in subsidiaries (3,293 ) (588,677 ) — Dividends received — — 24,089 Net cash (used in) provided by investing activities (3,293 ) (588,677 ) 24,089 Financing activities: Deferred financing costs — — — Shares issued 3,294 573,774 — Repurchased shares/net share settlements — 14,903 43 Shares re-issued from treasury — — (337 ) Net cash provided by (used in) financing activities 3,294 588,677 (294 ) (Decrease) increase in cash during the period (233 ) (2,206 ) 2,486 Cash and cash equivalents, beginning of period 803 3,009 523 Cash and cash equivalents, end of period $ 570 $ 803 $ 3,009

2018 Debt Exchange - Additional

2018 Debt Exchange - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 21, 2018	Dec. 31, 2017	Dec. 31, 2018
Debt Conversion [Line Items]
Principal amount of new debt instrument issued for exchange		$ 978,230
Ultra Resources, Inc. | Exchange Agreement
Debt Conversion [Line Items]
Warrants issued on exchange	10,919,499
Warrants exercise price	$ 0.01
Number of common stock issued upon exercise of each warrant	1
6.875% Senior, Unsecured Notes Due 2022
Debt Conversion [Line Items]
Stated interest rate		6.875%	6.875%
6.875% Senior, Unsecured Notes Due 2022 | Ultra Resources, Inc. | Exchange Agreement
Debt Conversion [Line Items]
Aggregate principal amount of debt exchanged	$ 505,000
Aggregate principal amount of debt exchanged, percentage	72.10%
Stated interest rate	6.875%
Debt conversion, original debt, due date, year	2,022
7.125% Senior, Unsecured Notes Due 2025
Debt Conversion [Line Items]
Stated interest rate		7.125%	7.125%
7.125% Senior, Unsecured Notes Due 2025 | Ultra Resources, Inc. | Exchange Agreement
Debt Conversion [Line Items]
Aggregate principal amount of debt exchanged	$ 275,000
Aggregate principal amount of debt exchanged, percentage	55.00%
Stated interest rate	7.125%
Debt conversion, original debt, due date, year	2,025
Senior Secured Second Lien Notes due July 2024 | Ultra Resources, Inc. | Exchange Agreement
Debt Conversion [Line Items]
Principal amount of new debt instrument issued for exchange	$ 545,000
Debt issued on exchange, paid in kind interest rate percentage	2.00%
Debt issued on exchange, interest rate	9.00%
Debt issued on exchange, maturity date	2024-07
Senior Unsecured Notes | Ultra Resources, Inc. | Exchange Agreement
Debt Conversion [Line Items]
Indebtedness reduced by exchange transaction	$ 235,000

Significant Accounting Polici_4

Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Cash Equivalents Restricted Cash And Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 17,014	$ 16,631	$ 401,478
Restricted cash	2,291	1,638	3,571
Total cash, cash equivalents, and restricted cash	$ 19,305	$ 18,269	$ 405,049	$ 4,258

Significant Accounting Polici_5

Significant Accounting Policies - Additional Information (Details)	Dec. 21, 2018$ / sharesshares	Apr. 12, 2017	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)shares	Jan. 01, 2018USD ($)
Significant Accounting Policies [Line Items]
provision for uncollectible accounts			$ 4,900,000
Discount rate future net revenues			10.00%
Ceiling test limitation			$ 0	$ 0	$ 0
Inventory			$ 18,757,000	$ 13,450,000
Common share, no par value | $ / shares
Conversion ratio		0.521562
Contingently issuable shares | shares			14,200,000	3,900,000	0
Addition to retained earnings			$ (3,186,016,000)	$ (3,270,605,000)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Significant Accounting Policies [Line Items]
Addition to retained earnings						$ 1,800,000
Ultra Resources, Inc. | Exchange Agreement
Significant Accounting Policies [Line Items]
Warrants issued on exchange | shares	10,919,499
Number of common stock issued upon exercise of each warrant | shares	1
Initial exercise price | $ / shares	$ 0.01
Volume-weighted average price of the Common Shares for warrants exercise | $ / shares	$ 2.50
Warrants Exercise description			No Warrants will be exercisable until the date on which the volume-weighted average price of the Common Shares is at least $2.50 per Common Share for 30 consecutive trading days (the “Trading Price Condition”).
Warrant exercisable date	Dec. 21, 2018
Warrant expiration date	Jul. 14, 2025
Pipe and Production Equipment and Miscellaneous Materials and Supplies
Significant Accounting Policies [Line Items]
Inventory			$ 17,600,000
Crude Oil Inventory
Significant Accounting Policies [Line Items]
Inventory			$ 1,100,000

Significant Accounting Polici_6

Significant Accounting Policies - Reconciliation of Components of Basic and Diluted Net Income Per Common Share (Details) - USD ($) $ / shares in Units, 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
Earnings Per Share Reconciliation [Abstract]
Net income	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	$ 85,207	$ 177,140	$ 56,151
Weighted average common shares outstanding during the period									196,964	163,824	79,996
Effect of dilutive instruments									577	152	367
Weighted average common shares outstanding during the period including the effects of dilutive instruments									197,541	163,976	80,363
Net income per common share — basic	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ 0.43	$ 1.08	$ 0.70
Net income per common share — fully diluted	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ 0.43	$ 1.08	$ 0.70
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares											749

Impact of ASC 606 Adoption - _3

Impact of ASC 606 Adoption - Revenue Recognition - Schedule of Impact of Adoption on Consolidated Income Statement (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
Revenues:
Total operating revenues									$ 892,499	$ 891,873	$ 721,091
Expenses:
Production taxes									93,322	91,067	69,737
Gathering fees									89,806	86,953	86,809
Net income:	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	85,207	177,140	56,151
Natural Gas Sales
Revenues:
Total operating revenues									722,313	748,682	609,756
Oil Sales
Revenues:
Total operating revenues									153,534	133,368	$ 111,335
Other Revenues
Revenues:
Total operating revenues									16,652	$ 9,823
Accounting Standards Update 2014-09 | Increase/ (Decrease)
Expenses:
Production taxes									93,326
Gathering fees									89,812
Net income:									85,249
Accounting Standards Update 2014-09 | Increase/ (Decrease)
Expenses:
Production taxes									(4)
Gathering fees									(6)
Net income:									(42)
Accounting Standards Update 2014-09 | Natural Gas Sales | Increase/ (Decrease)
Revenues:
Total operating revenues									722,365
Accounting Standards Update 2014-09 | Natural Gas Sales | Increase/ (Decrease)
Revenues:
Total operating revenues									(52)
Accounting Standards Update 2014-09 | Oil Sales | Increase/ (Decrease)
Revenues:
Total operating revenues									153,534
Accounting Standards Update 2014-09 | Other Revenues | Increase/ (Decrease)
Revenues:
Total operating revenues									$ 16,652

Impact of ASC 606 Adoption - _4

Impact of ASC 606 Adoption - Revenue Recognition - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue, practical expedient in ASC 606-10-50-14	true
Revenue, practical expedient in ASC 606-10-50-14(a), description	For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is 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.

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$ 173,100	$ 157,173
Accretion expense	12,342	11,689
Liabilities incurred	3,558	8,174
Liabilities divested	(9,372)	(4,812)
Liabilities acquired		1,456
Liabilities settled	(70)	(598)
Revisions of estimated liabilities	(96)	18
Asset retirement obligations at end of period	179,462	173,100
Less: current asset retirement obligations	(193)	(263)
Long-term asset retirement obligations	$ 179,269	$ 172,837

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,577,281	$ 11,215,563
Less: Accumulated depletion, depreciation and amortization	(10,079,554)	(9,890,495)
Total Oil and gas properties, net	$ 1,497,727	$ 1,325,068

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details) - $ / Mcfe	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Property [Abstract]
DD&A per Mcfe	0.74	0.59	0.44

Property, Plant & Equipment - S

Property, Plant & Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property Plant And Equipment [Line Items]
Cost	$ 26,026
Accumulated Depreciation	(14,391)
Property, plant and equipment	11,635	$ 9,569
Computer Equipment
Property Plant And Equipment [Line Items]
Cost	2,828
Accumulated Depreciation	(2,209)
Property, plant and equipment	619	554
Office Equipment
Property Plant And Equipment [Line Items]
Cost	265
Accumulated Depreciation	(200)
Property, plant and equipment	65	95
Leasehold Improvements
Property Plant And Equipment [Line Items]
Cost	264
Accumulated Depreciation	(178)
Property, plant and equipment	86	120
Land
Property Plant And Equipment [Line Items]
Cost	2,437
Property, plant and equipment	2,437	4,637
Production And Other Equipment
Property Plant And Equipment [Line Items]
Cost	20,232
Accumulated Depreciation	(11,804)
Property, plant and equipment	$ 8,428	$ 4,163

Long Term Debt - Summary of Out

Long Term Debt - Summary of Outstanding Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Principal	$ 2,044,035	$ 2,175,000
Unamortized Deferred Financing Costs and Discounts	(56,650)	(58,789)
Unamortized Premium on Exchange Transaction	228,096
Carrying Value	2,215,481	2,116,211
Principal, Current Maturities	7,313
Carrying Value, Current maturities	7,313
Principal, Total Long-term debt	2,036,722	2,175,000
Unamortized Deferred Financing Costs and Discounts, Total Long-term debt	(56,650)	(58,789)
Unamortized Premium on Exchange Transaction, Total Long-term debt	228,096
Total long-term debt, net	2,208,168	2,116,211
Credit Agreement
Debt Instrument [Line Items]
Principal	104,000
Carrying Value	104,000
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Principal	975,000	975,000
Unamortized Deferred Financing Costs and Discounts	(26,874)	(23,357)
Carrying Value	948,126	951,643
Second Lien Notes, Secured, Due 2024
Debt Instrument [Line Items]
Principal	545,000
Unamortized Premium on Exchange Transaction	228,096
Carrying Value	773,096
6.875% Unsecured Notes Due 2022
Debt Instrument [Line Items]
Principal	195,035	700,000
Unamortized Deferred Financing Costs and Discounts	(15,168)	(19,084)
Carrying Value	179,867	680,916
7.125% Unsecured Notes Due 2025
Debt Instrument [Line Items]
Principal	225,000	500,000
Unamortized Deferred Financing Costs and Discounts	(14,608)	(16,348)
Carrying Value	$ 210,392	$ 483,652

Long Term Debt - Summary of O_2

Long Term Debt - Summary of Outstanding Debt (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Maturity date	Apr. 12, 2024	Apr. 12, 2024
Second Lien Notes, Secured, Due 2024
Debt Instrument [Line Items]
Maturity date	Jul. 12, 2024
6.875% Unsecured Notes Due 2022
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2022	Apr. 15, 2022
Stated interest rate	6.875%	6.875%
7.125% Unsecured Notes Due 2025
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2025	Apr. 15, 2025
Stated interest rate	7.125%	7.125%

Long Term Debt - Summary of Agg

Long Term Debt - Summary of Aggregate Maturities of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Long Term Liabilities [Abstract]
2,019	$ 7,313
2,020	9,750
2,021	9,750
2,022	308,785
2,023	9,750
Beyond 5 years	1,698,687
Total	$ 2,044,035	$ 2,175,000

Long Term Debt - Ultra Resource

Long Term Debt - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($) $ in Thousands	Feb. 14, 2019	Dec. 31, 2018	Dec. 21, 2018	Dec. 20, 2018	Sep. 30, 2018	Sep. 29, 2018	Dec. 31, 2017	Apr. 12, 2017
Debt Instrument [Line Items]
Long-term debt, gross		$ 2,044,035					$ 2,175,000
Credit Agreement
Debt Instrument [Line Items]
Long-term debt, gross		104,000
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity		325,000			$ 325,000
Long-term debt, gross		104,000
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base		$ 1,300,000				$ 1,400,000		$ 1,300,000
Next scheduled borrowing base redeterminations date		Oct. 1, 2019
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Letters of Credit
Debt Instrument [Line Items]
Amount of commitments available for the issuance of letters of credit		$ 50,000
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Interest rate description		The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00.
Minimum required consolidated net leverage ratio, as percentage		400.00%
Interest rate on minimum required consolidated net leverage ratio exceeds 4.00 to 1.00		0.25%
Maximum required consolidated net leverage ratio, as percentage		400.00%
Maturity date		Jan. 12, 2022
Consolidated net leverage ratio		395.00%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Minimum
Debt Instrument [Line Items]
Variable rate		2.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Maximum
Debt Instrument [Line Items]
Variable rate		3.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Minimum
Debt Instrument [Line Items]
Variable rate		1.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Maximum
Debt Instrument [Line Items]
Variable rate		2.50%
Ultra Resources, Inc. | Credit Agreement | Barclays Bank PLC
Debt Instrument [Line Items]
Long-term debt, gross					$ 975,000
Ultra Resources, Inc. | Third Amendment
Debt Instrument [Line Items]
Percentage of collateral coverage			95.00%	85.00%
Ultra Resources, Inc. | Fourth Amendment | Bank Of Montreal | Subsequent Event
Debt Instrument [Line Items]
Borrowing Base	$ 1,300,000
Ultra Resources, Inc. | Fourth Amendment | Bank Of Montreal | Subsequent Event | Revolving Credit Facility
Debt Instrument [Line Items]
Borrowing Base	1,300,000
Credit facility, current borrowing capacity	$ 325,000
Minimum required interest coverage ratio, as percentage	250.00%
Minimum required current ratio, as percentage	100.00%
Minimum required asset coverage ratio, as percentage on achievement of investment grade	150.00%
Maximum required consolidated net leverage ratio, as percentage, for fiscal quarter ending December 31, 2018	450.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019	475.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020	490.00%
Maximum required consolidated net leverage ratio, as percentage, for fiscal quarter ending September 30, 2020	450.00%
Maximum required consolidated net leverage ratio, as percentage, the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter	425.00%
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Net leverage ratio through September 29, 2019, minimum required hedging percentage		65.00%
Net leverage ratio beginning on September 30, 2019 and ending on March 30, 2020, minimum required hedging percentage		50.00%
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Net leverage ratio through September 29, 2019, minimum required hedging percentage		65.00%
Net leverage ratio beginning on September 30, 2019 and ending on March 30, 2020, minimum required hedging percentage		50.00%

Long Term Debt - Ultra Resour_2

Long Term Debt - Ultra Resources, Inc. - Term Loan - Additional Information (Details) - USD ($)	Dec. 21, 2018	Apr. 12, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2018	Sep. 30, 2017
Debt Instrument [Line Items]
Total long-term debt			$ 2,044,035,000	$ 2,175,000,000
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Total long-term debt			$ 975,000,000	$ 975,000,000
Maturity date			Apr. 12, 2024	Apr. 12, 2024
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024
Debt Instrument [Line Items]
Credit Agreement, initial term loan		$ 800,000,000
Credit Agreement, initial term loan upon emergence from chapter 11		600,000,000
Credit Agreement, incremental term loan		$ 200,000,000				$ 175,000,000
Total long-term debt			$ 975,000,000			$ 975,000,000
Debt, original issue discount as percentage on principal		1.00%
Amortization of term loan, quarterly basis			0.25%
Maturity date			Apr. 12, 2024
Gain (loss) on debt extinguishment			$ 0
Deferred financing costs			$ 7,200,000
Mandatory prepayment trigger, on asset coverage ratio			200.00%
Debt instrument, covenant compliance			At December 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | LIBOR
Debt Instrument [Line Items]
Variable rate			4.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Base Rate
Debt Instrument [Line Items]
Variable rate			3.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement
Debt Instrument [Line Items]
Variable rate	1.00%
Percentage of collateral coverage	95.00%				85.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement | Until First Anniversary
Debt Instrument [Line Items]
Debt instrument call protection percentage	102.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement | Until Second Anniversary
Debt Instrument [Line Items]
Debt instrument call protection percentage	101.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Cash Notes | Exchange Agreement
Debt Instrument [Line Items]
Variable rate	0.75%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Payment in Kind (PIK) Note | Base Rate
Debt Instrument [Line Items]
Variable rate			0.25%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Payment in Kind (PIK) Note | Exchange Agreement
Debt Instrument [Line Items]
Variable rate	0.25%

Long Term Debt - Ultra Resour_3

Long Term Debt - Ultra Resources, Inc. - Second Lien Notes - Additional Information (Details) - USD ($) $ in Thousands	Dec. 21, 2018	Feb. 28, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange				$ 978,230
Second Lien Notes, Secured, Due 2024
Debt Instrument [Line Items]
Maturity date			Jul. 12, 2024
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Maturity date			Apr. 15, 2022	Apr. 15, 2022
6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged		$ 44,600
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024
Debt Instrument [Line Items]
Redemption price percentage of principal amount			111.00%
Redemption criteria			if at least 65% of the original principal amount of the Second Lien Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering.
Repurchase price percentage			101.00%
Debt instrument, exchange transaction expenses			$ 4,700
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Maximum
Debt Instrument [Line Items]
Redemption price percentage of aggregate principal amount			35.00%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Twelve-Month Period Beginning December 21, 2021
Debt Instrument [Line Items]
Redemption price percentage of principal amount			105.50%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Twelve-Month Period Beginning December 21, 2022
Debt Instrument [Line Items]
Redemption price percentage of principal amount			102.75%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Twelve-Month Period Beginning December 21, 2023
Debt Instrument [Line Items]
Redemption price percentage of principal amount			100.00%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange	$ 545,000
Maturity date			Jul. 12, 2024
Debt issued on exchange, interest rate	9.00%
Debt issued on exchange, paid in kind interest rate percentage	2.00%
Interest payment terms			The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Exchange Agreement | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange		27,000
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Interest payment terms			The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity.
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged	$ 505,000
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement | Subsequent Event
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged		$ 44,600

Long Term Debt - Ultra Resour_4

Long Term Debt - Ultra Resources, Inc. - Senior Unsecured Notes - Additional Information (Details) - USD ($)	Dec. 21, 2018	Dec. 31, 2018	Dec. 31, 2017	Apr. 12, 2017
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange			$ 978,230,000
Aggregate principal amounts outstanding		$ 2,044,035,000	2,175,000,000
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Aggregate principal amounts outstanding		195,035,000	700,000,000
7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Aggregate principal amounts outstanding		225,000,000	$ 500,000,000
Senior Secured Second Lien Notes due July 2024
Debt Instrument [Line Items]
Aggregate principal amounts outstanding		$ 545,000,000
Ultra Resources, Inc. | Exchange Agreement
Debt Instrument [Line Items]
Warrants issued on exchange	10,919,499
Number of common stock issued upon exercise of each warrant	1
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Debt instrument, face amount				$ 700,000,000
Interest payment terms		The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity.
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged	$ 505,000,000
Aggregate principal amount of debt exchanged, percentage	72.10%
Aggregate principal amounts outstanding		$ 195,000,000
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Debt instrument, face amount				$ 500,000,000
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged	$ 275,000,000
Aggregate principal amount of debt exchanged, percentage	55.00%
Aggregate principal amounts outstanding		$ 225,000,000
Ultra Resources, Inc. | Senior Secured Second Lien Notes due July 2024 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange	$ 545,000,000
Interest payment terms		The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019

Share Based Compensation - Sche

Share Based Compensation - Schedule of Valuation and Expense Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of share-based payment plans	$ 15,639	$ 53,952	$ 8,013
Amounts capitalized in oil and gas properties and equipment	3,814	13,975	2,451
Amounts charged against income, before income tax benefit	11,825	39,977	5,562
Amount of related income tax benefit recognized in income before valuation allowances	$ 2,483	$ 15,927	$ 2,216

Share Based Compensation - Secu

Share Based Compensation - Securities Authorized for Issuance Under Equity Compensation Plans (Details)	Dec. 31, 2018shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans	14,457,000
Equity Compensation Plans Approved by Security Holders
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans	14,457,000

Share Based Compensation - Addi

Share Based Compensation - Additional Information (Details) - USD ($)	Apr. 12, 2017	Jul. 31, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incremental expense recognized from modification				$ 600,000
Total cost of share based payment plans				$ 11,825,000	$ 39,977,000	$ 5,562,000
Long Term Incentive Award
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance period				3 years
Performance Shares | Stock Incentive Plan 2017 | Board of Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percent of equity reserved for directors, officers and other employees	7.50%
Performance Shares | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting description				During 2017, management incentive grants (the “Initial MIP Grants”) were made to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, such Initial MIP Grants shall automatically expire.
Performance Shares | Amendment and Restatement of Stock Incentive Plan 2017 | Outside Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive awards available for grant value, maximum limit during a single calendar year			$ 750,000
Performance Shares | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds $6.0 Billion | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage	0.33%
Total enterprise value	$ 6,000,000,000
Performance Shares | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds 110% of $6.0 Billion or $6.6 Billion | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage	0.33%
Total enterprise value	$ 6,000,000,000
Percentage of enterprise value	110.00%
Time-based Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Plan modification unvested portion exchange units percentage		100.00%
Time-based Restricted Stock Units | May 25, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date		May 25, 2019
Time-based Restricted Stock Units | May 25, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date		May 25, 2020
Time-based Restricted Stock Units | May 25, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date		May 25, 2021
Stock-Based Compensation Cost
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				$ 11,800,000	40,000,000	5,600,000
Stock-Based Compensation Cost | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				10,900,000	$ 38,500,000
Stock-Based Compensation Cost | Long Term Incentive Plan 2015 and 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans						$ 4,700,000
Stock-Based Compensation Cost | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds $6.0 Billion | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total enterprise value				6,000,000,000
Expected share-based compensation expense				21,300,000
Stock-Based Compensation Cost | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds 110% of $6.0 Billion or $6.6 Billion | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total enterprise value				6,600,000,000
Expected share-based compensation expense				$ 19,600,000

Derivative Financial Instrume_3

Derivative Financial Instruments - Additional Information (Details) - Revolving Credit Facility - Bank Of Montreal - Ultra Resources, Inc. - Second Amendment	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Hedging percentage on proved producing natural gas production for 18 months through September 30, 2019	65.00%
Hedging percentage on proved producing forecast for natural gas through March 31, 2020	50.00%
Maximum
Derivative [Line Items]
Hedging percentage on proved producing natural gas production for 18 months through September 30, 2019	65.00%
Hedging percentage on proved producing forecast for natural gas through March 31, 2020	50.00%
Line of credit facility maximum hedging percentage on forecast production for all products	85.00%

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands, bbl in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2017USD ($)
Derivative [Line Items]
Fair Value Asset	$ 23,374	$ 16,865
Fair Value (Liability)	$ (62,350)
Commodity Derivative Contract Fixed Price Swaps | Crude Oil
Derivative [Line Items]
Type	Crude oil fixed price swaps
Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type	Natural Gas fixed price swaps
Commodity Derivative Contract Fixed Price Swaps One | Crude Oil
Derivative [Line Items]
Type	2,019
Index	NYMEX-WTI
Total Volumes | bbl	1.4
Weighted Average Price Per Unit | $ / bbl	58.45
Fair Value Asset	$ 15,143
Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Type	2,019
Index	NYMEX-Henry Hub
Total Volumes | MMBTU	185.9
Weighted Average Price Per Unit | $ / MMBTU	2.81
Fair Value (Liability)	$ (12,832)
Commodity Derivative Contract Fixed Price Swaps Two | Crude Oil
Derivative [Line Items]
Type	2,020
Index	NYMEX-WTI
Total Volumes | bbl	0.1
Weighted Average Price Per Unit | $ / bbl	60.05
Fair Value Asset	$ 994
Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas
Derivative [Line Items]
Type	2,020
Index	NYMEX-Henry Hub
Total Volumes | MMBTU	22.8
Weighted Average Price Per Unit | $ / MMBTU	2.76
Fair Value (Liability)	$ (4,506)
Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Type	Natural Gas basis swaps
Commodity Derivative Basis Swap Contracts One | Natural Gas
Derivative [Line Items]
Type	2,019
Index	NW Rockies Basis Swap
Total Volumes | MMBTU	105.9
Weighted Average Price Per Unit | $ / MMBTU	0.67
Fair Value (Liability)	$ (41,286)
Commodity Derivative Contract Collars One | Natural Gas
Derivative [Line Items]
Type	2,020
Index	NYMEX
Total Volumes | MMBTU	9.1
Weighted Average Floor Price | $ / MMBTU	2.75
Weighted Average Ceiling Price | $ / MMBTU	3.19
Fair Value (Liability)	$ (346)
Commodity Derivative Contract Collars | Natural Gas
Derivative [Line Items]
Type	Natural Gas collars

Derivative Financial Instrume_5

Derivative Financial Instruments - Summary of Pre-tax Realized and Unrealized Gains and Losses Recognized Related to Natural Gas Derivative Instruments (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
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives									$ (59,799)	$ 16,966
Total gain (loss) on commodity derivatives	$ (69,607)	$ (21,804)	$ (47,271)	$ (6,530)	$ 16,263	$ 4,650	$ 20,717	$ (13,218)	(145,212)	28,412
Commodity Derivative Contract
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives									(59,799)	16,966
Total gain (loss) on commodity derivatives									(145,212)	28,412
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain (loss) on commodity derivatives									(77,031)	$ 11,446
Commodity Derivative Contract | Oil
Derivative [Line Items]
Realized gain (loss) on commodity derivatives									$ (8,382)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		$ 23,374	$ 16,865
Long-term derivative asset	[1]	1,203
Total derivative instruments		24,577
Current derivative liability		62,350
Long-term derivative liability	[2]	5,060
Total derivative instruments		67,410
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		23,374
Long-term derivative asset	[1]	1,203
Total derivative instruments		24,577
Current derivative liability		62,350
Long-term derivative liability	[2]	5,060
Total derivative instruments		$ 67,410
[1]	Included in Other assets in the Consolidated Balance Sheet.
[2]	Included in Other long-term obligations in the Consolidated Balance Sheet.

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Details) - Level 2 - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt		$ 2,044,035	$ 2,175,000
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt		1,495,137	2,181,750
Credit Agreement, Secured | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility		104,000
Credit Agreement, Secured | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility		104,000
Term Loan Secured Due 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan		975,000	975,000
Term Loan Secured Due 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan		858,000	975,000
Second Lien Notes, Secured, Due 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	[1]	545,000
Second Lien Notes, Secured, Due 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	[1]	395,125
6.875% Senior, Unsecured Notes Due 2022 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		195,035	700,000
6.875% Senior, Unsecured Notes Due 2022 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		68,262	701,750
7.125% Senior, Unsecured Notes Due 2025 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		225,000	500,000
7.125% Senior, Unsecured Notes Due 2025 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		$ 69,750	$ 505,000
[1]	The fair value on Second Lien Notes is priced as of January 8, 2019, the first available trade date.

Fair Value Measurements - Car_2

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Term Loan Secured Due 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,024
Second Lien Notes, Secured, Due 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,024
6.875% Senior, Unsecured Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,022
Stated interest rate	6.875%	6.875%
7.125% Senior, Unsecured Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,025
Stated interest rate	7.125%	7.125%

Income Taxes - Summary of Incom

Income Taxes - Summary of Income Before Income Tax Benefit (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
Income Loss From Continuing Operations Before Income Taxes Minority Interest And Income Loss From Equity Method Investments [Abstract]
United States									$ 86,242	$ (197,136)	$ 134,959
Foreign									(593)	360,982	(79,462)
Income before income tax expense (benefit)	$ 39,705	$ 18,563	$ (20,546)	$ 47,927	$ 89,118	$ (334,613)	$ 499,037	$ (89,696)	$ 85,649	$ 163,846	$ 55,497

Income Taxes - Summary of Conso

Income Taxes - Summary of Consolidated Income Tax Provision (Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended						12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current tax:
U.S. federal, state and local - current							$ 433	$ (13,296)	$ (72)
Foreign - current							9	2	(583)
Total current tax provision (benefit)							442	(13,294)	(655)
Deferred tax:
Foreign - deferred									1
Total deferred tax expense									1
Total income tax provision (benefit)	$ (1)	$ 9	$ 434	$ (6,410)	$ (6,886)	$ 2	$ 442	$ (13,294)	$ (654)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Statutory tax rate	21.00%	35.00%
Deferred tax assets, valuation allowance	$ 676,625	$ 707,348
Canada | 2015
Income Taxes [Line Items]
Tax years	2,015
Canada | 2016
Income Taxes [Line Items]
Tax years	2,016
Federal
Income Taxes [Line Items]
Net operating loss carryforward	$ 2,200,000
Percentage of taxable income limitation on carryforward	80.00%

Income Taxes - Summary of Inc_2

Income Taxes - Summary of Income Tax Provision (Benefit) from Operations (Details) - USD ($) $ in Thousands	3 Months Ended						12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Abstract]
Income tax provision computed at the U.S. statutory rate							$ 17,986	$ 57,346	$ 19,424
State income tax (benefit) provision net of federal effect								(25,519)	(2,335)
Valuation allowance							(30,723)	(562,491)	(31,083)
Tax effect of rate change								463,113
Sale of non-core assets							5,863	130,552
Foreign rate differential							(36)	(3,150)	17,388
Reorganization items							216	(89,327)
Equity compensation							2,689	10,778	1,599
Other, net							4,447	5,404	(5,647)
Total income tax provision (benefit)	$ (1)	$ 9	$ 434	$ (6,410)	$ (6,886)	$ 2	$ 442	$ (13,294)	$ (654)

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets:
Property and equipment	$ 33,953	$ 181,524
Deferred gain	19,874	22,256
U.S. federal tax credit carryforwards	512	987
U.S. interest carryforwards	5,931
U.S. net operating loss carryforwards	462,401	450,623
U.S. state net operating loss carryforwards		4,038
Non-U.S. net operating loss carryforwards	7,048	6,556
Asset retirement obligations	37,687	36,624
Derivative instruments, net	8,995
Debt financing	92,706
Incentive compensation	5,370	6,585
Other, net	2,148	1,723
Total deferred tax assets, gross	676,625	710,916
Valuation allowance	$ (676,625)	(707,348)
Net deferred tax assets		3,568
Deferred tax liabilities:
Derivative instruments, net		3,568
Net tax liabilities		$ 3,568

Employee Benefits - Additional

Employee Benefits - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Tax Deferred Savings Plan [Abstract]
Employee deferral percent for 401(k)	100.00%
Company matching percent for 401(k)	5.00%
Company discretionary contribution for 401(k)	8.00%
Pension and Other Postretirement Benefit Contributions [Abstract]
Other postretirement benefits payments	$ 2.5	$ 2.4	$ 2.3

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands	Oct. 16, 2018	Oct. 06, 2017	Aug. 31, 2016	Apr. 29, 2016	Apr. 19, 2016	Dec. 31, 2012	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Apr. 14, 2017
Loss Contingencies [Line Items]
Projected total lease payments							$ 3,900	$ 3,900	$ 3,900
Commitments for office leases in 2019							1,200	1,200	1,200
Commitments for office leases in 2020							1,100	1,100	1,100
Commitments for office leases in 2021							1,000	1,000	1,000
Commitments for office leases in 2022							600	600	600
Office leases expense recognized									$ 1,600	$ 1,600	$ 1,500
Oil and gas delivery commitments details									With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Part I. Item 1A. “Risk Factors.” If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments.
Claims settled		$ 399,000
Bankruptcy claims, undistributed amount returned		1,300
Bankruptcy claims amount of claims settled, make-whole fees		223,800								223,838
Bankruptcy claims amount of claims settled, postpetition interest		175,200								$ 175,200
Settlement Agreements
Loss Contingencies [Line Items]
Settlement agreement, amount claimants agreed to pay								$ 16,400
Indebtedness Claims | Notes holders
Loss Contingencies [Line Items]
Claim reserve account after emergence from bankruptcy		$ 400,000										$ 400,000
Royalties | ONRR
Loss Contingencies [Line Items]
Bankruptcy claims amount					$ 35,100
Oil Sales Contract | SPMT
Loss Contingencies [Line Items]
Bankruptcy claims amount			$ 16,900
Damage sought				$ 38,600
Settlement agreement, amount Company agreed to pay	$ 2,000
Settlement agreement, amount paid by Company							$ 1,000
Pinedale Lease Agreement
Loss Contingencies [Line Items]
Initial term liquids gathering system lease						15 years
Renewal term liquids gathering system lease						5 years
Renewal term liquids gathering system lease useful life						75.00%
Initial annual rent						$ 20,000
Projected total lease payments						$ 195,700

Concentration of Credit Risk -

Concentration of Credit Risk - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018
Customer Concentration Risk | Revenue | Minimum
Percentage of revenue	10.00%

2016_2017 Chapter 11 Proceedi_3

2016/2017 Chapter 11 Proceedings - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Oct. 06, 2017	Apr. 12, 2017	Feb. 08, 2017
Bankruptcy Proceedings [Line Items]
Petition date	Apr. 29, 2016
Court where petition was filed	United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”)
Plan confirmed date	Mar. 14, 2017
Plan expected to be effective date	Apr. 12, 2017
Claims settled		$ 399
Senior Unsecured Notes Due 2018
Bankruptcy Proceedings [Line Items]
Claims settled			$ 450
5.75% Senior Notes Due 2018
Bankruptcy Proceedings [Line Items]
Stated interest rate			5.75%
Senior Unsecured Notes Due 2024
Bankruptcy Proceedings [Line Items]
Claims settled			$ 850
6.125% Senior Notes Due 2024
Bankruptcy Proceedings [Line Items]
Stated interest rate			6.125%
Prepetition Credit Agreement
Bankruptcy Proceedings [Line Items]
Claims settled			$ 999
Prepetition Senior Notes
Bankruptcy Proceedings [Line Items]
Claims settled			1,460
Barclays Bank PLC
Bankruptcy Proceedings [Line Items]
Secured and unsecured financing provided by Barclays				$ 2,400
BCA
Bankruptcy Proceedings [Line Items]
Rights offering, aggregate purchase price			$ 580

2016_2017 Chapter 11 Proceedi_4

2016/2017 Chapter 11 Proceedings - Costs of Reorganization (Details) - USD ($) $ in Thousands	Oct. 06, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Reorganization Items [Abstract]
Professional fees						$ (66,529)	$ (11,781)
Gains (losses)						431,107
Deferred financing costs							(18,742)
Contract settlements							(17,350)
Make-whole fees	$ (223,800)					(223,838)
Other						167	370
Total Reorganization items, net		$ (1,240)	$ (227,123)	$ 426,816	$ (57,546)	$ 140,907	$ (47,503)

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ in Thousands	Feb. 14, 2019	Dec. 21, 2018	Oct. 06, 2017	Feb. 28, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 14, 2017
Subsequent Event [Line Items]
Equitization of Holdco Notes						$ 978,230
Claims settled			$ 399,000
Bankruptcy claims, undistributed amount returned			1,300
Bankruptcy claims amount of claims settled, make-whole fees			223,800			223,838
Bankruptcy claims amount of claims settled, postpetition interest			175,200			$ 175,200
Indebtedness Claims | Notes holders
Subsequent Event [Line Items]
Claim reserve account after emergence from bankruptcy			$ 400,000				$ 400,000
Settlement Agreements
Subsequent Event [Line Items]
Settlement agreement, amount claimants agreed to pay					$ 16,400
6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement | Ultra Resources, Inc.
Subsequent Event [Line Items]
Aggregate principal amount of debt exchanged		$ 505,000
Senior Secured Second Lien Notes due July 2024 | Exchange Agreement | Ultra Resources, Inc.
Subsequent Event [Line Items]
Equitization of Holdco Notes		$ 545,000
Subsequent Event | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement
Subsequent Event [Line Items]
Aggregate principal amount of debt exchanged				$ 44,600
Subsequent Event | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement | Ultra Resources, Inc.
Subsequent Event [Line Items]
Aggregate principal amount of debt exchanged				44,600
Subsequent Event | Senior Secured Second Lien Notes due July 2024 | Exchange Agreement
Subsequent Event [Line Items]
Equitization of Holdco Notes				$ 27,000
Subsequent Event | Fourth Amendment | Bank Of Montreal | Ultra Resources, Inc.
Subsequent Event [Line Items]
Borrowing Base	$ 1,300,000
Subsequent Event | Fourth Amendment | Bank Of Montreal | Ultra Resources, Inc. | Revolving Credit Facility
Subsequent Event [Line Items]
Borrowing Base	1,300,000
Credit facility, current borrowing capacity	$ 325,000
Maximum required consolidated net leverage ratio, as percentage, for fiscal quarter ending December 31, 2018	450.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019	475.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020	490.00%
Maximum required consolidated net leverage ratio, as percentage, for fiscal quarter ending September 30, 2020	450.00%
Maximum required consolidated net leverage ratio, as percentage, the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter	425.00%

Summarized Quarterly Financia_3

Summarized Quarterly Financial Information (Unaudited) - Summary of Quarterly Financial Information (Details) - 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
Quarterly Financial Data [Abstract]
Operating revenues	$ 273,211	$ 203,776	$ 190,138	$ 225,374	$ 240,627	$ 217,631	$ 212,657	$ 220,958	$ 892,499	$ 891,873
Operating expenses	145,506	126,872	127,679	137,686	132,574	122,394	134,393	104,227	537,743	493,588	$ 420,715
Other (expense) income, net:
Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016)	(36,382)	(38,382)	(37,715)	(35,837)	(36,388)	(210,107)	(29,425)	(85,447)	(148,316)	(361,367)	(66,565)
Gain (loss) on commodity derivatives	(69,607)	(21,804)	(47,271)	(6,530)	16,263	4,650	20,717	(13,218)	(145,212)	28,412
Contract settlement	15,332	(2,676)						(52,707)	12,656	(52,707)
Other income (expense), net	2,657	4,521	1,981	2,606	2,430	2,730	2,665	2,491	11,765	10,316
Total other (expense) income, net	(88,000)	(58,341)	(83,005)	(39,761)	(17,695)	(202,727)	(6,043)	(148,881)	(269,107)	(375,346)	(197,376)
Reorganization items, net					(1,240)	(227,123)	426,816	(57,546)		140,907	(47,503)
Income (loss) before income tax (benefit) provision	39,705	18,563	(20,546)	47,927	89,118	(334,613)	499,037	(89,696)	85,649	163,846	55,497
Income tax provision (benefit)	(1)		9	434	(6,410)	(6,886)		2	442	(13,294)	(654)
Net income	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	$ 85,207	$ 177,140	$ 56,151
Net income (loss) per common share — basic	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ 0.43	$ 1.08	$ 0.70
Net income (loss) per common share — fully diluted	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ 0.43	$ 1.08	$ 0.70

Disclosure About Oil and Gas _2

Disclosure About Oil and Gas Producing Activities (Unaudited) - Additional Information (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Internal engineer experience	14 years
Expert qualifications	The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over seven years of prior industry experience. He graduated from graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Significant changes in reserves	Changes in proved undeveloped reserves: The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years.
Weighted average sales price for proved reserves natural gas	$ 2.59	$ 2.59	$ 2.07
Weighted average sales price for proved reserves condensate	$ 63.49	$ 48.05	$ 37.90

Disclosure About Oil and Gas _3

Disclosure About Oil and Gas Producing Activities (Unaudited) - Analyses of Changes in Proven Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2018bblMcf	Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf
Natural Gas Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance | Mcf	2,955,992	2,321,613	2,336,280
Extensions, discoveries and additions | Mcf	85,180	50,312	251,634
Sales | Mcf	(4,033)	(89,315)
Acquisitions | Mcf		22,400
Production | Mcf	(260,406)	(260,009)	(264,278)
Revisions | Mcf	145,100	910,991	(2,023)
Reserves, Ending Balance | Mcf	2,921,833	2,955,992	2,321,613
Oil Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	27,118	21,475	22,175
Extensions, discoveries and additions	1,086	1,117	3,519
Sales	(3,573)
Acquisitions		153
Production	(2,442)	(2,775)	(2,912)
Revisions	1,256	7,148	(1,307)
Reserves, Ending Balance	23,445	27,118	21,475
Natural Gas Liquid Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	71	9,903	9,840
Extensions, discoveries and additions			530
Sales	(71)
Revisions		(9,832)	(467)
Reserves, Ending Balance		71	9,903

Disclosure About Oil and Gas _4

Disclosure About Oil and Gas Producing Activities (Unaudited) - Summary of Developed and Undeveloped Proven Reserves (Details) bbl in Thousands, Mcf in Thousands	Dec. 31, 2018bblMcf	Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf
Natural Gas Reserves
Reserve Quantities [Line Items]
Developed | Mcf	2,243,956	2,261,289	2,321,613	2,336,280
Undeveloped | Mcf	677,877	694,703
Total Proved | Mcf	2,921,833	2,955,992	2,321,613	2,336,280
Oil Reserves
Reserve Quantities [Line Items]
Developed	17,876	21,652	21,475	22,175
Undeveloped	5,569	5,466
Total Proved	23,445	27,118	21,475	22,175
Natural Gas Liquid Reserves
Reserve Quantities [Line Items]
Developed		71	9,903	9,840
Total Proved		71	9,903	9,840

Disclosure About Oil and Gas _5

Disclosure About Oil and Gas Producing Activities (Unaudited) - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future cash inflows	$ 9,195,725	$ 8,965,949	$ 5,812,234
Future production costs	(3,337,779)	(3,587,581)	(2,665,082)
Future development costs	(1,133,103)	(1,001,024)	(355,923)
Future income taxes	(180,057)
Future net cash flows	4,544,786	4,377,344	2,791,229
Discount at 10%	(2,139,303)	(1,993,016)	(1,100,283)
Standardized measure of discounted future net cash flows	$ 2,405,483	$ 2,384,328	$ 1,690,946	$ 1,865,649

Disclosure About Oil and Gas _6

Disclosure About Oil and Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning	$ 2,384,328	$ 1,690,946	$ 1,865,649
Net revisions of previous quantity estimates	160,405	840,505	(9,623)
Extensions, discoveries and other changes	90,609	53,549	209,603
Sales of reserves in place	(34,768)	(83,887)
Acquisition of reserves		21,903
Changes in future development costs	(235,205)	(329,635)	11,556
Sales of oil and gas, net of production costs	(593,134)	(589,621)	(454,725)
Net change in prices and production costs	362,084	572,224	(72,939)
Development costs incurred during the period that reduce future development costs	251,621	8,007	22,523
Accretion of discount	238,433	169,095	186,565
Net changes in production rates and other	(189,017)	31,242	(67,663)
Net change in income taxes	(29,873)
Aggregate changes	21,155	693,382	(174,703)
Standardized measure, ending	$ 2,405,483	$ 2,384,328	$ 1,690,946

Disclosure About Oil and Gas _7

Disclosure About Oil and Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Gas Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$ 1,468	$ 1,399	$ 983
Acquisition costs - proved properties	1,090	9,147
Exploration	156,718	510,710	224,277
Development	266,905	35,934	44,300
Total	$ 426,181	$ 557,190	$ 269,560

Disclosure About Oil and Gas _8

Disclosure About Oil and Gas Producing Activities (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$ 892,499	$ 891,873	$ 721,091
Production expenses	(299,365)	(292,095)	(266,366)
Depletion and depreciation	(204,255)	(161,945)	(125,121)
Income tax benefit (expense)	(2)	(168,355)	83,112
Total	$ 388,877	$ 269,478	$ 412,716

Disclosure About Oil and Gas _9

Disclosure About Oil and Gas Producing Activities (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,577,281	$ 11,215,563
Less: accumulated depletion, depreciation and amortization	(10,079,554)	(9,890,495)
Total Oil and gas properties, net	$ 1,497,727	$ 1,325,068

Supplemental Financial Statem_3

Supplemental Financial Statement Information - Supplemental Statement Of Operations Disclosures Parent Company (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
General and administrative expense									$ 25,005	$ 39,548	$ 9,179
Other income (expense):
Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016)	$ (36,382)	$ (38,382)	$ (37,715)	$ (35,837)	$ (36,388)	$ (210,107)	$ (29,425)	$ (85,447)	(148,316)	(361,367)	(66,565)
Other expense									1,212	(237)	(3,082)
Reorganization items, net					(1,240)	(227,123)	426,816	(57,546)		140,907	(47,503)
Income tax provision (benefit)	(1)		9	434	(6,410)	(6,886)		2	442	(13,294)	(654)
Net income	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	85,207	177,140	56,151
Parent
General and administrative expense									549	428	650
Other income (expense):
Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016)										(71,876)	(26,590)
Income (loss) from unconsolidated affiliates									85,809	(183,840)	157,450
Guarantee fee income											6,073
Other expense									(44)	90	(64,888)
Reorganization items, net										433,196	(15,827)
Income before income taxes									85,216	177,142	55,568
Income tax provision (benefit)									9	2	(583)
Net income									$ 85,207	$ 177,140	$ 56,151

Supplemental Financial Statem_4

Supplemental Financial Statement Information - Supplemental Statement Of Operations Disclosures Parent Company (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Contractual interest expense on prepetition liabilities not recognized in statement of operations	$ 141.5
Parent
Contractual interest expense on prepetition liabilities not recognized in statement of operations	$ 52.4

Supplemental Financial Statem_5

Supplemental Financial Statement Information - Supplemental Balance Sheet Disclosures Parent Company (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 17,014	$ 16,631	$ 401,478
Other current assets	2,473	5,647
Total current assets	214,730	167,425
Other non-current assets	9,196	10,920
Total assets	1,733,288	1,512,982
Current liabilities:
Accrued and other current liabilities	58,574	80,268
Total current liabilities	267,211	248,490
Total liabilities	2,781,910	2,667,618
Total shareholders’ deficit	(1,048,622)	(1,154,636)	(2,928,151)	$ (2,991,937)
Total liabilities and shareholders’ equity	1,733,288	1,512,982
Parent
Current Assets:
Cash and cash equivalents	570	803	$ 3,009	$ 523
Accounts receivable from related companies	29,939	29,940
Total current assets	30,509	30,743
Total assets	30,509	30,743
Current liabilities:
Accrued and other current liabilities		21
Total current liabilities		21
Advances from unconsolidated affiliates	1,079,131	1,185,359
Total liabilities	1,079,131	1,185,380
Total shareholders’ deficit	(1,048,622)	(1,154,637)
Total liabilities and shareholders’ equity	$ 30,509	$ 30,743

Supplemental Financial Statem_6

Supplemental Financial Statement Information - Supplemental Cash Flow Statement Disclosures Parent Company (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net cash (used in) operating activities	$ 310,897	$ 65,268	$ 311,070
Investing Activities:
Net cash used in investing activities	(401,710)	(435,311)	(278,900)
Financing activities:
Deferred financing costs	(9,773)	(73,092)
Shares issued		573,774
Repurchased shares/net share settlements	(2,378)	(9,581)	(379)
Net cash provided by (used in) financing activities	91,849	(16,737)	368,621
Cash and cash equivalents, beginning of period	16,631	401,478
Cash and cash equivalents, end of period	17,014	16,631	401,478
Parent
Net cash (used in) operating activities	(234)	(2,206)	(21,309)
Investing Activities:
Investment in subsidiaries	(3,293)	(588,677)
Dividends received			24,089
Net cash used in investing activities	(3,293)	(588,677)	24,089
Financing activities:
Shares issued	3,294	573,774
Repurchased shares/net share settlements		14,903	43
Shares re-issued from treasury			(337)
Net cash provided by (used in) financing activities	3,294	588,677	(294)
(Decrease) increase in cash during the period	(233)	(2,206)	2,486
Cash and cash equivalents, beginning of period	803	3,009	523
Cash and cash equivalents, end of period	$ 570	$ 803	$ 3,009