Ultra Petroleum 10-K 14 Apr 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Mar. 31, 2020	Jun. 28, 2019
Cover [Abstract]
Entity Registrant Name	ULTRA PETROLEUM CORP.
Entity Central Index Key	0001022646
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
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	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Entity Public Float			$ 28,438,541
Entity Common Stock, Shares Outstanding		198,303,021
Entity Interactive Data Current	Yes
Entity File Number	001-33614
Entity Incorporation, State or Country Code	B0
Entity Address, Address Line One	116 Inverness Drive East
Entity Address, Address Line Two	Suite 400
Entity Address, City or Town	Englewood
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80112
City Area Code	303
Local Phone Number	708-9740
Document Annual Report	true
Document Transition Report	false
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement relating to its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Form 10-K.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 1,664	$ 17,014
Restricted cash	1,777	2,291
Oil and gas revenue receivable	71,957	133,042
Joint interest billing and other receivables net of allowances $11,967 and $8,350, respectively	6,364	11,348
Derivative asset	32,100	23,374
Income tax receivable	881	6,431
Other current assets	10,746	21,230
Total current assets	125,489	214,730
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,552,419	1,497,727
Property, plant and equipment	9,779	11,635
Long-term right-of-use assets	119,496
Other	8,093	9,196
Total assets	1,815,276	1,733,288
Current liabilities:
Accounts payable	13,570	36,923
Accrued liabilities	42,824	58,574
Production taxes payable	53,428	58,365
Revolving credit facility, at face value	64,700
Debt, at face value	1,928,048	7,313
Add: Premium on exchange transaction	203,883
Less: Unamortized deferred financing costs and discount	(46,421)
Total current portion of long-term debt, net	2,150,210	7,313
Interest payable	29,903	28,672
Capital cost accrual	1,656	15,014
Lease liabilities	11,938
Derivative liability	20,692	62,350
Total current liabilities	2,324,221	267,211
Long-term debt
Revolving credit facility, at face value		104,000
Long-term debt, at face value		1,932,722
Add: Premium on exchange transaction	203,883	228,096
Less: Unamortized deferred financing costs and discount	(46,421)	(56,650)
Total long-term debt, net	2,150,210	2,208,168
Deferred gain on sale of liquids gathering system		94,636
Long-term lease liabilities	107,587
Other long-term obligations	228,282	211,895
Total liabilities	2,660,090	2,781,910
Commitments and contingencies (Note 14)
Shareholders’ equity:
Common stock — As of December 31, 2019 no par value; authorized — unlimited; issued and outstanding shares — 197,888,473 and as of December 31, 2018 no par value; authorized — 750,000,000; issued and outstanding shares — 197,383,295	2,140,520	2,137,443
Treasury stock	(49)	(49)
Retained loss	(2,985,285)	(3,186,016)
Total shareholders’ deficit	(844,814)	(1,048,622)
Total liabilities and shareholders’ equity	$ 1,815,276	$ 1,733,288

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement Of Financial Position [Abstract]
Joint interest billing and other receivables net of allowances	$ 11,967	$ 8,350
Common stock, No par value
Common stock, Shares authorized	Unlimited
Common Stock, Shares authorized		750,000,000
Common stock, Shares issued	197,888,473	197,383,295
Common stock, Shares outstanding	197,888,473	197,383,295

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Total operating revenues	$ 742,032	$ 892,499	$ 891,873
Expenses:
Lease operating expenses	70,608	90,290	92,326
Facility lease expense	25,468	25,947	21,749
Production taxes	79,459	93,322	91,067
Gathering fees	78,261	89,294	87,287
Transportation charges	1,496	512	(334)
Depletion, depreciation and amortization	204,227	204,255	161,945
General and administrative	26,551	25,005	39,548
Other operating expenses, net	28,889	9,118
Total operating expenses	514,959	537,743	493,588
Operating income	227,073	354,756	398,285
Other (expense) income, net:
Interest expense, net	(129,398)	(148,316)	(361,367)
Gain (loss) on commodity derivatives	(4,597)	(145,212)	28,412
Deferred gain on sale of liquids gathering system		10,553	10,553
Contract settlement income (expense), net	13,468	12,656	(52,707)
Other income (expense), net	392	1,212	(237)
Total other (expense) income, net	(120,135)	(269,107)	(375,346)
Reorganization items, net			140,907
Income before income tax expense (benefit)	106,938	85,649	163,846
Income tax expense (benefit)	(1,050)	442	(13,294)
Net income	$ 107,988	$ 85,207	$ 177,140
Basic Earnings per Share:
Net income per common share — basic	$ 0.55	$ 0.43	$ 1.08
Fully Diluted Earnings per Share:
Net income per common share — fully diluted	$ 0.55	$ 0.43	$ 1.08
Weighted average common shares outstanding — basic	197,651	196,964	163,824
Weighted average common shares outstanding — fully diluted	197,690	197,541	163,976
Natural Gas Sales
Revenues:
Total operating revenues	$ 637,007	$ 722,313	$ 748,682
Oil Sales
Revenues:
Total operating revenues	97,231	153,534	133,368
Other Revenues
Revenues:
Total operating revenues	$ 7,794	$ 16,652	$ 9,823

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Retained Loss	Treasury Stock
Beginning Balances at Dec. 31, 2016	$ (2,928,151)	$ 510,063	$ (3,438,165)	$ (49)
Beginning 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
Issuance of common stock upon vesting and settlement of equity awards, net of shares used for tax withholdings	17,093	$ 26,673	(9,580)
Issuance Of Stock Upon Vesting And Settlement Of Equity Awards, Net Of Shares For Tax Withholdings, Shares		1,361
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
Issuance of common stock upon vesting and settlement of equity awards, net of shares used for tax withholdings	(2,379)		(2,379)
Issuance Of Stock Upon Vesting And Settlement Of Equity Awards, Net Of Shares For Tax Withholdings, Shares		1,036
Issuance of warrants	5,786	$ 5,786
Fair value of employee stock plan grants	15,639	15,639
Initial adoption | 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
Issuance of common stock upon vesting and settlement of equity awards, net of shares used for tax withholdings	(75)		(75)
Issuance Of Stock Upon Vesting And Settlement Of Equity Awards, Net Of Shares For Tax Withholdings, Shares		505
Fair value of employee stock plan grants	3,077	$ 3,077
Initial adoption | ASC 842	92,818		92,818
Net income	107,988		107,988
Ending Balances at Dec. 31, 2019	$ (844,814)	$ 2,140,520	$ (2,985,285)	$ (49)
Ending Balances, Shares at Dec. 31, 2019		197,888

Consolidated Statements of Sh_2

Consolidated Statements of Shareholders' Equity (Parenthetical) - Common Stock	Apr. 12, 2017shares
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net income for the period	$ 107,988	$ 85,207	$ 177,140
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization	204,227	204,255	161,945
Unrealized (gain) loss on commodity derivatives	(54,282)	59,799	(16,966)
Deferred gain on sale of liquids gathering system		(10,553)	(10,553)
Stock compensation	2,571	11,825	39,977
Payable-in-kind (“PIK”) interest payable	12,867	377
Non-cash reorganization items, net			(453,909)
Amortization of premium on restructuring	(41,774)	(1,083)
Amortization of deferred financing costs	12,966	11,210	7,483
Inventory write-down	7,461
Other	3,153	3,501	(1,047)
Net changes in operating assets and liabilities:
Accounts receivable	62,452	(46,276)	(14,483)
Other current and non-current assets	3,139	5,630	14,615
Accounts payable	(8,195)	(13,206)	34,349
Accrued liabilities	(15,751)	(20,294)	89,935
Production taxes payable	(4,937)	7,098	7,023
Interest payable	1,251	3,889	36,220
Other long-term obligations	3,730	2,674	4,737
Current taxes payable/receivable	5,550	6,844	(11,198)
Net cash provided by operating activities	302,416	310,897	65,268
Investing Activities:
Oil and gas property expenditures	(241,134)	(426,166)	(557,029)
Sale of oil and gas properties		61,304	114,263
Change in capital cost accrual and accounts payable	(28,516)	(27,322)	20,076
Proceeds from sale of property, plant and equipment	9	2,872
Purchase of property, plant and equipment	(511)	(12,398)	(12,621)
Net cash used in investing activities	(270,152)	(401,710)	(435,311)
Financing activities:
Payments under Credit Agreement / Term Loan	(7,313)
Extinguishment of long-term debt (chapter 11)			(2,459,000)
Proceeds from issuance of Senior Notes			1,200,000
Deferred financing costs	(1,440)	(9,773)	(73,092)
Shares issued, net of transaction costs			573,774
Tax withholding on shares settled	(75)	(2,378)	(9,581)
Debt extinguishment costs			(223,838)
Net cash provided by (used in) financing activities	(48,128)	91,849	(16,737)
(Decrease)/Increase in cash during the period	(15,864)	1,036	(386,780)
Cash, cash equivalents, and restricted cash at beginning of period	19,305	18,269	405,049
Cash, cash equivalents, and restricted cash end of period	3,441	19,305	18,269
Cash paid for:
Interest	143,738	135,230	317,120
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 Agreement	712,900	1,020,000	773,000
Payments under Credit Agreement / Term Loan	$ (752,200)	$ (916,000)	(773,000)
Term Loan
Financing activities:
Borrowings under Credit Agreement			$ 975,000

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2019
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 operation and production, development and 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 operating and developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	1. Going Concern. As a result of our significant indebtedness and extremely challenging current market conditions that have had an adverse impact on our business, and as a result of our financial condition, substantial doubt exists about our ability to continue as a going concern. A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements is expected to result in reduced borrowing capacity or an event of default, causing our debt obligations under such financing agreements (and any other indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. Accordingly, all debt balances as of December 31, 2019 have been classified as current on the consolidated balance sheet. In February and March 2020, we entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors. Negotiations and discussions with certain debtholders and their advisors are ongoing, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions. There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be. If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement an agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate proceedings under Chapter 11 of the United States Bankruptcy Code to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. In either case, such a proceeding could be commenced in the near term. The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. Under our Credit Agreement and Term Loan Agreement, we are required to deliver audited, consolidated financial statements without a going concern or like qualification or explanation. Because the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern, we will be in default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when we deliver our financial statements to the lenders under the Credit Agreement and the Term Loan Agreement, respectively. We expect that we will be precluded from drawing additional amounts under the Credit Agreement while the default exists. There is a 30-day grace period related to this covenant in each of the Credit Agreement and the Term Loan Agreement. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement or the Term Loan Agreement before the expiration of the 30-day grace period, an event of default under each of the Credit Agreement and Term Loan Agreement would occur. If an event of default occurs, the lenders could accelerate the loans outstanding under the Credit Agreement and Term Loan Agreement. In addition, if the lenders under our Credit Agreement and Term Loan Agreement accelerate the loans outstanding thereunder, we will then also be in default under the indentures related to our Second Lien Notes and our Unsecured Notes. If we default under those indentures, the holders of the Second Lien Notes and Unsecured Notes could accelerate those notes. At this time, we do not expect to obtain a waiver of this requirement. 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 distribution of the production revenues 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. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Financial Statements: Current Presentation December 31, 2019 December 31, 2018 December 31, 2017 Cash and Cash Equivalents $ 1,664 $ 17,014 $ 16,631 Restricted Cash 1,777 2,291 1,638 Total cash, cash equivalents, and restricted cash $ 3,441 $ 19,305 $ 18,269 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 operating expenses, net on the Consolidated Statements of Operations is the provision for uncollectible accounts of $3.3 million for the period ended December 31, 2019. 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 lives. 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 (“ASC 932”). Under this method of accounting, the costs of successful and 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 the 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 of unevaluated properties 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, estimated 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 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 of the 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 subsequent 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 2019, 2018 or 2017. Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“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 for additional information). 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 of the Company each entitling the holder thereof to purchase one common share of the Company (each a “Warrant” and collectively, the “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. 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. Certain share-based awards subject to 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 market criteria are met. Additionally, certain share-based awards subject to service conditions are considered anti-dilutive if the exercise price exceeds the average market price. Lastly, 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, 2019, 2018 and 2017, the Company had 20.9 million, 14.2 million and 3.9 million, respectively, of shares not included in dilutive earnings per share because the shares would have been anti-dilutive as the exercise price was greater than the average market price of the common shares or the shares are contingently issuable shares. The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2019 2018 2017 Net income $ 107,988 $ 85,207 $ 177,140 Weighted average common shares outstanding during the period 197,651 196,964 163,824 Effect of dilutive instruments 39 577 152 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,690 197,541 163,976 Net income per common share — basic $ 0.55 $ 0.43 $ 1.08 Net income per common share — fully diluted $ 0.55 $ 0.43 $ 1.08 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 based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. We also estimate forfeitures at the time of grant and revise those estimates in subsequent periods if actual forfeitures differ from our estimates. Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“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 revenue recognition. 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 capital expenditures, including 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. New Accounting Pronouncements: From time to time, the FASB issues new accounting pronouncements. Updates to the FASB ASC are communicated through issuance of an Accounting Standards Update (“ASU”). Unless otherwise discussed, we believe that the impact of recently issued guidance, whether adopted or to be adopted in the future, is not expected to have a material impact on the consolidated financial statements upon adoption. Recently Adopted Accounting Pronouncements: Leases: In February 2016, the FASB issued ASU 2016-02, , and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. The Company adopted ASC 842 and applicable amendments on January 1, 2019, using the modified retrospective approach. The Company elected certain practical expedients and established internal controls and key system functionality to enable the preparation of financial information on adoption. The adoption of the standard had an effect on the Company’s consolidated balance sheets and consolidated statement of operations. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 12 for additional discussion. Cumulative Effect of Recently Adopted Accounting Pronouncements: The following table reflects the cumulative impact of the adoption of ASC 842 on January 1, 2019, using the modified retrospective approach: December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (In thousands) Long-term right-of-use assets $ — $ 130,649 $ 130,649 Total assets 1,733,288 130,649 1,863,937 Lease liabilities (current) — 11,141 11,141 Deferred gain on sale of liquids gathering system 94,636 (94,636 ) — Long-term lease liabilities — 121,326 121,326 Total liabilities 2,781,910 37,831 2,819,741 Retained earnings (loss) (3,186,016 ) 92,818 (3,093,198 ) Total shareholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and shareholders' equity (deficit) 1,733,288 130,649 1,863,937 Recent Accounting Pronouncements Not Yet Adopted: Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, (Topic 820): — 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. The Company is currently assessing the impact of this standard on its disclosures. The standard is effective for the Company on January 1, 2020. Financial Instruments. In June 2016, The FASB issued ASU 2016-13, (Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This ASU changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. For small reporting companies, as defined by the SEC, ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2022. The standard is effective for the Company on January 1, 2023. The Company is currently assessing the impact of ASU 2016-13 on its consolidated financial statements. Income Taxes. In December 2019, the FASB issued authoritative guidance intended to simplify the accounting for income taxes (ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”). This guidance eliminates certain exceptions to the general approach to the income tax accounting model, and adds new guidance to reduce the complexity in accounting for income taxes. This guidance is effective for annual periods after December 15, 2020, including interim periods within those annual periods. We are currently evaluating the potential impact of this guidance on our financial statements.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue From Contract With Customer [Abstract]
Revenue Recognition	2. REVENUE RECOGNITION: Revenue from Contracts with Customers Sales of oil and natural gas are recognized at the point when title and custody (“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 line or a transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price we receive for our produced 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 processing plant inlet, the tailgate of the processing plant or at another agreed-upon delivery point, as specified in the contracts with our customers. The production is sold at set volumes and we collect either (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue at the net price received when control transfers to the purchaser at the agreed-upon delivery point. 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 their gas volumes in kind. The Company may act as an agent and market the other partners’ share of the natural gas production from wells we operate. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Oil sales We sell oil production at either (a) a lease automatic custody transfer meter, (b) a tank battery, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect either (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) 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 Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take their oil volumes in kind. The Company acts as an agent and markets the other partners’ share of almost all oil production from wells we operate. In these situations, 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 when 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. 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 at index-based prices. 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 when control is transferred to the purchaser and all contractual obligations are satisfied. However, settlement statements for certain natural gas sales may not be received for 30 to 90 days after the date production is delivered. Consequently, 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 been insignificant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the years ended December 31, 2019 and 2018.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Asset retirement obligations at beginning of period $ 179,462 $ 173,100 Accretion expense 13,255 12,342 Liabilities incurred 1,511 3,558 Liabilities divested (1) — (9,372 ) Liabilities settled — (70 ) Revisions of estimated liabilities (40 ) (96 ) Asset retirement obligations at end of period 194,188 179,462 Less: current asset retirement obligations (193 ) (193 ) Long-term asset retirement obligations (2) $ 193,995 $ 179,269 (1) During the year ended December 31, 2018, the Company divested certain non-core properties in Utah. (2) Included in Other long-term obligations in the Consolidated Balance Sheet.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2019
Oil And Gas Property [Abstract]
Oil and Gas Properties	4 . OIL AND GAS PROPERTIES: December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,820,392 $ 11,577,281 Less: Accumulated depletion, depreciation and amortization (10,267,973 ) (10,079,554 ) Total Oil and gas properties, net 1,552,419 1,497,727 On a unit basis, DD&A was $0.85, $0.74 and $0.59 per Mcfe for the years ended December 31, 2019, 2018 and 2017, respectively. Impairment of Oil and Gas Properties in the quarter ended March 31, 2020 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. In order to fulfill the obligation to evaluate the full cost ceiling and to calculate DD&A of its oil and gas properties, the Company is required to estimate its reserves on a quarterly basis. The estimated proven oil and gas reserves considers the estimated future production based on the most current well information available including decline rate changes causing downward revisions and updated pricing in accordance with SEC requirements. The reserve estimated as of March 31, 2020 were prepared by Netherland, Sewell & Associates, Inc. The comparable calculated average SEC prices utilized in the preparation of the reserves as of March 31, 2020 were $2.07 per Mcf and $55.35 per Bbl. These prices represent a decrease of 15% and <1% for natural gas and oil, respectively, as compared to the pricing utilized as of December 31, 2019. As a result of the decrease in both quantities of oil and gas reserves, as well as the discounted future cash flow estimates, the Company estimates it will record an increased rate of DD&A per Mcfe and require a material impairment charge to its oil and gas properties due to the ceiling test limitation as of March 31, 2020.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	5 . December 31, 2019 2018 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,893 (2,349 ) 544 619 Office equipment 277 (221 ) 56 65 Leasehold improvements 264 (206 ) 58 86 Land 2,437 — 2,437 2,437 Production and other equipment 20,221 (13,537 ) 6,684 8,428 Property, plant and equipment, net $ 26,092 $ (16,313 ) $ 9,779 $ 11,635

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	6 . December 31, 2019 Principal (1) Unamortized Deferred Financing Costs and Discounts (2) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement, secured, due January 2022 $ 64,700 $ — $ — $ 64,700 Term Loan, secured, due April 2024 968,756 (22,498 ) — 946,258 Second Lien Notes, secured, due July 2024 583,853 — 203,883 787,736 6.875% Unsecured Notes due April 2022 150,439 (11,146 ) — 139,293 7.125% Unsecured Notes due April 2025 225,000 (12,777 ) — 212,223 Total $ 1,992,748 $ (46,421 ) $ 203,883 $ 2,150,210 (1) Includes PIK interest on the Term Loan and Second Lien Notes of $1.1 million and $11.8 million, respectively. (2) 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. December 31, 2018 Principal Unamortized Deferred Financing Costs and Discounts (1) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement, secured, due January 2022 $ 104,000 $ — $ — $ 104,000 Term Loan, secured, due April 2024 975,000 (26,874 ) — 948,126 Second Lien Notes, secured, due July 2024 545,000 — 228,096 773,096 6.875% Unsecured Notes due April 2022 195,035 (15,168 ) — 179,867 7.125% Unsecured Notes due April 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 (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, 2020 (1) $ 1,992,748 2021 $ — 2022 ( 2 ) $ — 2023 $ — 2024 $ — Beyond 5 years $ — Total $ 1,992,748 (1) As previously noted, the audit report prepared by the Company’s independent registered public accounting firm includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern. This is a default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when we deliver our financial statements to the lenders under the Credit Agreement. As a result, we have reclassified our total outstanding debt as short-term as of December 31, 2019. (2) In connection with the Exchange Transaction, the Company entered into the Term Loan Amendment, which among other things, included a prohibition on repurchasing more than $50 million of the 6.875% Unsecured Notes due 2022 or the 7.125% Unsecured Notes due 2025 at their respective maturity dates or within one year thereof. Ultra Resources, Inc. Credit Agreement. Ultra Resources Inc., a Delaware corporation and wholly-owned subsidiary of the Company (“Ultra Resources”), entered into a Credit Agreement (as amended, the “Credit Agreement”) as the borrower 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 from time to time (collectively, the “RBL Lenders”), 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). On February 14, 2020, Ultra Resources entered into a Sixth Amendment to the Credit Agreement (the “Sixth Amendment”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Sixth Amendment and the spring 2020 borrowing base redetermination, the Borrowing Base (as defined in the Credit Agreement) was reduced, effective April 1, 2020 to $1.075 billion, with $100 million attributed to the Revolving Credit Facility. As described in previous periodic reports, the commitment amount for the Revolving Credit Facility was reduced from $120 million to $100 million, as established by the Sixth Amendment. Also included in the Sixth Amendment was the reduction of the all times anti-cash hoarding amount to $15 million and a provision to complete the borrowing base redetermination quarterly. The next scheduled borrowing base redetermination is scheduled to be completed on or before July 1, 2020. Other provisions of the Credit Agreement, including the recent amendments are described below: • elimination of all financial maintenance covenants; • required minimum hedging on projected natural gas volumes for at least 50% through March 31, 2020, and no minimum hedging requirements exist thereafter; • limitation of capital expenditures of $65 million, $10 million and $5 million, for the quarters ended September 30, 2019, December 31, 2019, and quarterly thereafter, with the ability to carryforward unused amounts up to $5 million in aggregate; and • ability to repurchase indebtedness, including borrowings under the Company’s Senior Secured Term Loan, Senior Secured Second Lien Notes, 6.875% Senior Notes due 2022 and 7.125% Senior Notes due 2025 under certain circumstances, including having no amounts drawn on the Revolving Credit Facility, the Company having established adequate cash reserves, satisfaction of a first lien incurrence test, each as set forth in the Fifth Amendment, and compliance with the Company’s other debt documents. The Term Loan and the Second Lien Notes continue to have prohibitions against the use of cash to repurchase debt. Therefore, in order for the Company to utilize this provision provided by the Credit Agreement, the Company would have to receive additional approval from both the Term Loan Lenders (as defined below) and the holders of the Second Lien Notes. As of December 31, 2019, Ultra Resources had $64.7 million of outstanding borrowings under the Revolving Credit Facility, plus an outstanding Letter of Credit of $6.7 million, with total commitments of $200.0 million. Availability under the Revolving Credit Facility is the undrawn portion of the commitment, plus the unrestricted cash of the Company, and net of any outstanding letters of credit outstanding for a total availability of $130.3 million as of December 31, 2019. The Company believes there is substantial doubt that its projected cash flows from operations and available liquidity under the Sixth Amendment will be adequate to meet its obligations for the ensuing twelve months from the date of this report. The next scheduled borrowing base redetermination will be July 1, 2020, as noted above, and then continue on a quarterly basis thereafter. To the extent future commitments under the Credit Agreement decreases below the outstanding balance of the Revolving Credit Facility, because of a downward redetermination of the borrowing base and commitment amount, the Company would be required to enter into a mandatory repayment schedule to satisfy the deficiency. Should the lenders not support such a repayment schedule, in month liquidity for the Company could be inadequate to meet obligations on a timely basis. In the event that the borrowing base is reduced to an amount that is less than the outstanding borrowings under the Term Loan Agreement, then commitments under the Revolving Credit Facility would be reduced to zero and Ultra Resources would become subject to additional coverage tests under the Term Loan Agreement. Among these new requirements is an asset coverage test and, if not satisfied, Ultra Resources would be required to make mandatory prepayments to the Term Loan Lenders in order to cure any deficiency. Failure to make such required payments would result in an Event of Default under the Term Loan Agreement. The Revolving Credit Facility has $35.0 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 based upon the borrowing base utilization grid. The applicable margin increases by 25 basis points in the event the Company’s consolidated net leverage ratio, as defined, exceeds 4.00 to 1.00 . 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 loans mature on January 12, 2022. As noted above, the Fifth Amendment established a maximum capital expenditure level. Per the definition of maximum capital expenditures in the Fifth Amendment, the Company expended $6.8 million in the quarter ended December 31, 2019, and $53.7 million in the quarter ended September 30, 2019, resulting in a $5 million carryover as of December 31, 2019. The Revolving Credit Facility also contains customary affirmative and negative covenants, including, 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. As of December 31, 2019, Ultra Resources was in compliance with its debt covenants under the Revolving Credit Facility. Subsequent to December 31, 2019, the audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the Credit Agreement. 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 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 may terminate any outstanding unfunded commitments. Term Loan. Ultra Resources, entered into a Term Loan Agreement (the “Term Loan Agreement”) as the borrower with the Company and UP Energy Corporation, as parent guarantors, with Barclays Bank PLC(“Barclays”), as administrative agent (the “Term Loan Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “Term Loan Lenders”), providing for a term loan credit facility. As of December 31, 2019, Ultra Resources had a balance of approximately $968.8 million in borrowings, including $1.1 million PIK interest. In December 2018, 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 2018 Exchange Transaction (as defined below), 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, with the remaining term of the call protection at 101% until December 21, 2020; • 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; • collateral coverage established at 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; • prohibiting the repurchase of more than $50 million of the 2022 Notes (as defined below) or the 2025 Notes (as defined below) at their respective maturity dates or within one year thereof; • 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. Borrowings under the Term Loan Agreement bear interest at a rate equal to either (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”) solely upon election by Ultra Resources. During 2019, the Company elected the PIK option for several of its selected interest payments. In the third quarter 2019, the Company began electing not to utilize this PIK option. Beginning in June 2019, the borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the initial aggregate principal amount. Remaining borrowings under the Term Loan Agreement mature on April 12, 2024. Borrowings under the Term Loan Agreement are 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 conditions including a situation in which the Revolving Credit Facility no longer exist, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments equal to six monthly payments are required in order to attain compliance, with such amounts being applied to prepay the borrowings under the Term Loan Agreement. 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, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement. Subsequent to December 31, 2019, the audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default 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 . As of December 31, 2019, Ultra Resources had approximately $583.9 million, including $11.8 million of PIK interest, in outstanding borrowings of Senior Secured Second Lien Notes (the “Second Lien Notes”) pursuant to the Indenture, dated December 21, 2018 (the “Second Lien Notes Indenture”), with Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral agent. Interest on the Second Lien Notes accrues at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The cash interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing in July 2019. The Company has accounted for such PIK interest as an increase to the principal outstanding. The Second Lien Notes will mature on July 12, 2024. 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 Ultra Resources 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, (viii) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (ix) 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 (x) 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. Senior Unsecured Notes . At December 31, 2019, Ultra Resources had approximately $150.4 million of the 6.875% Senior Notes due 2022 In December 2018, the Company exchanged (i) $505 million aggregate principal amount, or 72.1%, of the 2022 Notes, and (ii) $275 million aggregate principal amount, or 55%, of the 2025 Notes of Ultra Resources for (a) $545.0 million aggregate principal amount of new Second Lien Notes, and (b) an aggregate of 10,919,499 Warrants (such transaction, the “2018 Exchange Transaction”). Then in the first quarter of 2019, the Company entered into an incremental note exchange transaction that provided for the exchange of $44.6 million aggregate principal amount of 2022 Notes for $27.0 million aggregate principal amount of Second Lien Notes (together with the 2018 Exchange Transaction, the “Exchange Transactions”), as allowed by the Second Lien Notes Indenture. The Company evaluated the accounting treatment of the Exchange Transactions under ASC 470, Debt 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. 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.

Equity Compensation

Equity Compensation	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity Compensation	2017 Stock Incentive Plan In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (the “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”). 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 (as defined in the A&R Stock Incentive Plan) 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 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. There are several components to the Plan that are described below. Various types of equity awards have been granted by the Company in different periods. As of December 31, 2019, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved equity 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 12,588 Equity compensation plans not approved by security holders n/a Total 12,588 Performance Share Units : The Company grants performance share units (“PSUs”) to eligible employees as part of its Plan. For purposes of ASC 718, when vesting of an equity award is dependent on a specific share value or the value of a company’s total equity, the award is considered to be subject to a “market condition”. ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the equity award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the equity awards that include a market condition. ASC 718 requires the expense for an award of equity 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) the award’s derived service period. The Company uses a lattice model to determine the derived service period which 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. 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 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 In July 2018, the Company offered the recipients of the Initial MIP Grants an opportunity to exchange the unvested portion of their Initial MIP Grants for new equity awards of time-based restricted stock units (“RSUs”) effective July 31, 2018 on a one-for-one basis (the “Initial MIP Exchange”). The RSUs granted as part of the Initial MIP Exchange 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 In March 2019, additional Initial MIP Grants were exchanged for new equity awards of time-based and performance-based restricted stock units (collectively with the Initial MIP Exchange, the “MIP Exchanges”). The Company evaluated the cancellation of an outstanding award of equity compensation followed by the issuance of a replacement award under ASC 718. For the March 2019 modification, the fair value of the equity award was assessed both prior to modification and after modification. Per ASC 718, if the fair value after modification exceeded the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period. This incremental expense is reflected in the pre-tax equity compensation expense described below. See Equity Compensation Cost: Expense Additionally, in 2018 and 2019, the Board approved long-term incentive awards under the 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 market conditions are achieved. The awards cover a performance period of three years and include time-based vesting conditions and market-based measures established by the Committee at the beginning of the three-year period. The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. A summary of the status and activity of non-vested PSUs is presented in the following table: Year Ended December 31, 2019 2018 2017 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 3,128,575 3,874,278 — Granted 5,310,251 $ 0.30 2,524,719 $ 0.62 4,214,902 $ 11.87 Vested — $ — (1,769,734 ) $ 11.87 — $ — Forfeited (1,950,658 ) $ 0.41 (329,156 ) $ 11.87 (214,408 ) $ 11.87 Cancelled — $ — — $ — (126,216 ) $ 11.87 Cancelled - MIP Exchanges (581,677 ) $ 11.87 (1,171,532 ) $ 11.87 — $ — Non-vested at end of year 5,906,491 3,128,575 3,874,278 During the years ended December 31, 2019 and 2017, there were no common stock issued to settle PSUs. Presented below is a summary of the shares of common stock issued to settle PSUs for the year ended December 31, 2018: Year Ended December 31, 2018 Shares of common stock issued to settle PSUs (1) 1,769,734 Less: shares of common stock withheld for income and payroll taxes (733,174 ) Net shares of common stock issued 1,036,560 (1) During the year ended December 31, 2018, the Company issued shares of common stock to settle PSUs that related to awards granted in 2017. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. Restricted Share Units : The Company grants RSUs to eligible persons as part of its Plan. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized over the vesting periods of the respective awards. The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. A summary of the status and activity of non-vested RSUs granted to eligible persons is presented in the following table: Year Ended December 31, 2019 2018 2017 RSUs Weighted-Average Grant-Date Fair Value RSUs Weighted-Average Grant-Date Fair Value RSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 2,734,709 73,048 — Granted 2,677,593 $ 0.64 1,650,983 $ 1.89 2,269,199 $ 13.59 Vested (1,042,515 ) $ 4.59 — $ — (2,191,297 ) $ 14.07 Forfeited (704,916 ) $ 6.41 (160,854 ) $ 3.00 (4,854 ) $ 10.31 Granted - MIP Exchanges 581,677 $ 0.70 1,171,532 $ 1.77 — $ — Non-vested at end of year 4,246,548 2,734,709 73,048 A summary of the shares of common stock issued to settle RSUs is presented in the table below: Year Ended December 31, 2019 2018 2017 Shares of common stock issued to settle RSUs (1) 715,809 — 2,191,297 Less: shares of common stock withheld for income and payroll taxes (210,631 ) — (837,282 ) Net shares of common stock issued 505,178 — 1,354,015 (1) During the year ended December 31, 2019 and 2017, the Company issued shares of common stock to settle RSUs that related to awards granted in 2017, 2018 and 2019. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. Equity Compensation Cost: For the year ended December 31, 2019, the Company recognized $2.6 million in pre-tax equity compensation expense. For the year ended December 31, 2018, the Company recognized $11.8 million in pre-tax equity compensation expense. For the year ended December 31, 2017, the Company recognized $40 million in pre-tax equity compensation expense. As of December 31, 2019, there was $1.4 million of total unrecognized compensation expense related to non-vested awards, which is being amortized through 2022. Below is a table which summarizes the equity compensation expense for the periods noted. Year Ended December 31, 2019 2018 2017 Total cost of equity compensation plans $ 3,077 $ 15,639 $ 53,952 Amounts capitalized in oil and gas properties and equipment $ 506 $ 3,814 $ 13,975 Amounts charged against income, before income tax benefit $ 2,571 $ 11,825 $ 39,977 Amount of related income tax benefit recognized in income before valuation allowances $ 540 $ 2,483 $ 15,927

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
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, deferred premium puts 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. Under the Credit Agreement, the Company was subject to minimum hedging requirements through March 31, 2020, as described in Note 6. Beginning April 1, 2020, the Company is no longer be subject to a minimum hedging requirement. Fair Value of Commodity Derivatives: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC 815”). The Company does not apply hedge accounting to any of its derivative instruments. Instead, in accordance with ASC 815 the derivative contracts are recorded at fair value as derivative assets and liabilities on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense on the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. 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, 2019, 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. For deferred premium puts, the Company pays the deferred premium in the month of settlement. To the extent the market price is below the put price, the counterparty owes the Company the difference between the market price and put price in the period of settlement. The reference prices of these commodity derivative contracts are typically referenced to index prices published by independent third parties. Refer to Note 9 for more information regarding the fair value of the Company’s derivative instruments. Type Index Total Volumes (in millions) Weighted Average Price Per Unit Fair Value - December 31, 2019 Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2020 NYMEX-Henry Hub 23.7 $ 2.76 $ 14,012 Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2020 NW Rockies Basis Swap 29.9 $ (0.06 ) $ (16,122 ) Crude oil fixed price swaps (Bbl) ($/Bbl) 2020 NYMEX-WTI 0.5 $ 60.14 $ 262 Type Index Total Volumes (in millions) Weighted Average Floor Price Weighted Average Ceiling Price Fair Value - December 31, 2019 Asset (Liability) Natural gas collars ($/MMBTU) 2020 NYMEX 60.7 $ 2.41 $ 2.88 $ 11,870 2021 NYMEX 7.2 $ 2.46 $ 3.05 $ 43 Natural gas put options (2) ($/MMBTU) 2020 NYMEX 13.4 $ 2.42 N/A $ 1,386 (1) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period. (2) The Natural gas deferred premium put options include an average deferred premium of $0.13. Subsequent to December 31, 2019 through April 10, 2020, the Company entered into the following commodity derivative contracts to manage commodity price risk: Type Index Total Volumes Weighted Average Price Per Unit Oil swaps (Bbl) ($/Bbl) 2020 NYMEX WTI 27,300 $ 60.55 Additionally, the Company terminated approximately $1.3 million of commodity derivative contracts subsequent to December 31, 2019 and through April 10, 2020. 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, 2019, 2018 and 2017: For the Year Ended December 31, Commodity Derivatives: 2019 2018 2017 Realized gain (loss) on commodity derivatives-natural gas (1) $ (62,573 ) $ (77,031 ) $ 11,446 Realized gain (loss) on commodity derivatives-crude oil(1) 3,694 (8,382 ) — Unrealized gain (loss) on commodity derivatives (1) 54,282 (59,799 ) 16,966 Total gain (loss) on commodity derivatives $ (4,597 ) $ (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, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	9 . As required by FASB ASC Topic 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 $ — $ 32,100 $ — $ 32,100 Long-term derivative asset (1) — 1,516 — 1,516 Total derivative instruments $ — $ 33,616 $ — $ 33,616 Liabilities: Current derivative liability $ — $ 20,692 $ — $ 20,692 Long-term derivative liability (2) — 1,473 — 1,473 Total derivative instruments $ — $ 22,165 $ — $ 22,165 (1) Included in Other assets in the Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Consolidated Balance Sheet. The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk. Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract. In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties. In addition, each of our current counterparties are lenders under our Credit Agreement. We believe that all of our counterparties are of substantial credit quality. Other than as provided in our Credit Agreement, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of December 31, 2019, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts. Refer to Note 8 for additional details about our derivative financial instruments. 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, 2019 2018 Principal Estimated Fair Value Principal Estimated Fair Value Credit Agreement, secured $ 64,700 $ 64,700 $ 104,000 $ 104,000 Term Loan, secured due 2024 968,756 566,723 975,000 858,000 Second Lien Notes, secured due 2024 583,853 86,994 545,000 395,125 6.875% Senior, unsecured Notes, due 2022 150,439 18,805 195,035 68,262 7.125% Senior, unsecured Notes, due 2025 225,000 15,750 225,000 69,750 Total debt $ 1,992,748 $ 752,972 $ 2,044,035 $ 1,495,137

Other Current Assets

Other Current Assets	12 Months Ended
	Dec. 31, 2019
Other Current Assets [Abstract]
Other Current Assets	10. The following table summarizes the major components of Other current assets included on the consolidated balance sheet: December 31, December 31, 2019 2018 Deposits and retainers $ 651 $ 651 Prepaids and others 1,087 1,822 Crude oil 1,032 1,113 Pipe and production equipment 7,976 17,644 Total Other current assets $ 10,746 $ 21,230 During the year ended December 31, 2019, the Company recorded a write-down of pipe and production inventory to the lower of cost or net realizable value. 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. Accordingly, the Company recorded a write-down of pipe and production equipment for $7.5 million. The expense is reported as Other operating expenses on the consolidated statement of operations. The pipe and production equipment and crude oil inventory has been reclassified to Other current assets as of December 31, 2019 and 2018.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	1 1 . Income before income tax benefit is as follows: Year Ended December 31, 2019 2018 2017 United States $ 108,575 $ 86,242 $ (197,136 ) Foreign (1,637 ) (593 ) 360,982 Total $ 106,938 $ 85,649 $ 163,846 The consolidated income tax provision (benefit) is comprised of the following: Year Ended December 31, 2019 2018 2017 Current tax: U.S. federal, state and local $ (1,050 ) $ 433 $ (13,296 ) Foreign — 9 2 Total current tax provision (benefit) (1,050 ) 442 (13,294 ) Deferred tax: Foreign — — — Total deferred tax expense — — — Total income tax provision (benefit) $ (1,050 ) $ 442 $ (13,294 ) 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, 2019 2018 2017 Income tax provision computed at the U.S. statutory rate $ 22,457 $ 17,986 $ 57,346 State income tax (benefit) provision net of federal effect — — (25,519 ) Valuation allowance (31,733 ) (30,723 ) (562,491 ) Tax effect of rate change — — 463,113 Sale of non-core assets — 5,863 130,552 Foreign rate differential (98 ) (36 ) (3,150 ) Reorganization items 220 216 (89,327 ) Equity compensation 1,747 2,689 10,778 Disallowed interest 5,799 700 — Other, net 558 3,747 5,404 Total income tax provision (benefit) $ (1,050 ) $ 442 $ (13,294 ) 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, 2019 2018 Deferred tax assets: Property and equipment $ — $ 33,953 Deferred gain — 19,874 U.S. federal tax credit carryforwards 512 512 U.S. interest carryforwards 27,949 5,931 U.S. net operating loss carryforwards 480,673 462,401 Non-U.S. net operating loss carryforwards 8,868 7,048 Asset retirement obligations 40,780 37,687 Derivative instruments, net — 8,995 Debt financing 81,394 92,706 Incentive compensation 2,956 5,370 Lease liabilities 25,452 — Other, net 3,143 2,148 Total deferred tax assets, gross 671,727 676,625 Valuation allowance (625,400 ) (676,625 ) Net deferred tax assets $ 46,327 $ — Deferred tax liabilities: Derivative instruments, net $ 2,404 $ — Property and equipment 18,828 — Right-of-use assets 25,095 — Net tax liabilities $ 46,327 $ — 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, 2019 and 2018, the Company recorded a valuation allowance against certain deferred tax assets of $625.4 million and $676.6 million, 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 $2.3 billion as of December 31, 2019, which may be carried forward to offset taxable income generated in future years and, as a result of the CARES Act, may be carried back to any of the five years preceding the taxable year in which the net operating loss was generated to the extent generated in 2018, 2019 or 2020. If the net operating loss carryforwards and carrybacks are unutilized, they 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, if generated in taxable years beginning after 2020, 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, 2019. 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 2016 through 2019 remain open to examination by the major taxing jurisdictions in which the Company has business activity. The Company is under audit in Canada for tax years 2015, 2016, and 2017. 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. Further guidance and clarifications continue to be issued regarding the regulations and provisions of the Tax Act. The Company will continue to monitor these new regulations and analyze their applicability and impact on the Company. On March 27, 2020, President Trump signed into U.S. federal law the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, under the CARES Act, (i) for taxable years beginning before 2021, net operating loss carryforwards and carrybacks may offset 100% of taxable income, (ii) NOLs arising in 2018 2019, and 2020 taxable years may be carried back to each of the preceding five years to generate a refund and (iii) for taxable years beginning in 2019 and 2020, the base for interest deductibility is increased from 30% to 50% of EBITDA. We are analyzing the different aspects of the CARES Act to determine whether any specific provisions may impact us.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	1 2 . LEASES The Company adopted ASU 2016-02, Leases (Topic 842), and all applicable amendments as of January 1, 2019. The Company elected to apply the new standard to all leases existing at the date of initial application. Consequently, historical financial information will not be updated, and the disclosures required under the new standard will be provided only for periods beginning January 1, 2019. The Company determines if an arrangement is a lease at inception. Operating leases are included in long-term right-of-use (“ROU”) assets, and long-term lease liabilities on our consolidated balance sheets. ROU assets represent the Company’s right to use of an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives. The Company’s lease terms may include options to extend or terminate the lease when the Company is reasonably certain that it will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The ROU assets are evaluated for impairment in accordance with ASC 360. The Company has lease agreements with lease and non-lease components, which are accounted for as a single lease component under the practical expedient provisions of the standard. Additionally, for certain leases, the Company applies a portfolio approach to effectively account for the operating lease ROU assets and liabilities. The portfolio approach was used to assess and determine the incremental borrowing rate with information available at adoption date. The Company has lease agreements with terms less than one year. For the qualifying short-term leases, the Company elected the short-term lease recognition exemption in which the Company will not recognize ROU assets or lease liabilities, including the ROU assets or lease liabilities for existing short-term leases of those assets in upon adoption. As of the adoption date, the Company had existing lease agreements with easements in which the Company elected the practical expedient. All new and modified lease agreements with easements completed after the adoption date will be evaluated under the ASC 842. The Company has operating leases for corporate offices, a liquids gathering system, and certain equipment. The leases have remaining lease terms of one year to nine years. The Company does not include renewal options in the lease term for calculating the lease liability unless it is reasonably certain that it will exercise the option, or the lessor has the sole ability to exercise the option. The following table summarizes the components of lease cost: For the Year Ended December 31, 2019 (In thousands) Operating lease cost $ 20,919 Variable lease cost (1) $ 6,654 Short-term lease cost (2) $ 15,333 Total lease cost (3) $ 42,906 (1) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding lease liability for agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain agreements, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes under long-term agreements. (2) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling activities, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs the Company is operating under short-term agreements. Additionally, this balance includes approximately $2.0 million of rig demobilization costs and early termination costs. Drilling contracts that were on a month-to-month basis are excluded from this amount. (3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset. The following table provides supplemental balance sheet information related to the Company’s operating leases: For the Year Ended December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 20,889 The following table provides supplemental cash flow information related to the Company’s operating leases: December 31, 2019 (In thousands) Operating Leases Operating lease right-of-use assets $ 119,496 Operating lease liabilities $ 11,938 Long-term operating lease liabilities 107,587 Total operating lease liabilities $ 119,525 Weighted Average Remaining Lease Term Operating leases 7.85 years Weighted Average Discount Rate Operating leases 7.91 % The following table summarizes the fixed, future minimum rental payments, excluding variable costs, which are discounted by the Company’s incremental borrowing rates to calculate the lease liabilities for the Company’s operating leases: Operating Leases (In thousands) For the year ending December 31, 2020 20,853 2021 20,750 2022 20,326 2023 19,719 2024 19,719 Thereafter 58,520 Total lease payments $ 159,887 Less: imputed interest (40,362 ) Total $ 119,525

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2019
Compensation And Retirement Disclosure [Abstract]
Employee Benefits	1 3 . EMPLOYEE BENEFITS: The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code (“IRC”) for its employees. Employees may defer 100% of their compensation, subject to limitations established under the IRC. 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, $2.5 million and $2.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	14 . COMMITMENTS AND CONTINGENCIES: 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. Transportation Contract During our chapter 11 proceedings, REX filed a claim against us for $303.3 million for breach of contract. As previously disclosed, on January 12, 2017, we agreed to settle their claim and paid the settlement amounts of $150.0 million during the year ended December 31, 2017. In connection with the settlement of REX’s proof of claim, the Company agreed to enter into a new transportation agreement pursuant to which the Company has committed to firm transportation capacity of 200,000 Dekatherms per day at a rate of approximately $0.37 per Dekatherm on the Rockies Express Pipeline, commencing on December 1, 2019 and extending for a term expiring December 31, 2026. This agreement provides the Company with the opportunity to transport a portion of its natural gas production away from its properties in Wyoming to capture improved basis differentials available at sales points along the Rockies Express Pipeline, if any. The Company has demonstrated its ability to mitigate this cost with capacity releases through March 31, 2020, and will continue to seek alternatives to reduce exposure to this commitment and potentially enhance the realized value of the natural gas for which it markets. 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 post-petition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we have 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 post-petition 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 post-petition 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 post-petition 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 2018 and 2019, 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 various Settlement Agreements, the Claimants have collectively paid approximately $29.9 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. The holders of these claims subsequently filed a petition for rehearing en banc and on November 26, 2019, the Appellate Court, following an en banc review, issued a new opinion that replaced the original opinion from January 17, 2019 (the “En Banc Opinion”). The En Banc Opinion affirmed the primary holding of the Appellate Court’s original opinion and vacated the order of the Bankruptcy Court denying the Company’s objection to the asserted make-whole and post-petition interest claims and remanded the matter and those determinations to the Bankruptcy Court for further reconsideration. As of the date of this filing, the matter is now in the Bankruptcy Court for rehearing. As of December 31, 2019, there is approximately $240 million of claims outstanding Other Claims We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in the Pinedale field. At this time, no determination of the outcome of these claims can be made, and we cannot reasonably estimate the potential impact of these claims. We are defending these cases vigorously, and we expect these claims to be resolved in our chapter 11 proceedings. In addition, we are currently involved in various routine disputes and allegations incidental to our business operations. While it is not possible to determine the ultimate disposition of these matters, we believe the Company has adequately reserved for such items where it has been determined that a liability is probable and is reasonably estimable. Additionally, we believe that resolution of all such additional pending or threatened litigation is not likely to have a material adverse effect on our financial position, results of operations, or cash flows.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2019
Risks And Uncertainties [Abstract]
Concentration of Credit Risk	1 5 . 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, 2019. A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2019, sales to Nevada Power Company and Pacific Gas and Electric accounted for 11.1% and 10.2% of our total revenue, respectively. In 2018 and 2017, the Company had no single customer that represented 10% or more of the Company’s total revenues.

2017 Chapter 11 Plan of Reorgan

2017 Chapter 11 Plan of Reorganization	12 Months Ended
	Dec. 31, 2019
Reorganizations [Abstract]
2017 Chapter 11 Plan of Reorganization	1 6 . 2017 CHAPTER 11 PLAN OF REORGANIZATION: 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 (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 post-petition 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 the following table which summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended 2017: For the Year Ended December 31, 2017 Professional fees $ (66,529 ) Gains (losses) (1) 431,107 Make-whole fees (223,838 ) Other (2) 167 Total Reorganization items, net $ 140,907 ( 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, 2019
Subsequent Events [Abstract]
Subsequent Events	1 7 . SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to December 31, 2019 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose in order to keep the financial statements from being misleading, except as otherwise disclosed herein.

Summarized Quarterly Financial

Summarized Quarterly Financial Information	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Information (Unaudited)	1 8 . SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 271,461 $ 155,406 $ 144,238 $ 170,927 $ 742,032 Operating expenses 133,433 137,677 125,819 118,030 514,959 Other income (expense), net: Interest expense (33,327 ) (32,376 ) (32,372 ) (31,323 ) (129,398 ) Gain (loss) on commodity derivatives (64,339 ) 71,654 11,938 (23,850 ) (4,597 ) Contract settlement — — 13,468 — 13,468 Other income (expense), net 285 (43 ) 60 90 392 Total other (expense) income, net (97,381 ) 39,235 (6,906 ) (55,083 ) (120,135 ) Income (loss) before income tax provision (benefit) 40,647 56,964 11,513 (2,186 ) 106,938 Income tax provision (benefit) (27 ) (141 ) — (882 ) (1,050 ) Net (loss) income $ 40,674 $ 57,105 $ 11,513 $ (1,304 ) $ 107,988 Net income (loss) per common share — basic $ 0.21 $ 0.29 $ 0.06 $ (0.01 ) $ 0.55 Net income (loss) per common share — fully diluted $ 0.21 $ 0.29 $ 0.06 $ (0.01 ) $ 0.55 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 ) Gain (loss) on commodity derivatives (6,530 ) (47,271 ) (21,804 ) (69,607 ) (145,212 ) Contract settlement, net — — (2,676 ) 15,332 12,656 Other income, 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 (benefit) provision 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

Disclosure About Oil and Gas Pr

Disclosure About Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Disclosure About Oil and Gas Producing Activities (Unaudited)	1 9 . 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 15 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, 2019, 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 period ended March 31, 2020 and the years ended December 31, 2019, 2018 and 2017 in 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 eight 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 15 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. 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 NSAI reports are included as Exhibits 99.1 and 99.2 to this annual report. 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, 2019, 2018 and 2017 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2019, 2018 and 2017. All such reserves were located in the Green River Basin in Wyoming for the year ended December 31, 2019 and 2018, and in the Green River Basin in Wyoming and the Uinta Basin in Utah for the year ended December 31, 2017. ANALYSES OF CHANGES IN PROVEN RESERVES: United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) 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 ) Production (260,406 ) (2,442 ) — Revisions 145,100 1,256 — Reserves, December 31, 2018 2,921,833 23,445 — Extensions, discoveries and additions 13,113 114 — Production (230,120 ) (1,684 ) — Revisions (802,226 ) (7,248 ) — Reserves, December 31, 2019 1,902,600 14,627 — United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Proved: 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 — Developed 1,902,600 14,627 — Undeveloped — — — Total Proved — 2019 1,902,600 14,627 — Changes in proved developed reserves : During 2019, substantially all of the changes were attributable to wells drilled in 2019. Changes in proved undeveloped reserves : The Company’s year-end development plans 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. Factors such as commodity price, service costs, performance data, and asset mix are subject to change; therefore, 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. Commodity prices have fluctuated 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, 2019, 2018 and 2017 was $2.44, $2.59 and $2.59 per Mcf, respectively, for natural gas, and $55.36, $63.49 and $48.05 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, 2019 2018 2017 Future cash inflows $ 5,538,104 $ 9,195,725 $ 8,965,949 Future production costs (2,277,881 ) (3,337,779 ) (3,587,581 ) Future development costs (355,830 ) (1,133,103 ) (1,001,024 ) Future income taxes — (180,057 ) — Future net cash flows 2,904,393 4,544,786 4,377,344 Discount at 10% (1,193,774 ) (2,139,303 ) (1,993,016 ) Standardized measure of discounted future net cash flows $ 1,710,619 $ 2,405,483 $ 2,384,328 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, 2019 2018 2017 Standardized measure, beginning $ 2,405,483 $ 2,384,328 $ 1,690,946 Net revisions of previous quantity estimates (713,236 ) 160,405 840,505 Extensions, discoveries and other changes 16,493 90,609 53,549 Sales of reserves in place — (34,768 ) (83,887 ) Acquisition of reserves — — 21,903 Changes in future development costs 106,464 (235,205 ) (329,635 ) Sales of oil and gas, net of production costs (486,740 ) (593,134 ) (589,621 ) Net change in prices and production costs (369,917 ) 362,084 572,224 Development costs incurred during the period that reduce future development costs 147,042 251,621 8,007 Accretion of discount 243,536 238,433 169,095 Net changes in production rates and other 331,621 (189,017 ) 31,242 Net change in income taxes 29,873 (29,873 ) — Aggregate changes (694,864 ) 21,155 693,382 Standardized measure, ending $ 1,710,619 $ 2,405,483 $ 2,384,328 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, 2019 2018 2017 United States Property Acquisitions: Unproved $ 817 $ 1,468 $ 1,399 Proved 73 1,090 9,147 Exploration* 33,509 156,718 510,710 Development 206,339 266,905 35,934 Total $ 240,738 $ 426,181 $ 557,190 * 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, 2019 2018 2017 United States Oil and gas revenue $ 742,032 $ 892,499 $ 891,873 Production expenses (255,292 ) (299,365 ) (292,095 ) Depletion and depreciation (204,227 ) (204,255 ) (161,945 ) Income tax benefit (expense) 8 (2 ) (168,355 ) Total $ 282,521 $ 388,877 $ 269,478 CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,820,392 $ 11,577,281 Less: accumulated depletion, depreciation and amortization (10,267,973 ) (10,079,554 ) Total Oil and gas properties, net $ 1,552,419 $ 1,497,727

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2019
Supplemental Financial Statement Information [Abstract]
Supplemental Financial Statement Information	20 . 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, 2019 2018 2017 General and administrative expense $ 1,650 $ 549 $ 428 Other income (expense): Interest expense — — (71,876 ) Income (loss) from unconsolidated affiliates 109,625 85,809 (183,840 ) Other expense 13 (44 ) 90 Reorganization items, net — — 433,196 Income before income taxes 107,988 85,216 177,142 Income tax provision (benefit) — 9 2 Net income $ 107,988 $ 85,207 $ 177,140 CONDENSED BALANCE SHEET: December 31, 2019 December 31, 2018 ASSETS Current Assets: Cash and cash equivalents $ 289 $ 570 Accounts receivable from related companies 29,939 29,939 Other current assets — — Total current assets 30,228 30,509 Other non-current assets — — Total assets $ 30,228 $ 30,509 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ — $ — Total current liabilities — 0 Advances from unconsolidated affiliates 875,043 1,079,131 Total liabilities 875,043 1,079,131 Total shareholders’ deficit (844,815 ) (1,048,622 ) Total liabilities and shareholders’ equity $ 30,228 $ 30,509 CONDENSED STATEMENT OF CASH FLOWS: Year Ended December 31, 2019 2018 2017 Net cash (used in) operating activities $ (281 ) $ (234 ) $ (2,206 ) Investing Activities: Investment in subsidiaries (180 ) (3,293 ) (588,677 ) Net cash (used in) provided by investing activities (180 ) (3,293 ) (588,677 ) Financing activities: Shares issued — 3,294 573,774 Repurchased shares/net share settlements 180 — 14,903 Net cash provided by (used in) financing activities 180 3,294 588,677 (Decrease) increase in cash during the period (281 ) (233 ) (2,206 ) Cash and cash equivalents, beginning of period 570 803 3,009 Cash and cash equivalents, end of period $ 289 $ 570 $ 803

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Going Concern	Going Concern. As a result of our significant indebtedness and extremely challenging current market conditions that have had an adverse impact on our business, and as a result of our financial condition, substantial doubt exists about our ability to continue as a going concern. A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements is expected to result in reduced borrowing capacity or an event of default, causing our debt obligations under such financing agreements (and any other indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. Accordingly, all debt balances as of December 31, 2019 have been classified as current on the consolidated balance sheet. In February and March 2020, we entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors. Negotiations and discussions with certain debtholders and their advisors are ongoing, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions. There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be. If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement an agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate proceedings under Chapter 11 of the United States Bankruptcy Code to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. In either case, such a proceeding could be commenced in the near term. The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. Under our Credit Agreement and Term Loan Agreement, we are required to deliver audited, consolidated financial statements without a going concern or like qualification or explanation. Because the audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern, we will be in default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when we deliver our financial statements to the lenders under the Credit Agreement and the Term Loan Agreement, respectively. We expect that we will be precluded from drawing additional amounts under the Credit Agreement while the default exists. There is a 30-day grace period related to this covenant in each of the Credit Agreement and the Term Loan Agreement. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement or the Term Loan Agreement before the expiration of the 30-day grace period, an event of default under each of the Credit Agreement and Term Loan Agreement would occur. If an event of default occurs, the lenders could accelerate the loans outstanding under the Credit Agreement and Term Loan Agreement. In addition, if the lenders under our Credit Agreement and Term Loan Agreement accelerate the loans outstanding thereunder, we will then also be in default under the indentures related to our Second Lien Notes and our Unsecured Notes. If we default under those indentures, the holders of the Second Lien Notes and Unsecured Notes could accelerate those notes. At this time, we do not expect to obtain a waiver of this requirement.
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 distribution of the production revenues 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. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Financial Statements: Current Presentation December 31, 2019 December 31, 2018 December 31, 2017 Cash and Cash Equivalents $ 1,664 $ 17,014 $ 16,631 Restricted Cash 1,777 2,291 1,638 Total cash, cash equivalents, and restricted cash $ 3,441 $ 19,305 $ 18,269
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 operating expenses, net on the Consolidated Statements of Operations is the provision for uncollectible accounts of $3.3 million for the period ended December 31, 2019. 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 lives.
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 (“ASC 932”). Under this method of accounting, the costs of successful and 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 the 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 of unevaluated properties 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, estimated 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 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 of the 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 subsequent 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 2019, 2018 or 2017.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“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 for additional information).
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. Income Taxes. In December 2019, the FASB issued authoritative guidance intended to simplify the accounting for income taxes (ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”). This guidance eliminates certain exceptions to the general approach to the income tax accounting model, and adds new guidance to reduce the complexity in accounting for income taxes. This guidance is effective for annual periods after December 15, 2020, including interim periods within those annual periods. We are currently evaluating the potential impact of this guidance on our financial statements.
Warrants	Warrants: On December 21, 2018, in connection with the consummation of the Exchange Transaction, the Company issued 10,919,499 new warrants of the Company each entitling the holder thereof to purchase one common share of the Company (each a “Warrant” and collectively, the “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. 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. Certain share-based awards subject to 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 market criteria are met. Additionally, certain share-based awards subject to service conditions are considered anti-dilutive if the exercise price exceeds the average market price. Lastly, 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, 2019, 2018 and 2017, the Company had 20.9 million, 14.2 million and 3.9 million, respectively, of shares not included in dilutive earnings per share because the shares would have been anti-dilutive as the exercise price was greater than the average market price of the common shares or the shares are contingently issuable shares. The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2019 2018 2017 Net income $ 107,988 $ 85,207 $ 177,140 Weighted average common shares outstanding during the period 197,651 196,964 163,824 Effect of dilutive instruments 39 577 152 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,690 197,541 163,976 Net income per common share — basic $ 0.55 $ 0.43 $ 1.08 Net income per common share — fully diluted $ 0.55 $ 0.43 $ 1.08
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 based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. We also estimate forfeitures at the time of grant and revise those estimates in subsequent periods if actual forfeitures differ from our estimates.
Fair Value Accounting	Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“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 revenue recognition.
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 capital expenditures, including 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.
New Accounting Pronouncements	New Accounting Pronouncements: From time to time, the FASB issues new accounting pronouncements. Updates to the FASB ASC are communicated through issuance of an Accounting Standards Update (“ASU”). Unless otherwise discussed, we believe that the impact of recently issued guidance, whether adopted or to be adopted in the future, is not expected to have a material impact on the consolidated financial statements upon adoption. Recently Adopted Accounting Pronouncements: Leases: In February 2016, the FASB issued ASU 2016-02, , and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. The Company adopted ASC 842 and applicable amendments on January 1, 2019, using the modified retrospective approach. The Company elected certain practical expedients and established internal controls and key system functionality to enable the preparation of financial information on adoption. The adoption of the standard had an effect on the Company’s consolidated balance sheets and consolidated statement of operations. The most significant impact was the recognition of right-of-use assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 12 for additional discussion. Cumulative Effect of Recently Adopted Accounting Pronouncements: The following table reflects the cumulative impact of the adoption of ASC 842 on January 1, 2019, using the modified retrospective approach: December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (In thousands) Long-term right-of-use assets $ — $ 130,649 $ 130,649 Total assets 1,733,288 130,649 1,863,937 Lease liabilities (current) — 11,141 11,141 Deferred gain on sale of liquids gathering system 94,636 (94,636 ) — Long-term lease liabilities — 121,326 121,326 Total liabilities 2,781,910 37,831 2,819,741 Retained earnings (loss) (3,186,016 ) 92,818 (3,093,198 ) Total shareholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and shareholders' equity (deficit) 1,733,288 130,649 1,863,937
Recent Accounting Pronouncements Not Yet Adopted	Recent Accounting Pronouncements Not Yet Adopted: Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, (Topic 820): — 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. The Company is currently assessing the impact of this standard on its disclosures. The standard is effective for the Company on January 1, 2020. Financial Instruments. In June 2016, The FASB issued ASU 2016-13, (Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This ASU changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. For small reporting companies, as defined by the SEC, ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2022. The standard is effective for the Company on January 1, 2023. The Company is currently assessing the impact of ASU 2016-13 on its consolidated financial statements. Income Taxes. In December 2019, the FASB issued authoritative guidance intended to simplify the accounting for income taxes (ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”). This guidance eliminates certain exceptions to the general approach to the income tax accounting model, and adds new guidance to reduce the complexity in accounting for income taxes. This guidance is effective for annual periods after December 15, 2020, including interim periods within those annual periods. We are currently evaluating the potential impact of this guidance on our financial statements.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 December 31, 2017 Cash and Cash Equivalents $ 1,664 $ 17,014 $ 16,631 Restricted Cash 1,777 2,291 1,638 Total cash, cash equivalents, and restricted cash $ 3,441 $ 19,305 $ 18,269
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, 2019 2018 2017 Net income $ 107,988 $ 85,207 $ 177,140 Weighted average common shares outstanding during the period 197,651 196,964 163,824 Effect of dilutive instruments 39 577 152 Weighted average common shares outstanding during the period including the effects of dilutive instruments 197,690 197,541 163,976 Net income per common share — basic $ 0.55 $ 0.43 $ 1.08 Net income per common share — fully diluted $ 0.55 $ 0.43 $ 1.08
Schedule of Cumulative Impact of Adoption of ASC 842 Using Retrospective Approach	The following table reflects the cumulative impact of the adoption of ASC 842 on January 1, 2019, using the modified retrospective approach: December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (In thousands) Long-term right-of-use assets $ — $ 130,649 $ 130,649 Total assets 1,733,288 130,649 1,863,937 Lease liabilities (current) — 11,141 11,141 Deferred gain on sale of liquids gathering system 94,636 (94,636 ) — Long-term lease liabilities — 121,326 121,326 Total liabilities 2,781,910 37,831 2,819,741 Retained earnings (loss) (3,186,016 ) 92,818 (3,093,198 ) Total shareholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and shareholders' equity (deficit) 1,733,288 130,649 1,863,937

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Asset retirement obligations at beginning of period $ 179,462 $ 173,100 Accretion expense 13,255 12,342 Liabilities incurred 1,511 3,558 Liabilities divested (1) — (9,372 ) Liabilities settled — (70 ) Revisions of estimated liabilities (40 ) (96 ) Asset retirement obligations at end of period 194,188 179,462 Less: current asset retirement obligations (193 ) (193 ) Long-term asset retirement obligations (2) $ 193,995 $ 179,269 (1) During the year ended December 31, 2018, the Company divested certain non-core properties in Utah. (2) 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, 2019
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties	December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,820,392 $ 11,577,281 Less: Accumulated depletion, depreciation and amortization (10,267,973 ) (10,079,554 ) Total Oil and gas properties, net 1,552,419 1,497,727

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property Plant And Equipment [Abstract]
Schedule of Property, Plant and Equipment	December 31, 2019 2018 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,893 (2,349 ) 544 619 Office equipment 277 (221 ) 56 65 Leasehold improvements 264 (206 ) 58 86 Land 2,437 — 2,437 2,437 Production and other equipment 20,221 (13,537 ) 6,684 8,428 Property, plant and equipment, net $ 26,092 $ (16,313 ) $ 9,779 $ 11,635

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Summary of Debt Instruments	December 31, 2019 Principal (1) Unamortized Deferred Financing Costs and Discounts (2) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement, secured, due January 2022 $ 64,700 $ — $ — $ 64,700 Term Loan, secured, due April 2024 968,756 (22,498 ) — 946,258 Second Lien Notes, secured, due July 2024 583,853 — 203,883 787,736 6.875% Unsecured Notes due April 2022 150,439 (11,146 ) — 139,293 7.125% Unsecured Notes due April 2025 225,000 (12,777 ) — 212,223 Total $ 1,992,748 $ (46,421 ) $ 203,883 $ 2,150,210 (1) Includes PIK interest on the Term Loan and Second Lien Notes of $1.1 million and $11.8 million, respectively. (2) 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. December 31, 2018 Principal Unamortized Deferred Financing Costs and Discounts (1) Unamortized Premium on Exchange Transaction Carrying Value Credit Agreement, secured, due January 2022 $ 104,000 $ — $ — $ 104,000 Term Loan, secured, due April 2024 975,000 (26,874 ) — 948,126 Second Lien Notes, secured, due July 2024 545,000 — 228,096 773,096 6.875% Unsecured Notes due April 2022 195,035 (15,168 ) — 179,867 7.125% Unsecured Notes due April 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 (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, 2020 (1) $ 1,992,748 2021 $ — 2022 ( 2 ) $ — 2023 $ — 2024 $ — Beyond 5 years $ — Total $ 1,992,748 (1) As previously noted, the audit report prepared by the Company’s independent registered public accounting firm includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern. This is a default under each of the Credit Agreement and Term Loan Agreement on April 14, 2020 when we deliver our financial statements to the lenders under the Credit Agreement. As a result, we have reclassified our total outstanding debt as short-term as of December 31, 2019. (2) In connection with the Exchange Transaction, the Company entered into the Term Loan Amendment, which among other things, included a prohibition on repurchasing more than $50 million of the 6.875% Unsecured Notes due 2022 or the 7.125% Unsecured Notes due 2025 at their respective maturity dates or within one year thereof.

Equity Compensation (Tables)

Equity Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Securities Authorized for Issuance Under Equity Compensation Plans	As of December 31, 2019, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved equity 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 12,588 Equity compensation plans not approved by security holders n/a Total 12,588
Schedule of Activity of Non-vested PSUs	The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. A summary of the status and activity of non-vested PSUs is presented in the following table: Year Ended December 31, 2019 2018 2017 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 3,128,575 3,874,278 — Granted 5,310,251 $ 0.30 2,524,719 $ 0.62 4,214,902 $ 11.87 Vested — $ — (1,769,734 ) $ 11.87 — $ — Forfeited (1,950,658 ) $ 0.41 (329,156 ) $ 11.87 (214,408 ) $ 11.87 Cancelled — $ — — $ — (126,216 ) $ 11.87 Cancelled - MIP Exchanges (581,677 ) $ 11.87 (1,171,532 ) $ 11.87 — $ — Non-vested at end of year 5,906,491 3,128,575 3,874,278
Schedule of Performance Share Units Settled in Entity Own Stock Equity	During the years ended December 31, 2019 and 2017, there were no common stock issued to settle PSUs. Presented below is a summary of the shares of common stock issued to settle PSUs for the year ended December 31, 2018: Year Ended December 31, 2018 Shares of common stock issued to settle PSUs (1) 1,769,734 Less: shares of common stock withheld for income and payroll taxes (733,174 ) Net shares of common stock issued 1,036,560 (1) During the year ended December 31, 2018, the Company issued shares of common stock to settle PSUs that related to awards granted in 2017. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
Schedule of Status and Activity of Non-vested RSUs	A summary of the status and activity of non-vested RSUs granted to eligible persons is presented in the following table: Year Ended December 31, 2019 2018 2017 RSUs Weighted-Average Grant-Date Fair Value RSUs Weighted-Average Grant-Date Fair Value RSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 2,734,709 73,048 — Granted 2,677,593 $ 0.64 1,650,983 $ 1.89 2,269,199 $ 13.59 Vested (1,042,515 ) $ 4.59 — $ — (2,191,297 ) $ 14.07 Forfeited (704,916 ) $ 6.41 (160,854 ) $ 3.00 (4,854 ) $ 10.31 Granted - MIP Exchanges 581,677 $ 0.70 1,171,532 $ 1.77 — $ — Non-vested at end of year 4,246,548 2,734,709 73,048
Schedule of Restricted Share Units Settled in Entity Own Stock Equity	A summary of the shares of common stock issued to settle RSUs is presented in the table below: Year Ended December 31, 2019 2018 2017 Shares of common stock issued to settle RSUs (1) 715,809 — 2,191,297 Less: shares of common stock withheld for income and payroll taxes (210,631 ) — (837,282 ) Net shares of common stock issued 505,178 — 1,354,015 (1) During the year ended December 31, 2019 and 2017, the Company issued shares of common stock to settle RSUs that related to awards granted in 2017, 2018 and 2019. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
Valuation and Expense Information	Below is a table which summarizes the equity compensation expense for the periods noted. Year Ended December 31, 2019 2018 2017 Total cost of equity compensation plans $ 3,077 $ 15,639 $ 53,952 Amounts capitalized in oil and gas properties and equipment $ 506 $ 3,814 $ 13,975 Amounts charged against income, before income tax benefit $ 2,571 $ 11,825 $ 39,977 Amount of related income tax benefit recognized in income before valuation allowances $ 540 $ 2,483 $ 15,927

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	At December 31, 2019, 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, 2019 Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2020 NYMEX-Henry Hub 23.7 $ 2.76 $ 14,012 Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2020 NW Rockies Basis Swap 29.9 $ (0.06 ) $ (16,122 ) Crude oil fixed price swaps (Bbl) ($/Bbl) 2020 NYMEX-WTI 0.5 $ 60.14 $ 262 Type Index Total Volumes (in millions) Weighted Average Floor Price Weighted Average Ceiling Price Fair Value - December 31, 2019 Asset (Liability) Natural gas collars ($/MMBTU) 2020 NYMEX 60.7 $ 2.41 $ 2.88 $ 11,870 2021 NYMEX 7.2 $ 2.46 $ 3.05 $ 43 Natural gas put options (2) ($/MMBTU) 2020 NYMEX 13.4 $ 2.42 N/A $ 1,386 (1) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period. (2) The Natural gas deferred premium put options include an average deferred premium of $0.13. Subsequent to December 31, 2019 through April 10, 2020, the Company entered into the following commodity derivative contracts to manage commodity price risk: Type Index Total Volumes Weighted Average Price Per Unit Oil swaps (Bbl) ($/Bbl) 2020 NYMEX WTI 27,300 $ 60.55
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, 2019, 2018 and 2017: For the Year Ended December 31, Commodity Derivatives: 2019 2018 2017 Realized gain (loss) on commodity derivatives-natural gas (1) $ (62,573 ) $ (77,031 ) $ 11,446 Realized gain (loss) on commodity derivatives-crude oil(1) 3,694 (8,382 ) — Unrealized gain (loss) on commodity derivatives (1) 54,282 (59,799 ) 16,966 Total gain (loss) on commodity derivatives $ (4,597 ) $ (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, 2019
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 32,100 $ — $ 32,100 Long-term derivative asset (1) — 1,516 — 1,516 Total derivative instruments $ — $ 33,616 $ — $ 33,616 Liabilities: Current derivative liability $ — $ 20,692 $ — $ 20,692 Long-term derivative liability (2) — 1,473 — 1,473 Total derivative instruments $ — $ 22,165 $ — $ 22,165 (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, 2019 2018 Principal Estimated Fair Value Principal Estimated Fair Value Credit Agreement, secured $ 64,700 $ 64,700 $ 104,000 $ 104,000 Term Loan, secured due 2024 968,756 566,723 975,000 858,000 Second Lien Notes, secured due 2024 583,853 86,994 545,000 395,125 6.875% Senior, unsecured Notes, due 2022 150,439 18,805 195,035 68,262 7.125% Senior, unsecured Notes, due 2025 225,000 15,750 225,000 69,750 Total debt $ 1,992,748 $ 752,972 $ 2,044,035 $ 1,495,137

Other Current Assets (Tables)

Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Other Current Assets [Abstract]
Schedule of Other Current Assets	The following table summarizes the major components of Other current assets included on the consolidated balance sheet: December 31, December 31, 2019 2018 Deposits and retainers $ 651 $ 651 Prepaids and others 1,087 1,822 Crude oil 1,032 1,113 Pipe and production equipment 7,976 17,644 Total Other current assets $ 10,746 $ 21,230

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Summary of Income Before Income Tax Benefit	Income before income tax benefit is as follows: Year Ended December 31, 2019 2018 2017 United States $ 108,575 $ 86,242 $ (197,136 ) Foreign (1,637 ) (593 ) 360,982 Total $ 106,938 $ 85,649 $ 163,846
Summary of Consolidated Income Tax Provision (Benefit)	The consolidated income tax provision (benefit) is comprised of the following: Year Ended December 31, 2019 2018 2017 Current tax: U.S. federal, state and local $ (1,050 ) $ 433 $ (13,296 ) Foreign — 9 2 Total current tax provision (benefit) (1,050 ) 442 (13,294 ) Deferred tax: Foreign — — — Total deferred tax expense — — — Total income tax provision (benefit) $ (1,050 ) $ 442 $ (13,294 )
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, 2019 2018 2017 Income tax provision computed at the U.S. statutory rate $ 22,457 $ 17,986 $ 57,346 State income tax (benefit) provision net of federal effect — — (25,519 ) Valuation allowance (31,733 ) (30,723 ) (562,491 ) Tax effect of rate change — — 463,113 Sale of non-core assets — 5,863 130,552 Foreign rate differential (98 ) (36 ) (3,150 ) Reorganization items 220 216 (89,327 ) Equity compensation 1,747 2,689 10,778 Disallowed interest 5,799 700 — Other, net 558 3,747 5,404 Total income tax provision (benefit) $ (1,050 ) $ 442 $ (13,294 )
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, 2019 2018 Deferred tax assets: Property and equipment $ — $ 33,953 Deferred gain — 19,874 U.S. federal tax credit carryforwards 512 512 U.S. interest carryforwards 27,949 5,931 U.S. net operating loss carryforwards 480,673 462,401 Non-U.S. net operating loss carryforwards 8,868 7,048 Asset retirement obligations 40,780 37,687 Derivative instruments, net — 8,995 Debt financing 81,394 92,706 Incentive compensation 2,956 5,370 Lease liabilities 25,452 — Other, net 3,143 2,148 Total deferred tax assets, gross 671,727 676,625 Valuation allowance (625,400 ) (676,625 ) Net deferred tax assets $ 46,327 $ — Deferred tax liabilities: Derivative instruments, net $ 2,404 $ — Property and equipment 18,828 — Right-of-use assets 25,095 — Net tax liabilities $ 46,327 $ — Net tax asset $ — $ —

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Components of Lease Cost	The following table summarizes the components of lease cost: For the Year Ended December 31, 2019 (In thousands) Operating lease cost $ 20,919 Variable lease cost (1) $ 6,654 Short-term lease cost (2) $ 15,333 Total lease cost (3) $ 42,906 (1) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding lease liability for agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain agreements, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes under long-term agreements. (2) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling activities, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs the Company is operating under short-term agreements. Additionally, this balance includes approximately $2.0 million of rig demobilization costs and early termination costs. Drilling contracts that were on a month-to-month basis are excluded from this amount. (3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.
Supplemental Balance Sheet Information Related to Operating Leases	The following table provides supplemental balance sheet information related to the Company’s operating leases: For the Year Ended December 31, 2019 (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 20,889
Supplemental Cash Flow Information Related to Operating Leases	The following table provides supplemental cash flow information related to the Company’s operating leases: December 31, 2019 (In thousands) Operating Leases Operating lease right-of-use assets $ 119,496 Operating lease liabilities $ 11,938 Long-term operating lease liabilities 107,587 Total operating lease liabilities $ 119,525 Weighted Average Remaining Lease Term Operating leases 7.85 years Weighted Average Discount Rate Operating leases 7.91 %
Summary of Fixed, Future Minimum Rental Payments Excluding Variable Costs, for Operating Lease Liabilities	The following table summarizes the fixed, future minimum rental payments, excluding variable costs, which are discounted by the Company’s incremental borrowing rates to calculate the lease liabilities for the Company’s operating leases: Operating Leases (In thousands) For the year ending December 31, 2020 20,853 2021 20,750 2022 20,326 2023 19,719 2024 19,719 Thereafter 58,520 Total lease payments $ 159,887 Less: imputed interest (40,362 ) Total $ 119,525

2017 Chapter 11 Plan of Reorg_2

2017 Chapter 11 Plan of Reorganization (Tables)	12 Months Ended
	Dec. 31, 2019
Reorganizations [Abstract]
Schedule of Reorganization Items	the following table which summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended 2017: For the Year Ended December 31, 2017 Professional fees $ (66,529 ) Gains (losses) (1) 431,107 Make-whole fees (223,838 ) Other (2) 167 Total Reorganization items, net $ 140,907 ( 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, 2019
Quarterly Financial Information Disclosure [Abstract]
Summary of Quarterly Financial Information	2019 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 271,461 $ 155,406 $ 144,238 $ 170,927 $ 742,032 Operating expenses 133,433 137,677 125,819 118,030 514,959 Other income (expense), net: Interest expense (33,327 ) (32,376 ) (32,372 ) (31,323 ) (129,398 ) Gain (loss) on commodity derivatives (64,339 ) 71,654 11,938 (23,850 ) (4,597 ) Contract settlement — — 13,468 — 13,468 Other income (expense), net 285 (43 ) 60 90 392 Total other (expense) income, net (97,381 ) 39,235 (6,906 ) (55,083 ) (120,135 ) Income (loss) before income tax provision (benefit) 40,647 56,964 11,513 (2,186 ) 106,938 Income tax provision (benefit) (27 ) (141 ) — (882 ) (1,050 ) Net (loss) income $ 40,674 $ 57,105 $ 11,513 $ (1,304 ) $ 107,988 Net income (loss) per common share — basic $ 0.21 $ 0.29 $ 0.06 $ (0.01 ) $ 0.55 Net income (loss) per common share — fully diluted $ 0.21 $ 0.29 $ 0.06 $ (0.01 ) $ 0.55 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 ) Gain (loss) on commodity derivatives (6,530 ) (47,271 ) (21,804 ) (69,607 ) (145,212 ) Contract settlement, net — — (2,676 ) 15,332 12,656 Other income, 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 (benefit) provision 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

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Analyses of Changes in Proven Reserves	The unaudited reserve estimates as of March 31, 2020 are as follow: Natural Gas (MMcf) Oil (MBbls) Natural Gas Equivalents (MMcfe) Developed 1,694,828 11,902 1,766,239 Undeveloped — — — Total Proved as of March 31, 2020 1,694,828 11,902 1,766,239 United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) 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 ) Production (260,406 ) (2,442 ) — Revisions 145,100 1,256 — Reserves, December 31, 2018 2,921,833 23,445 — Extensions, discoveries and additions 13,113 114 — Production (230,120 ) (1,684 ) — Revisions (802,226 ) (7,248 ) — Reserves, December 31, 2019 1,902,600 14,627 — United States Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) Proved: 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 — Developed 1,902,600 14,627 — Undeveloped — — — Total Proved — 2019 1,902,600 14,627 —
Standardized Measure	As of December 31, 2019 2018 2017 Future cash inflows $ 5,538,104 $ 9,195,725 $ 8,965,949 Future production costs (2,277,881 ) (3,337,779 ) (3,587,581 ) Future development costs (355,830 ) (1,133,103 ) (1,001,024 ) Future income taxes — (180,057 ) — Future net cash flows 2,904,393 4,544,786 4,377,344 Discount at 10% (1,193,774 ) (2,139,303 ) (1,993,016 ) Standardized measure of discounted future net cash flows $ 1,710,619 $ 2,405,483 $ 2,384,328
Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows	December 31, 2019 2018 2017 Standardized measure, beginning $ 2,405,483 $ 2,384,328 $ 1,690,946 Net revisions of previous quantity estimates (713,236 ) 160,405 840,505 Extensions, discoveries and other changes 16,493 90,609 53,549 Sales of reserves in place — (34,768 ) (83,887 ) Acquisition of reserves — — 21,903 Changes in future development costs 106,464 (235,205 ) (329,635 ) Sales of oil and gas, net of production costs (486,740 ) (593,134 ) (589,621 ) Net change in prices and production costs (369,917 ) 362,084 572,224 Development costs incurred during the period that reduce future development costs 147,042 251,621 8,007 Accretion of discount 243,536 238,433 169,095 Net changes in production rates and other 331,621 (189,017 ) 31,242 Net change in income taxes 29,873 (29,873 ) — Aggregate changes (694,864 ) 21,155 693,382 Standardized measure, ending $ 1,710,619 $ 2,405,483 $ 2,384,328
Costs Incurred in Oil and Gas Exploration and Development Activities	Years Ended December 31, 2019 2018 2017 United States Property Acquisitions: Unproved $ 817 $ 1,468 $ 1,399 Proved 73 1,090 9,147 Exploration* 33,509 156,718 510,710 Development 206,339 266,905 35,934 Total $ 240,738 $ 426,181 $ 557,190 * 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, 2019 2018 2017 United States Oil and gas revenue $ 742,032 $ 892,499 $ 891,873 Production expenses (255,292 ) (299,365 ) (292,095 ) Depletion and depreciation (204,227 ) (204,255 ) (161,945 ) Income tax benefit (expense) 8 (2 ) (168,355 ) Total $ 282,521 $ 388,877 $ 269,478
Capitalized Costs Relating to Oil and Gas Producing Activities	CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,820,392 $ 11,577,281 Less: accumulated depletion, depreciation and amortization (10,267,973 ) (10,079,554 ) Total Oil and gas properties, net $ 1,552,419 $ 1,497,727

Supplemental Financial Statem_2

Supplemental Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2019
Parent Company Financial Statements [Abstract]
Supplemental Statement Of Operations Disclosures Parent Company	CONDENSED STATEMENT OF OPERATIONS: Year Ended December 31, 2019 2018 2017 General and administrative expense $ 1,650 $ 549 $ 428 Other income (expense): Interest expense — — (71,876 ) Income (loss) from unconsolidated affiliates 109,625 85,809 (183,840 ) Other expense 13 (44 ) 90 Reorganization items, net — — 433,196 Income before income taxes 107,988 85,216 177,142 Income tax provision (benefit) — 9 2 Net income $ 107,988 $ 85,207 $ 177,140
Supplemental Balance Sheet Disclosures Parent Company	CONDENSED BALANCE SHEET: December 31, 2019 December 31, 2018 ASSETS Current Assets: Cash and cash equivalents $ 289 $ 570 Accounts receivable from related companies 29,939 29,939 Other current assets — — Total current assets 30,228 30,509 Other non-current assets — — Total assets $ 30,228 $ 30,509 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ — $ — Total current liabilities — 0 Advances from unconsolidated affiliates 875,043 1,079,131 Total liabilities 875,043 1,079,131 Total shareholders’ deficit (844,815 ) (1,048,622 ) Total liabilities and shareholders’ equity $ 30,228 $ 30,509
Supplemental Cash Flow Statement Disclosures Parent Company	CONDENSED STATEMENT OF CASH FLOWS: Year Ended December 31, 2019 2018 2017 Net cash (used in) operating activities $ (281 ) $ (234 ) $ (2,206 ) Investing Activities: Investment in subsidiaries (180 ) (3,293 ) (588,677 ) Net cash (used in) provided by investing activities (180 ) (3,293 ) (588,677 ) Financing activities: Shares issued — 3,294 573,774 Repurchased shares/net share settlements 180 — 14,903 Net cash provided by (used in) financing activities 180 3,294 588,677 (Decrease) increase in cash during the period (281 ) (233 ) (2,206 ) Cash and cash equivalents, beginning of period 570 803 3,009 Cash and cash equivalents, end of period $ 289 $ 570 $ 803

Significant Accounting Polici_4

Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Cash Equivalents Restricted Cash And Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 1,664	$ 17,014	$ 16,631
Restricted cash	1,777	2,291	1,638
Total cash, cash equivalents, and restricted cash	$ 3,441	$ 19,305	$ 18,269	$ 405,049

Significant Accounting Polici_5

Significant Accounting Policies - Additional Information (Details) - USD ($)	Dec. 21, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Provision for uncollectible accounts			$ 3,300,000
Discount rate future net revenues			10.00%
Ceiling test limitation			$ 0	$ 0	$ 0
Common share, no par value
Contingently issuable shares			20,900,000	14,200,000	3,900,000
Ultra Resources, Inc. | Exchange Agreement
Significant Accounting Policies [Line Items]
Warrants issued on exchange	10,919,499	10,919,499
Warrant entitling to purchase common stock	1
Number of common stock issued upon exercise of each warrant	1
Initial exercise price	$ 0.01
Volume-weighted average price of the Common Shares for warrants exercise	$ 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

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share Reconciliation [Abstract]
Net income	$ (1,304)	$ 11,513	$ 57,105	$ 40,674	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 107,988	$ 85,207	$ 177,140
Weighted average common shares outstanding during the period									197,651	196,964	163,824
Effect of dilutive instruments									39	577	152
Weighted average common shares outstanding during the period including the effects of dilutive instruments									197,690	197,541	163,976
Net income per common share — basic	$ (0.01)	$ 0.06	$ 0.29	$ 0.21	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.55	$ 0.43	$ 1.08
Net income per common share — fully diluted	$ (0.01)	$ 0.06	$ 0.29	$ 0.21	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.55	$ 0.43	$ 1.08

Significant Accounting Polici_7

Significant Accounting Policies - Schedule of Cumulative Impact of Adoption of ASC 842 Using Retrospective Approach (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant Accounting Policies [Line Items]
Long-term right-of-use assets	$ 119,496
Total assets	1,815,276		$ 1,733,288
Lease liabilities (current)	11,938
Deferred gain on sale of liquids gathering system			94,636
Long-term lease liabilities	107,587
Total liabilities	2,660,090		2,781,910
Retained earnings (loss)	(2,985,285)		(3,186,016)
Total shareholders' equity (deficit)	(844,814)		(1,048,622)	$ (1,154,636)	$ (2,928,151)
Total liabilities and shareholders' equity (deficit)	$ 1,815,276		$ 1,733,288
ASC 842
Significant Accounting Policies [Line Items]
Long-term right-of-use assets		$ 130,649
Total assets		1,863,937
Lease liabilities (current)		11,141
Long-term lease liabilities		121,326
Total liabilities		2,819,741
Retained earnings (loss)		(3,093,198)
Total shareholders' equity (deficit)		(955,804)
Total liabilities and shareholders' equity (deficit)		1,863,937
ASC 842 | Impact of ASC 842
Significant Accounting Policies [Line Items]
Long-term right-of-use assets		130,649
Total assets		130,649
Lease liabilities (current)		11,141
Deferred gain on sale of liquids gathering system		(94,636)
Long-term lease liabilities		121,326
Total liabilities		37,831
Retained earnings (loss)		92,818
Total shareholders' equity (deficit)		92,818
Total liabilities and shareholders' equity (deficit)		$ 130,649

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019
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, 2019	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$ 179,462	$ 173,100
Accretion expense	13,255	12,342
Liabilities incurred	1,511	3,558
Liabilities divested		(9,372)
Liabilities settled		(70)
Revisions of estimated liabilities	(40)	(96)
Asset retirement obligations at end of period	194,188	179,462
Less: current asset retirement obligations	(193)	(193)
Long-term asset retirement obligations	$ 193,995	$ 179,269

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,820,392	$ 11,577,281
Less: Accumulated depletion, depreciation and amortization	(10,267,973)	(10,079,554)
Total Oil and gas properties, net	$ 1,552,419	$ 1,497,727

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2020$ / Mcfe	Mar. 31, 2020$ / bbl	Dec. 31, 2019$ / Mcfe	Dec. 31, 2018$ / Mcfe	Dec. 31, 2017$ / Mcfe
Results Of Operations For Oil And Gas Producing Activities By Geographic Area [Line Items]
DD&A per Mcfe				0.85	0.74	0.59
Scenario Forecast
Results Of Operations For Oil And Gas Producing Activities By Geographic Area [Line Items]
Crude oil and natural gas reserves discounted rate	10.00%
Base price of oil and gas		2.07	55.35
Scenario Forecast | Natural Gas
Results Of Operations For Oil And Gas Producing Activities By Geographic Area [Line Items]
Percentage of decrease in price of natural gas	15.00%
Scenario Forecast | Maximum | Oil Reserves
Results Of Operations For Oil And Gas Producing Activities By Geographic Area [Line Items]
Percentage of decrease in price of natural gas	1.00%

Property, Plant & Equipment - S

Property, Plant & Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Cost	$ 26,092
Accumulated Depreciation	(16,313)
Property, plant and equipment	9,779	$ 11,635
Computer Equipment
Property Plant And Equipment [Line Items]
Cost	2,893
Accumulated Depreciation	(2,349)
Property, plant and equipment	544	619
Office Equipment
Property Plant And Equipment [Line Items]
Cost	277
Accumulated Depreciation	(221)
Property, plant and equipment	56	65
Leasehold Improvements
Property Plant And Equipment [Line Items]
Cost	264
Accumulated Depreciation	(206)
Property, plant and equipment	58	86
Land
Property Plant And Equipment [Line Items]
Cost	2,437
Property, plant and equipment	2,437	2,437
Production And Other Equipment
Property Plant And Equipment [Line Items]
Cost	20,221
Accumulated Depreciation	(13,537)
Property, plant and equipment	$ 6,684	$ 8,428

Debt - Summary of Debt Instrume

Debt - Summary of Debt Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Principal	$ 1,992,748	$ 2,044,035
Unamortized Deferred Financing Costs and Discounts	(46,421)	(56,650)
Unamortized Premium on Exchange Transaction	203,883	228,096
Carrying Value	2,150,210	2,215,481
Principal, Total long-term debt, net	1,992,748	2,036,722
Less: Unamortized deferred financing costs and discount	(46,421)	(56,650)
Unamortized Premium on Exchange Transaction, Total Long-term debt	203,883	228,096
Total long-term debt, net	2,150,210	2,208,168
Principal, Current Maturities		7,313
Unamortized Deferred Financing Costs and Discounts, Current Maturities	(46,421)
Add: Premium on exchange transaction	203,883
Total current portion of long-term debt, net	2,150,210	7,313
Credit Agreement, Secured, Due January 2022
Debt Instrument [Line Items]
Principal	64,700	104,000
Carrying Value	64,700	104,000
Term Loan, Secured, Due April 2024
Debt Instrument [Line Items]
Principal	968,756	975,000
Unamortized Deferred Financing Costs and Discounts	(22,498)	(26,874)
Carrying Value	946,258	948,126
Second Lien Notes, Secured, Due July 2024
Debt Instrument [Line Items]
Principal	583,853	545,000
Unamortized Premium on Exchange Transaction	203,883	228,096
Carrying Value	787,736	773,096
6.875% Unsecured Notes Due April 2022
Debt Instrument [Line Items]
Principal	150,439	195,035
Unamortized Deferred Financing Costs and Discounts	(11,146)	(15,168)
Carrying Value	139,293	179,867
7.125% Unsecured Notes Due April 2025
Debt Instrument [Line Items]
Principal	225,000	225,000
Unamortized Deferred Financing Costs and Discounts	(12,777)	(14,608)
Carrying Value	$ 212,223	$ 210,392

Debt - Summary of Debt Instru_2

Debt - Summary of Debt Instruments (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Payable-in-kind (“PIK”) interest payable	$ 12,867	$ 377
Credit Agreement, Secured, Due January 2022
Debt Instrument [Line Items]
Maturity date	Jan. 12, 2022	Jan. 12, 2022
Term Loan, Secured, Due April 2024
Debt Instrument [Line Items]
Maturity date	Apr. 12, 2024	Apr. 12, 2024
Payable-in-kind (“PIK”) interest payable	$ 1,100
Second Lien Notes, Secured, Due July 2024
Debt Instrument [Line Items]
Maturity date	Jul. 12, 2024	Jul. 12, 2024
Payable-in-kind (“PIK”) interest payable	$ 11,800
6.875% Unsecured Notes Due April 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 April 2025
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2025	Apr. 15, 2025
Stated interest rate	7.125%	7.125%

Debt - Summary of Aggregate Mat

Debt - Summary of Aggregate Maturities of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Long Term Liabilities [Abstract]
2020 (1)	$ 1,992,748
Total	$ 1,992,748	$ 2,044,035

Debt - Summary of Aggregate M_2

Debt - Summary of Aggregate Maturities of Debt (Parenthetical) (Details) - Revolving Credit Facility $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
6.875% Unsecured Notes Due 2022 or 7.125% Unsecured Notes Due 2025 | Maximum
Line Of Credit Facility [Line Items]
Prohibitions against use of cash to repurchase debt	$ 50
6.875% Senior Notes Due 2022
Line Of Credit Facility [Line Items]
Stated interest rate	6.875%
Maturity date	Apr. 15, 2022
7.125% Senior Notes Due 2025
Line Of Credit Facility [Line Items]
Stated interest rate	7.125%
Maturity date	Apr. 15, 2025

Debt - Ultra Resources, Inc. -

Debt - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Jun. 30, 2020	Apr. 01, 2020	Mar. 31, 2020	Feb. 29, 2020	Feb. 14, 2020	Sep. 30, 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,992,748	$ 2,044,035
Principal	1,992,748	2,044,035
Credit Agreement
Debt Instrument [Line Items]
Long-term debt, gross	64,700	104,000
Principal	$ 64,700	$ 104,000
Maturity date	Jan. 12, 2022	Jan. 12, 2022
Revolving Credit Facility | 6.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Stated interest rate	6.875%
Maturity date	Apr. 15, 2022
Revolving Credit Facility | 7.125% Senior Notes Due 2025
Debt Instrument [Line Items]
Stated interest rate	7.125%
Maturity date	Apr. 15, 2025
Ultra Resources, Inc.
Debt Instrument [Line Items]
Long-term debt, gross	$ 64,700
Principal	64,700
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity	120,000
Credit facility, current borrowing capacity	120,000
Line of credit facility, maximum borrowing capacity	$ 130,300
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Scheduled Borrowing Base Redeterminations Description	July 1, 2020
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity	$ 200,000
Credit facility, current borrowing capacity	200,000
Ultra Resources, Inc. | Fifth Amendment
Debt Instrument [Line Items]
Line of credit facility, covenant, maximum capital expenditure amount expended	$ 6,800								$ 53,700
Ultra Resources, Inc. | Fifth Amendment | Scenario Forecast
Debt Instrument [Line Items]
Line of credit facility, covenant, maximum capital expenditure amount expended			$ 5,000	$ 5,000		$ 5,000
Ultra Resources, Inc. | Subsequent Event | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity							$ 100,000
Credit facility, current borrowing capacity							$ 100,000
Ultra Resources, Inc. | Subsequent Event | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base					$ 1,075,000
Ultra Resources, Inc. | Subsequent Event | Credit Agreement | Barclays Bank PLC
Debt Instrument [Line Items]
Long-term debt, gross								$ 100,000
Principal								100,000
Ultra Resources, Inc. | Revolving Credit Facility | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Commitments under the revolving credit facility description	The next scheduled borrowing base redetermination will be July 1, 2020, as noted above, and then continue on a quarterly basis thereafter. To the extent future commitments under the Credit Agreement decreases below the outstanding balance of the Revolving Credit Facility, because of a downward redetermination of the borrowing base and commitment amount, the Company would be required to enter into a mandatory repayment schedule to satisfy the deficiency. Should the lenders not support such a repayment schedule, in month liquidity for the Company could be inadequate to meet obligations on a timely basis.
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 based upon the borrowing base utilization grid. The applicable margin increases by 25 basis points in the event the Company’s consolidated net leverage ratio, as defined, exceeds 4.00 to 1.00.
Minimum required consolidated net leverage ratio, as percentage	400.00%
Maturity date	Jan. 12, 2022
Ultra Resources, Inc. | Revolving Credit Facility | Credit Agreement | Bank Of Montreal | LIBOR | Minimum
Debt Instrument [Line Items]
Variable rate	2.50%
Ultra Resources, Inc. | Revolving Credit Facility | Credit Agreement | Bank Of Montreal | LIBOR | Maximum
Debt Instrument [Line Items]
Variable rate	3.50%
Ultra Resources, Inc. | Revolving Credit Facility | Credit Agreement | Bank Of Montreal | Base Rate | Minimum
Debt Instrument [Line Items]
Variable rate	1.50%
Ultra Resources, Inc. | Revolving Credit Facility | Credit Agreement | Bank Of Montreal | Base Rate | Maximum
Debt Instrument [Line Items]
Variable rate	2.50%
Ultra Resources, Inc. | Revolving Credit Facility | 6.875% Senior Notes Due 2022
Debt Instrument [Line Items]
Stated interest rate	6.875%
Maturity date	Apr. 15, 2022
Ultra Resources, Inc. | Revolving Credit Facility | 7.125% Senior Notes Due 2025
Debt Instrument [Line Items]
Stated interest rate	7.125%
Maturity date	Apr. 15, 2025
Ultra Resources, Inc. | Revolving Credit Facility | Fifth Amendment | Bank Of Montreal
Debt Instrument [Line Items]
Net leverage ratio beginning on December 31, 2019 and ending on March 30, 2020, minimum required hedging percentage	50.00%
Line of credit facility, covenant, establishment of maximum capital expenditure	$ 10,000								$ 65,000
Ultra Resources, Inc. | Revolving Credit Facility | Fifth Amendment | Bank Of Montreal | Scenario Forecast
Debt Instrument [Line Items]
Line of credit facility, covenant, establishment of maximum capital expenditure				$ 5,000		$ 5,000
Ultra Resources, Inc. | Revolving Credit Facility | Subsequent Event | Credit Agreement
Debt Instrument [Line Items]
Anti-cash hoarding provision								$ 15,000
Ultra Resources, Inc. | Letter Of Credit
Debt Instrument [Line Items]
Long-term debt, gross	6,700
Principal	6,700
Ultra Resources, Inc. | Letter Of Credit | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Amount of commitments available for the issuance of letters of credit	$ 35,000

Debt - Ultra Resources, Inc. _2

Debt - Ultra Resources, Inc. - Term Loan - Additional Information (Details) - USD ($) $ in Thousands	Dec. 21, 2018	Jun. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Principal			$ 2,044,035	$ 1,992,748	$ 2,044,035
Payable-in-kind (“PIK”) interest payable				12,867	377
Term Loan, Secured, Due April 2024
Debt Instrument [Line Items]
Principal			$ 975,000	968,756	$ 975,000
Ultra Resources, Inc.
Debt Instrument [Line Items]
Principal				64,700
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024
Debt Instrument [Line Items]
Principal				968,800
Payable-in-kind (“PIK”) interest payable				$ 1,100
Amortization of term loan, quarterly basis		0.25%
Maturity date		Apr. 12, 2024
Mandatory prepayment trigger, on asset coverage ratio				200.00%
Debt instrument, covenant compliance				At December 31, 2019, 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 April 2024 | LIBOR
Debt Instrument [Line Items]
Variable rate				4.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024 | Base Rate
Debt Instrument [Line Items]
Variable rate				3.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024 | Exchange Agreement
Debt Instrument [Line Items]
Variable rate			1.00%
Percentage of collateral coverage			95.00%		95.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024 | Exchange Agreement | Until December 21, 2020
Debt Instrument [Line Items]
Debt instrument call protection percentage	101.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024 | Cash Notes | Exchange Agreement
Debt Instrument [Line Items]
Variable rate			0.75%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 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 April 2024 | Payment in Kind (PIK) Note | Exchange Agreement
Debt Instrument [Line Items]
Variable rate			0.25%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan, Secured, Due April 2024 | 2022 Notes | Exchange Agreement
Debt Instrument [Line Items]
Repurchase of notes			$ 50,000		$ 50,000

Debt - Ultra Resources, Inc. _3

Debt - Ultra Resources, Inc. - Second Lien Notes - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange					$ 978,230,000
Payable-in-kind (“PIK”) interest payable			$ 12,867,000	$ 377,000
Ultra Resources, Inc. | Second Lien Notes, Secured, Due July 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%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due July 2024 | Maximum
Debt Instrument [Line Items]
Redemption price percentage of aggregate principal amount			35.00%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due July 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 July 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 July 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 July 2024 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange	$ 545,000,000	$ 27,000,000	$ 583,900,000
Payable-in-kind (“PIK”) interest payable			$ 11,800
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 cash interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing in July 2019

Debt - Ultra Resources, Inc. _4

Debt - Ultra Resources, Inc. - Senior Unsecured Notes - Additional Information (Details) - USD ($)	Dec. 21, 2018	Dec. 31, 2018	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2017
Debt Instrument [Line Items]
Principal		$ 2,044,035,000		$ 1,992,748,000
Aggregate principal amount of debt issued on exchange					$ 978,230,000
Equitization of Holdco Notes					$ 978,230,000
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Principal		195,035,000		150,439,000
7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Principal		225,000,000		225,000,000
Second Lien Notes, Secured, Due July 2024
Debt Instrument [Line Items]
Principal		$ 545,000,000		583,853,000
Ultra Resources, Inc.
Debt Instrument [Line Items]
Principal				64,700,000
Ultra Resources, Inc. | Exchange Agreement
Debt Instrument [Line Items]
Warrants issued on exchange	10,919,499	10,919,499
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Principal				$ 150,400,000
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%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Principal				$ 225,000,000
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%
Ultra Resources, Inc. | Second Lien Notes, Secured, Due July 2024 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange		$ 545,000,000	$ 27,000,000	583,900,000
Equitization of Holdco Notes		$ 545,000,000	27,000,000	$ 583,900,000
Interest payment terms				The cash interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing in July 2019
Ultra Resources, Inc. | 2022 Notes | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged			$ 44,600,000

Equity Compensation - Additiona

Equity Compensation - Additional Information (Details) - USD ($) $ in Thousands	Apr. 12, 2017	Jul. 31, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				$ 2,571	$ 11,825	$ 39,977
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				2,600	$ 11,800	$ 40,000
Unrecognized compensation expense related to non-vested awards				$ 1,400
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%
Amendment and Restatement of Stock Incentive Plan 2017 | Outside Director | Performance Shares
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
Management Incentive Plan | Performance Shares
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 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.
Management Incentive Plan | Performance Shares | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds $6.0 Billion
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage	0.33%
Total enterprise value	$ 6,000,000
Management Incentive Plan | Performance Shares | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds 110% of $6.0 Billion or $6.6 Billion
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage	0.33%
Total enterprise value	$ 6,000,000
Percentage of enterprise value	110.00%
Long Term Incentive Award
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance period				3 years	3 years

Equity Compensation - Securitie

Equity Compensation - Securities Authorized for Issuance Under Equity Compensation Plans (Details)	Dec. 31, 2019shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans	12,588,000
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	12,588,000

Equity Compensation - Schedule

Equity Compensation - Schedule of Activity of Non-vested PSUs (Details) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-vested shares at beginning of year	3,128,575	3,874,278
Non-vested shares, Granted	5,310,251	2,524,719	4,214,902
Non-vested shares, Vested		(1,769,734)
Non-vested shares, Forfeited	(1,950,658)	(329,156)	(214,408)
Non-vested shares, Cancelled			(126,216)
Non-vested shares,Cancelled - MIP Exchanges	(581,677)	(1,171,532)
Non-vested shares at end of year	5,906,491	3,128,575	3,874,278
Non-vested Weighted-Average Grant-Date Fair Value, Granted	$ 0.30	$ 0.62	$ 11.87
Non-vested Weighted-Average Grant-Date Fair Value, Vested		11.87
Non-vested Weighted-Average Grant-Date Fair Value, Forfeited	0.41	11.87	11.87
Non-vested Weighted-Average Grant-Date Fair Value, Cancelled			$ 11.87
Non-vested Weighted Average Grant-Date Fair Value Cancelled - MIP Exchanges	$ 11.87	$ 11.87

Equity Compensation - Schedul_2

Equity Compensation - Schedule of Performance Share Units Settled in Entity Own Stock Equity (Details) - shares	Dec. 31, 2019	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, Shares issued	197,888,473	197,383,295
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares of common stock issued to settle PSUs		1,769,734
Less: shares of common stock withheld for income and payroll taxes		(733,174)
Common stock, Shares issued		1,036,560

Equity Compensation - Schedul_3

Equity Compensation - Schedule of Status and Activity of Non-vested RSUs (Details) - Restricted Share Units - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Non-vested shares at beginning of year	2,734,709	73,048
Non-vested shares, Granted	2,677,593	1,650,983	2,269,199
Non-vested shares, Vested	(1,042,515)		(2,191,297)
Non-vested shares, Forfeited	(704,916)	(160,854)	(4,854)
Non-vested shares, Granted - MIP Exchanges	581,677	1,171,532
Non-vested shares at end of year	4,246,548	2,734,709	73,048
Non-vested Weighted-Average Grant-Date Fair Value, Granted	$ 0.64	$ 1.89	$ 13.59
Non-vested Weighted-Average Grant-Date Fair Value, Vested	4.59		14.07
Non-vested Weighted-Average Grant-Date Fair Value, Forfeited	6.41	3	$ 10.31
Non-vested Weighted-Average Grant-Date Fair Value, Granted - MIP Exchanges	$ 0.70	$ 1.77

Equity Compensation - Schedul_4

Equity Compensation - Schedule of Restricted Share Units Settled in Entity Own Stock Equity (Details) - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, Shares issued	197,888,473	197,383,295
Restricted Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares of common stock issued to settle RSUs	715,809		2,191,297
Less: shares of common stock withheld for income and payroll taxes	(210,631)		(837,282)
Common stock, Shares issued	505,178		1,354,015

Equity Compensation - Schedul_5

Equity Compensation - Schedule of Valuation and Expense Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of equity compensation plans	$ 3,077	$ 15,639	$ 53,952
Amounts capitalized in oil and gas properties and equipment	506	3,814	13,975
Amounts charged against income, before income tax benefit	2,571	11,825	39,977
Amount of related income tax benefit recognized in income before valuation allowances	$ 540	$ 2,483	$ 15,927

Derivative Financial Instrume_3

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands, bbl in Millions, MMBTU in Millions	3 Months Ended	12 Months Ended
	Apr. 10, 2020$ / bblbbl	Dec. 31, 2019USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2018USD ($)
Derivative [Line Items]
Fair Value Asset		$ 32,100	$ 23,374
Fair Value (Liability)		$ (20,692)	$ (62,350)
Subsequent Event
Derivative [Line Items]
Type	Oil swaps
Year	2020
Index	NYMEX WTI
Total Volumes | bbl	27,300
Weighted Average Price Per Unit | $ / bbl	60.55
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]
Year		2020
Index		NYMEX-WTI
Total Volumes | bbl		0.5
Weighted Average Price Per Unit | $ / bbl		60.14
Fair Value Asset		$ 262
Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Year		2020
Index		NYMEX-Henry Hub
Total Volumes | MMBTU		23.7
Weighted Average Price Per Unit | $ / MMBTU		2.76
Fair Value Asset		$ 14,012
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]
Year		2020
Index		NW Rockies Basis Swap
Total Volumes | MMBTU		29.9
Weighted Average Price Per Unit | $ / MMBTU		(0.06)
Fair Value (Liability)		$ (16,122)
Commodity Derivative Contract Collars One | Natural Gas
Derivative [Line Items]
Year		2020
Index		NYMEX
Total Volumes | MMBTU		60.7
Weighted Average Floor Price | $ / MMBTU		2.41
Weighted Average Ceiling Price | $ / MMBTU		2.88
Fair Value Asset		$ 11,870
Commodity Derivative Contract Collars | Natural Gas
Derivative [Line Items]
Type		Natural gas collars
Commodity Derivative Contract Collars Two | Natural Gas
Derivative [Line Items]
Year		2021
Index		NYMEX
Total Volumes | MMBTU		7.2
Weighted Average Floor Price | $ / MMBTU		2.46
Weighted Average Ceiling Price | $ / MMBTU		3.05
Fair Value Asset		$ 43
Commodity Derivative Contract Put Options | Natural Gas
Derivative [Line Items]
Type		Natural gas put options
Commodity Derivative Contract Put Options One | Natural Gas
Derivative [Line Items]
Year		2020
Index		NYMEX
Total Volumes | MMBTU		13.4
Weighted Average Floor Price | $ / MMBTU		2.42
Fair Value Asset		$ 1,386

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Parenthetical) (Details)	Dec. 31, 2019$ / MMBTU
Natural Gas | Commodity Derivative Contract Deferred Premium Put Options
Derivative [Line Items]
Average deferred premium cost	0.13

Derivative Financial Instrume_5

Derivative Financial Instruments - Additional Information (Details) $ in Millions	3 Months Ended
	Apr. 10, 2020USD ($)
Subsequent Event
Derivative [Line Items]
Termination of derivative contracts	$ 1.3

Derivative Financial Instrume_6

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives									$ 54,282	$ (59,799)	$ 16,966
Total gain (loss) on commodity derivatives	$ (23,850)	$ 11,938	$ 71,654	$ (64,339)	$ (69,607)	$ (21,804)	$ (47,271)	$ (6,530)	(4,597)	(145,212)	28,412
Commodity Derivative Contract
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives									54,282	(59,799)	16,966
Total gain (loss) on commodity derivatives									(4,597)	(145,212)	28,412
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain (loss) on commodity derivatives									(62,573)	(77,031)	$ 11,446
Commodity Derivative Contract | Crude Oil
Derivative [Line Items]
Realized gain (loss) on commodity derivatives									$ 3,694	$ (8,382)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		$ 32,100	$ 23,374
Long-term derivative asset	[1]	1,516
Total derivative instruments		33,616
Current derivative liability		20,692	$ 62,350
Long-term derivative liability	[2]	1,473
Total derivative instruments		22,165
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		32,100
Long-term derivative asset	[1]	1,516
Total derivative instruments		33,616
Current derivative liability		20,692
Long-term derivative liability	[2]	1,473
Total derivative instruments		$ 22,165
[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, 2019	Dec. 31, 2018
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	$ 1,992,748	$ 2,044,035
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	752,972	1,495,137
Credit Agreement | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility	64,700	104,000
Credit Agreement | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility	64,700	104,000
Term Loan, Secured, Due April 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	968,756	975,000
Term Loan, Secured, Due April 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	566,723	858,000
Second Lien Notes, Secured, Due July 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	583,853	545,000
Second Lien Notes, Secured, Due July 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	86,994	395,125
6.875% Senior, Unsecured Notes Due 2022 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	150,439	195,035
6.875% Senior, Unsecured Notes Due 2022 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	18,805	68,262
7.125% Senior, Unsecured Notes Due 2025 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	225,000	225,000
7.125% Senior, Unsecured Notes Due 2025 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	$ 15,750	$ 69,750

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
Term Loan, Secured, Due April 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2024
Second Lien Notes, Secured, Due July 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2024
6.875% Senior, Unsecured Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2022
Stated interest rate	6.875%
7.125% Senior, Unsecured Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2025
Stated interest rate	7.125%

Other Current Assets - Schedule

Other Current Assets - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Other current assets	$ 10,746	$ 21,230
Deposits And Retainers
Other current assets	651	651
Prepaids And Others
Other current assets	1,087	1,822
Crude Oil
Other current assets	1,032	1,113
Pipe And Production Equipment
Other current assets	$ 7,976	$ 17,644

Other Current Assets - Addition

Other Current Assets - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Other Current Assets [Abstract]
Write down of pipe and production equipment	$ 7,461

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Loss From Continuing Operations Before Income Taxes Minority Interest And Income Loss From Equity Method Investments [Abstract]
United States									$ 108,575	$ 86,242	$ (197,136)
Foreign									(1,637)	(593)	360,982
Income before income tax expense (benefit)	$ (2,186)	$ 11,513	$ 56,964	$ 40,647	$ 39,705	$ 18,563	$ (20,546)	$ 47,927	$ 106,938	$ 85,649	$ 163,846

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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current tax:
U.S. federal, state and local - current							$ (1,050)	$ 433	$ (13,296)
Foreign - current								9	2
Total current tax provision (benefit)							(1,050)	442	(13,294)
Deferred tax:
Total income tax provision (benefit)	$ (882)	$ (141)	$ (27)	$ (1)	$ 9	$ 434	$ (1,050)	$ 442	$ (13,294)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	Mar. 27, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Line Items]
Statutory tax rate		21.00%
Deferred tax assets, valuation allowance		$ 625,400	$ 676,625
Subsequent Event | CARES Act
Income Taxes [Line Items]
Net operating loss carryforward	100.00%
Subsequent Event | CARES Act | Minimum [Member]
Income Taxes [Line Items]
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent	30.00%
Subsequent Event | CARES Act | Maximum
Income Taxes [Line Items]
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent	50.00%
Canada | 2015
Income Taxes [Line Items]
Tax years		2015
Canada | 2016
Income Taxes [Line Items]
Tax years		2016
Canada | 2017
Income Taxes [Line Items]
Tax years		2017
Federal
Income Taxes [Line Items]
Net operating loss carryforward		$ 2,300,000
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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Abstract]
Income tax provision computed at the U.S. statutory rate							$ 22,457	$ 17,986	$ 57,346
State income tax (benefit) provision net of federal effect									(25,519)
Valuation allowance							(31,733)	(30,723)	(562,491)
Tax effect of rate change									463,113
Sale of non-core assets								5,863	130,552
Foreign rate differential							(98)	(36)	(3,150)
Reorganization items							220	216	(89,327)
Equity compensation							1,747	2,689	10,778
Disallowed interest							5,799	700
Other, net							558	3,747	5,404
Total income tax provision (benefit)	$ (882)	$ (141)	$ (27)	$ (1)	$ 9	$ 434	$ (1,050)	$ 442	$ (13,294)

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Property and equipment		$ 33,953
Deferred gain		19,874
U.S. federal tax credit carryforwards	$ 512	512
U.S. interest carryforwards	27,949	5,931
U.S. net operating loss carryforwards	480,673	462,401
Non-U.S. net operating loss carryforwards	8,868	7,048
Asset retirement obligations	40,780	37,687
Derivative instruments, net		8,995
Debt financing	81,394	92,706
Incentive compensation	2,956	5,370
Lease liabilities	25,452
Other, net	3,143	2,148
Total deferred tax assets, gross	671,727	676,625
Valuation allowance	(625,400)	$ (676,625)
Net deferred tax assets	46,327
Deferred tax liabilities:
Derivative instruments, net	2,404
Property and equipment	18,828
Right-of-use assets	25,095
Net tax liabilities	$ 46,327

Leases - Additional Information

Leases - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Lessee Lease Description [Line Items]
Lessee, operating lease, remaining lease term	1 year
Maximum
Lessee Lease Description [Line Items]
Lease agreement term	1 year
Lessee, operating lease, remaining lease term	9 years

Leases - Summary of Components

Leases - Summary of Components of Lease Cost (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 20,919
Variable lease cost	6,654
Short-term lease cost	15,333
Total lease cost	$ 42,906

Leases - Summary of Component_2

Leases - Summary of Components of Lease Cost (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Demobilization and termination Costs	$ 2

Leases - Summary of Supplementa

Leases - Summary of Supplemental Balance Sheet Information Related to Operating Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 20,889

Leases - Summary of Supplemen_2

Leases - Summary of Supplemental Cash Flow Information Related to Operating Leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Operating Leases
Operating lease right-of-use assets	$ 119,496
Operating lease liabilities	11,938
Long-term operating lease liabilities	107,587
Total operating lease liabilities	$ 119,525
Weighted Average Remaining Lease Term
Operating leases	7 years 10 months 6 days
Weighted Average Discount Rate
Operating leases	7.91%

Leases - Summary of Fixed, Futu

Leases - Summary of Fixed, Future Minimum Rental Payments Excluding Variable Costs, for Operating Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019USD ($)
Operating Lease Liabilities Payments Due [Abstract]
2020	$ 20,853
2021	20,750
2022	20,326
2023	19,719
2024	19,719
Thereafter	58,520
Total lease payments	159,887
Less: imputed interest	(40,362)
Total	$ 119,525

Employee Benefits - Additional

Employee Benefits - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 2.5	$ 2.4

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Dekatherm / d$ / Dekatherm	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Oct. 06, 2017USD ($)	Apr. 14, 2017USD ($)
Loss Contingencies [Line Items]
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			$ 223,838
Bankruptcy claims amount of claims settled, post-petition interest			175,200
Claims subject to Appellate Court decision	$ 240,000
Settlement Agreements
Loss Contingencies [Line Items]
Settlement agreement, amount claimants paid	$ 29,900	$ 29,900
Indebtedness Claims | Notes holders
Loss Contingencies [Line Items]
Claim reserve account after emergence from bankruptcy					$ 400,000
Transportation Contract
Loss Contingencies [Line Items]
Claim against breach of contract			303,300
Settlement amount paid against claim			$ 150,000
Transportation capacity | Dekatherm / d	200,000
Transportation cost | $ / Dekatherm	0.37
Commencement of agreement term	Dec. 1, 2019
Expiration of agreement term	Dec. 31, 2026

Concentration of Credit Risk -

Concentration of Credit Risk - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019
Nevada Power Company
Sales, percentage of total revenue	11.10%
Pacific Gas and Electric
Sales, percentage of total revenue	10.20%
Customer Concentration Risk | Revenue | Minimum
Percentage of revenue	10.00%

2017 Chapter 11 Plan of Reorg_3

2017 Chapter 11 Plan of Reorganization - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	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

2017 Chapter 11 Plan of Reorg_4

2017 Chapter 11 Plan of Reorganization - Costs of Reorganization (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Reorganization Items [Abstract]
Professional fees	$ (66,529)
Gains (losses)	431,107
Make-whole fees	(223,838)
Other	167
Total Reorganization items, net	$ 140,907

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Operating revenues	$ 170,927	$ 144,238	$ 155,406	$ 271,461	$ 273,211	$ 203,776	$ 190,138	$ 225,374	$ 742,032	$ 892,499
Operating expenses	118,030	125,819	137,677	133,433	145,506	126,872	127,679	137,686	514,959	537,743	$ 493,588
Other (expense) income, net:
Interest expense, net	(31,323)	(32,372)	(32,376)	(33,327)	(36,382)	(38,382)	(37,715)	(35,837)	(129,398)	(148,316)	(361,367)
Gain (loss) on commodity derivatives	(23,850)	11,938	71,654	(64,339)	(69,607)	(21,804)	(47,271)	(6,530)	(4,597)	(145,212)	28,412
Contract settlement income (expense), net		13,468			15,332	(2,676)			13,468	12,656	(52,707)
Other income (expense), net	90	60	(43)	285	2,657	4,521	1,981	2,606	392	11,765
Total other (expense) income, net	(55,083)	(6,906)	39,235	(97,381)	(88,000)	(58,341)	(83,005)	(39,761)	(120,135)	(269,107)	(375,346)
Income (loss) before income tax (benefit) provision	(2,186)	11,513	56,964	40,647	39,705	18,563	(20,546)	47,927	106,938	85,649	163,846
Income tax provision (benefit)	(882)		(141)	(27)	(1)		9	434	(1,050)	442	(13,294)
Net income	$ (1,304)	$ 11,513	$ 57,105	$ 40,674	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	$ 107,988	$ 85,207	$ 177,140
Net income (loss) per common share — basic	$ (0.01)	$ 0.06	$ 0.29	$ 0.21	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.55	$ 0.43	$ 1.08
Net income (loss) per common share — fully diluted	$ (0.01)	$ 0.06	$ 0.29	$ 0.21	$ 0.20	$ 0.09	$ (0.10)	$ 0.24	$ 0.55	$ 0.43	$ 1.08

Disclosure About Oil and Gas _2

Disclosure About Oil and Gas Producing Activities (Unaudited) - Additional Information (Details) $ / shares in Units, $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2020USD ($)	Mar. 31, 2020USD ($)$ / Mcfe	Mar. 31, 2020USD ($)$ / bbl	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares	Dec. 31, 2016USD ($)
Reserve Quantities [Line Items]
Internal engineer experience				15 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 eight 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 15 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.
Discount rate future net revenues				10.00%
Future estimated net cash flows				$ 2,904,393	$ 4,544,786	$ 4,377,344
Standardized measure of discounted future net cash flows				$ 1,710,619	$ 2,405,483	$ 2,384,328	$ 1,690,946
Significant changes in reserves				Changes in proved undeveloped reserves: The Company’s year-end development plans are consistent with SEC guidelines for PUD development within five years.
Weighted average sales price for proved reserves natural gas | $ / shares				$ 2.44	$ 2.59	$ 2.59
Weighted average sales price for proved reserves condensate | $ / shares				$ 55.36	$ 63.49	$ 48.05
Subsequent Event
Reserve Quantities [Line Items]
Base price of oil and gas		2.07	55.35
Future estimated net cash flows	$ 1,907,000	$ 1,907,000	$ 1,907,000
Standardized measure of discounted future net cash flows	$ 1,218,000	$ 1,218,000	$ 1,218,000
Natural Gas | Subsequent Event
Reserve Quantities [Line Items]
Percentage of decrease in price of natural gas	15.00%
Oil Reserves | Maximum | Subsequent Event
Reserve Quantities [Line Items]
Percentage of decrease in price of natural gas	1.00%

Disclosure About Oil and Gas _3

Disclosure About Oil and Gas Producing Activities (Unaudited) - Summary of Developed and Undeveloped Proven Reserves (Details) bbl in Thousands, Mcf in Thousands	Mar. 31, 2020MMcfMBbls	Dec. 31, 2019bblMcf	Dec. 31, 2018bblMcf	Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf
Natural Gas Reserves
Reserve Quantities [Line Items]
Developed | Mcf		1,902,600	2,243,956	2,261,289	2,321,613
Undeveloped | Mcf			677,877	694,703
Total Proved | Mcf		1,902,600	2,921,833	2,955,992	2,321,613
Oil Reserves
Reserve Quantities [Line Items]
Developed		14,627	17,876	21,652	21,475
Undeveloped			5,569	5,466
Total Proved		14,627	23,445	27,118	21,475
Natural Gas Liquid Reserves
Reserve Quantities [Line Items]
Developed				71	9,903
Total Proved				71	9,903
Subsequent Event | Natural Gas Reserves
Reserve Quantities [Line Items]
Developed | MMcf	1,694,828
Total Proved | MMcf	1,694,828
Subsequent Event | Natural Gas Equivalents Reserves
Reserve Quantities [Line Items]
Developed | MMcf	1,766,239
Total Proved | MMcf	1,766,239
Subsequent Event | Oil Reserves
Reserve Quantities [Line Items]
Developed | MBbls	11,902
Total Proved | MBbls	11,902

Disclosure About Oil and Gas _4

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, 2019bblMcf	Dec. 31, 2018bblMcf	Dec. 31, 2017bblMcf
Natural Gas Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance | Mcf	2,921,833	2,955,992	2,321,613
Extensions, discoveries and additions | Mcf	13,113	85,180	50,312
Sales | Mcf		(4,033)	(89,315)
Acquisitions | Mcf			22,400
Production | Mcf	(230,120)	(260,406)	(260,009)
Revisions | Mcf	(802,226)	145,100	910,991
Reserves, Ending Balance | Mcf	1,902,600	2,921,833	2,955,992
Oil Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	23,445	27,118	21,475
Extensions, discoveries and additions	114	1,086	1,117
Sales		(3,573)
Acquisitions			153
Production	(1,684)	(2,442)	(2,775)
Revisions	(7,248)	1,256	7,148
Reserves, Ending Balance	14,627	23,445	27,118
Natural Gas Liquid Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance		71	9,903
Sales		(71)
Revisions			(9,832)
Reserves, Ending Balance			71

Disclosure About Oil and Gas _5

Disclosure About Oil and Gas Producing Activities (Unaudited) - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future cash inflows	$ 5,538,104	$ 9,195,725	$ 8,965,949
Future production costs	(2,277,881)	(3,337,779)	(3,587,581)
Future development costs	(355,830)	(1,133,103)	(1,001,024)
Future income taxes		(180,057)
Future net cash flows	2,904,393	4,544,786	4,377,344
Discount at 10%	(1,193,774)	(2,139,303)	(1,993,016)
Standardized measure of discounted future net cash flows	$ 1,710,619	$ 2,405,483	$ 2,384,328	$ 1,690,946

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning	$ 2,405,483	$ 2,384,328	$ 1,690,946
Net revisions of previous quantity estimates	(713,236)	160,405	840,505
Extensions, discoveries and other changes	16,493	90,609	53,549
Sales of reserves in place		(34,768)	(83,887)
Acquisition of reserves			21,903
Changes in future development costs	106,464	(235,205)	(329,635)
Sales of oil and gas, net of production costs	(486,740)	(593,134)	(589,621)
Net change in prices and production costs	(369,917)	362,084	572,224
Development costs incurred during the period that reduce future development costs	147,042	251,621	8,007
Accretion of discount	243,536	238,433	169,095
Net changes in production rates and other	331,621	(189,017)	31,242
Net change in income taxes	29,873	(29,873)
Aggregate changes	(694,864)	21,155	693,382
Standardized measure, ending	$ 1,710,619	$ 2,405,483	$ 2,384,328

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$ 817	$ 1,468	$ 1,399
Acquisition costs - proved properties	73	1,090	9,147
Exploration	33,509	156,718	510,710
Development	206,339	266,905	35,934
Total	$ 240,738	$ 426,181	$ 557,190

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$ 742,032	$ 892,499	$ 891,873
Production expenses	(255,292)	(299,365)	(292,095)
Depletion and depreciation	(204,227)	(204,255)	(161,945)
Income tax benefit (expense)	8	(2)	(168,355)
Total	$ 282,521	$ 388,877	$ 269,478

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, 2019	Dec. 31, 2018
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,820,392	$ 11,577,281
Less: accumulated depletion, depreciation and amortization	(10,267,973)	(10,079,554)
Total Oil and gas properties, net	$ 1,552,419	$ 1,497,727

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
General and administrative expense									$ 26,551	$ 25,005	$ 39,548
Other income (expense):
Interest expense	$ (31,323)	$ (32,372)	$ (32,376)	$ (33,327)	$ (36,382)	$ (38,382)	$ (37,715)	$ (35,837)	(129,398)	(148,316)	(361,367)
Other expense									392	1,212	(237)
Reorganization items, net											140,907
Income tax provision (benefit)	(882)		(141)	(27)	(1)		9	434	(1,050)	442	(13,294)
Net income	$ (1,304)	$ 11,513	$ 57,105	$ 40,674	$ 39,706	$ 18,563	$ (20,555)	$ 47,493	107,988	85,207	177,140
Parent
General and administrative expense									1,650	549	428
Other income (expense):
Interest expense											(71,876)
Income (loss) from unconsolidated affiliates									109,625	85,809	(183,840)
Other expense									13	(44)	90
Reorganization items, net											433,196
Income before income taxes									107,988	85,216	177,142
Income tax provision (benefit)										9	2
Net income									$ 107,988	$ 85,207	$ 177,140

Supplemental Financial Statem_4

Supplemental Financial Statement Information - Supplemental Balance Sheet Disclosures Parent Company (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 1,664	$ 17,014	$ 16,631
Other current assets	10,746	21,230
Total current assets	125,489	214,730
Other non-current assets	8,093	9,196
Total assets	1,815,276	1,733,288
Current liabilities:
Accrued and other current liabilities	42,824	58,574
Total current liabilities	2,324,221	267,211
Total liabilities	2,660,090	2,781,910
Total shareholders' equity (deficit)	(844,814)	(1,048,622)	(1,154,636)	$ (2,928,151)
Total liabilities and shareholders’ equity	1,815,276	1,733,288
Parent
Current Assets:
Cash and cash equivalents	289	570	$ 803	$ 3,009
Accounts receivable from related companies	29,939	29,939
Total current assets	30,228	30,509
Total assets	30,228	30,509
Current liabilities:
Total current liabilities		0
Advances from unconsolidated affiliates	875,043	1,079,131
Total liabilities	875,043	1,079,131
Total shareholders' equity (deficit)	(844,815)	(1,048,622)
Total liabilities and shareholders’ equity	$ 30,228	$ 30,509

Supplemental Financial Statem_5

Supplemental Financial Statement Information - Supplemental Cash Flow Statement Disclosures Parent Company (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net cash (used in) operating activities	$ 302,416	$ 310,897	$ 65,268
Investing Activities:
Net cash used in investing activities	(270,152)	(401,710)	(435,311)
Financing activities:
Shares issued			573,774
Net cash provided by (used in) financing activities	(48,128)	91,849	(16,737)
Cash and cash equivalents, beginning of period	17,014	16,631
Cash and cash equivalents, end of period	1,664	17,014	16,631
Parent
Net cash (used in) operating activities	(281)	(234)	(2,206)
Investing Activities:
Investment in subsidiaries	(180)	(3,293)	(588,677)
Net cash used in investing activities	(180)	(3,293)	(588,677)
Financing activities:
Shares issued		3,294	573,774
Repurchased shares/net share settlements	180		14,903
Net cash provided by (used in) financing activities	180	3,294	588,677
(Decrease) increase in cash during the period	(281)	(233)	(2,206)
Cash and cash equivalents, beginning of period	570	803	3,009
Cash and cash equivalents, end of period	$ 289	$ 570	$ 803