Ultra Petroleum 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document And Entity Information [Abstract]
Entity Registrant Name	ULTRA PETROLEUM CORP.
Entity Central Index Key	0001022646
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		197,383,295
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Trading Symbol	UPL

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 10,469	$ 17,014
Restricted cash	2,596	2,291
Oil and gas revenue receivable	86,763	133,042
Joint interest billing and other receivables, net	6,701	11,348
Derivative assets	10,985	23,374
Income tax receivable		6,431
Inventory	18,277	18,757
Other current assets	2,840	2,473
Total current assets	138,631	214,730
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,543,166	1,497,727
Property, plant and equipment, net	11,178	11,635
Long-term right-of-use assets	127,861
Other assets	13,532	9,196
Total assets	1,834,368	1,733,288
Current liabilities:
Accounts payable	36,314	36,923
Accrued liabilities	62,999	58,574
Production taxes payable	84,108	58,365
Current portion of long-term debt	9,750	7,313
Interest payable	28,771	28,672
Lease liabilities	11,261
Derivative liabilities	38,483	62,350
Capital cost accrual	16,966	15,014
Total current liabilities	288,652	267,211
Long-term debt
Credit facility	38,000	104,000
Long-term debt	1,915,906	1,932,722
Add: Premium on exchange transactions	235,941	228,096
Less: Unamortized deferred financing costs and discount	(54,161)	(56,650)
Total long-term debt, net	2,135,686	2,208,168
Deferred gain on sale of liquids gathering system		94,636
Long-term lease liabilities	116,613
Other long-term obligations	207,420	211,895
Total liabilities	2,748,371	2,781,910
Commitments and contingencies (Note 9)
Shareholders' equity:
Common stock - no par value; authorized - 750,000,000; issued and outstanding - 197,383,295 at March 31, 2019 and December 31, 2018, respectively	2,138,570	2,137,443
Treasury stock	(49)	(49)
Retained loss	(3,052,524)	(3,186,016)
Total shareholders' deficit	(914,003)	(1,048,622)
Total liabilities and shareholders' equity	$ 1,834,368	$ 1,733,288

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Statement Of Financial Position [Abstract]
Common stock, No par value
Common stock, Shares authorized	750,000,000	750,000,000
Common stock, Shares issued	197,383,295	197,383,295
Common stock, Shares outstanding	197,383,295	197,383,295

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues:
Total operating revenues	$ 271,461	$ 225,374
Expenses:
Lease operating expenses	17,225	21,764
Facility lease expense	6,645	6,156
Production taxes	30,175	23,270
Gathering fees	19,880	23,055
Depletion, depreciation and amortization	51,653	50,540
General and administrative	7,052	12,688
Other expenses	684	213
Total operating expenses	133,314	137,686
Operating income	138,147	87,688
Other income (expense), net:
Interest expense	(33,327)	(35,837)
Loss on commodity derivatives	(64,339)	(6,530)
Deferred gain on sale of liquids gathering system		2,638
Other income (expense), net	166	(32)
Total other (expense) income, net	(97,500)	(39,761)
Income before income tax (benefit) provision	40,647	47,927
Income tax (benefit) provision	(27)	434
Net income	$ 40,674	$ 47,493
Basic earnings per share:
Net income per common share - basic	$ 0.21	$ 0.24
Fully diluted earnings per share:
Net income per common share - fully diluted	$ 0.21	$ 0.24
Weighted average common shares outstanding - basic	197,383	196,550
Weighted average common shares outstanding - fully diluted	197,801	196,550
Natural Gas Sales
Revenues:
Total operating revenues	$ 245,989	$ 181,462
Oil Sales
Revenues:
Total operating revenues	23,465	41,284
Other Revenues
Revenues:
Total operating revenues	$ 2,007	$ 2,628

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Shareholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Common Stock	Retained (Loss) Earnings	Treasury Stock
Beginning Balances at Dec. 31, 2017	$ (1,154,636)	$ 2,116,018	$ (3,270,605)	$ (49)
Beginning Balances, Shares at Dec. 31, 2017		196,347
Employee stock plan grants, Shares		1,226
Net share settlements	(2,061)		(2,061)
Net share settlements, Shares		(519)
Fair value of employee stock plan grants	10,709	$ 10,709
Initial adoption | ASC 606	1,761		1,761
Net income	47,493		47,493
Ending Balances at Mar. 31, 2018	(1,096,734)	$ 2,126,727	(3,223,412)	(49)
Ending Balances, Shares at Mar. 31, 2018		197,054
Beginning Balances at Dec. 31, 2018	(1,048,622)	$ 2,137,443	(3,186,016)	(49)
Beginning Balances, Shares at Dec. 31, 2018		197,383
Fair value of employee stock plan grants	1,127	$ 1,127
Initial adoption | ASC 842	92,818		92,818
Net income	40,674		40,674
Ending Balances at Mar. 31, 2019	$ (914,003)	$ 2,138,570	$ (3,052,524)	$ (49)
Ending Balances, Shares at Mar. 31, 2019		197,383

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating activities - cash provided by (used in):
Net income for the period	$ 40,674	$ 47,493
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization	51,653	50,540
Unrealized loss (gain) on commodity derivatives	(14,292)	7,606
Deferred gain on sale of liquids gathering system		(2,638)
Stock compensation	841	8,810
Payable-in-Kind (“PIK”) interest payable	3,183
Amortization of premium on debt exchange	(9,716)
Amortization of deferred financing costs	3,123	2,727
Other	582	209
Net changes in operating assets and liabilities:
Accounts receivable	50,243	12,561
Other current assets	(307)	2,485
Other non-current assets	30	30
Accounts payable	(359)	(5,263)
Accrued liabilities	4,425	(7,486)
Production taxes payable	25,743	23,622
Interest payable	99	17,172
Other long-term obligations	(11,663)	(12,708)
Income taxes payable/receivable	6,431	6,836
Net cash provided by operating activities	150,690	151,996
Investing Activities - cash provided by (used in):
Oil and gas property expenditures	(92,352)	(134,500)
Change in capital cost accrual and accounts payable	1,702	(8,079)
Inventory	419	(5,074)
Purchase of capital assets	(211)	(1,196)
Net cash used in investing activities	(90,442)	(148,849)
Financing activities - cash provided by (used in):
Deferred financing costs	(488)
Repurchased shares/net share settlements		(2,061)
Net cash used in financing activities	(66,488)	(2,061)
(Decrease) increase in cash during the period	(6,240)	1,086
Cash, cash equivalents, and restricted cash, beginning of period	19,305	18,269
Cash, cash equivalents and restricted cash, end of period	13,065	19,355
Credit Agreement
Financing activities - cash provided by (used in):
Borrowings under Credit / Term Loan Agreement	232,000	191,000
Payments under Credit Agreement	$ (298,000)	$ (191,000)

Description of the Business

Description of the Business	3 Months Ended
	Mar. 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”, “us”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

Debt Exchanges

Debt Exchanges	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt Exchanges	Debt Exchanges In December 2018, the Company exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022 Notes”) and (ii) $275 million aggregate principal amount, or 55.0%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022 Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of Ultra Petroleum Corp., for (a) $545.0 million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “Second Lien Notes”), and (b) an aggregate of 10,919,499 new $0.01 warrants of Ultra Petroleum Corp. entitling the holder thereof to purchase one common share of Ultra Petroleum Corp. (each a “Warrant” and collectively, the “Warrants”) (such transaction, the “December Exchange Transaction”). In January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions (such transactions, the “Follow-on Exchange Transactions” and, together with the December Exchange Transaction, the “Exchange Transactions”). All Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. Refer to Note 4 for additional details and the accounting treatment on the Exchange Transactions.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	1. SIGNIFICANT ACCOUNTING POLICIES: The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ended December 31, 2019. The condensed consolidated balance sheet at December 31, 2018, has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2018. Basis of Presentation and Principles of Consolidation: The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All inter-company transactions and balances have been eliminated. Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. The Company follows Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Accounts Receivable, net: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. As of March 31, 2019, the allowance for uncollectible accounts was $9.0 million. The carrying amount of the Company’s accounts receivable approximates fair value due to the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. 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 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. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the three months ended March 31, 2019 or 2018. Inventories: Inventory primarily includes $17.2 million in pipe and production equipment that will be utilized during the 2019-2020 drilling programs and $1.1 million in crude oil inventory as of March 31, 2019. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Deferred Financing Costs (“DFC”): The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs for its borrowings under the Term Loan Agreement (as defined below), Second Lien Notes and 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 Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Condensed Consolidated Balance Sheets and records the changes in the fair value of its commodity derivatives in the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 7 for additional details. 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 : In December 2018, the Company issued 10,919,499 Warrants. The Warrants are initially exercisable for one common share of Ultra Petroleum Corp., no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the common shares is at least $2.50 per common share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof 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. Under the guidance in FASB ASC 815, the Warrants do not meet the definition of a derivative. The Warrants are classified as equity and recorded at fair value as of the date of issuance on the Company’s Consolidated Balance Sheets and no further adjustments to their valuation are made. 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 payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator using the treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. The following table provides a reconciliation of components of basic and diluted net income per common share: For the Three Months Ended March 31, 2019 2018 (Share amounts in 000's) Net income $ 40,674 $ 47,493 Weighted average common shares outstanding - basic 197,383 196,550 Effect of dilutive instruments 418 — Weighted average common shares outstanding - diluted 197,801 196,550 Net income per common share - basic $ 0.21 $ 0.24 Net income per common share - fully diluted $ 0.21 $ 0.24 Use of Estimates: Preparation of condensed consolidated financial statements in accordance with 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. Beginning as of January 1, 2019, the Company revised its estimate of administrative costs associated with its operations and classified as Lease operating expenses on the consolidated statement of operations. During 2018 and 2019, the Company has taken steps to drive efficiencies through its operations which resulted in its overhead costs being less than the inflation adjustment to the overhead rates set by the Council of Petroleum Accountants Societies (“COPAS”). Accordingly, the Company reduced the amount of costs categorized as Lease operating expenses, with General and administrative expenses absorbing a larger portion of the total costs. Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional details. 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 Condensed Consolidated Balance Sheets. Leases: The Company adopted ASU 2016-02, , 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 not be provided for dates and periods prior to 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 condensed 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 tested 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. Additionally, 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 (as defined below). 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. Other Revenues : Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed . Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. 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 condensed consolidated balance sheets but did not have an effect on the Company’s condensed consolidated income statements. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 9 for additional discussion. Cumulative Effect of Recently Adopted Accounting Pronouncements: The following table reflects the cumulative impact of the adoption of ASC 842 using the modified retrospective approach. December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (Amounts 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 stockholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and stockholders' 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): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements. Financial Instruments. In June 2016, The FASB issued ASU 2016-13, "Financial Instruments—Credit Losses (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. ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. Early adoption is permitted for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are currently assessing the impact ASU 2016-13 will have on our Consolidated Financial Statements.

Revenue Recognition

Revenue Recognition	3 Months Ended
	Mar. 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 control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies. Natural gas sales We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the natural gas production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Oil sales We sell oil production at (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 (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the oil production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Other revenues Our other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred upon completion of the processing service. The Company is considered the principal, and revenue is recognized at the point in time that the control is transferred. Transaction price allocated to remaining performance obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Oil and Gas Properties and Equi

Oil and Gas Properties and Equipment	3 Months Ended
	Mar. 31, 2019
Oil And Gas Property [Abstract]
Oil and Gas Properties and Equipment	3. OIL AND GAS PROPERTIES AND EQUIPMENT: March 31, December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,670,425 $ 11,577,281 Less: Accumulated depletion, depreciation and amortization (10,127,259 ) (10,079,554 ) Oil and gas properties, net $ 1,543,166 $ 1,497,727

Long Term Debt

Long Term Debt	3 Months Ended
	Mar. 31, 2019
Long Term Liabilities [Abstract]
Long Term Debt	4. LONG TERM DEBT: The following tables summarize the Company’s debt instruments as of March 31, 2019 and December 31, 2018: March 31, 2019 Principal repayment obligation (1) Unamortized DFC and discounts (2) Unamortized premium Carrying value Credit Facility, secured, due January 2022 $ 38,000 $ — $ — $ 38,000 Term Loan, secured, due April 2024 975,068 (25,807 ) — 949,261 Second Lien Notes, secured, due July 2024 575,149 — 235,941 811,090 6.875% Notes, unsecured, due April 2022 150,439 (14,189 ) — 136,250 7.125% Notes, unsecured, due April 2025 225,000 (14,165 ) — 210,835 Total debt $ 1,963,656 $ (54,161 ) $ 235,941 $ 2,145,436 Less: Current maturities (9,750 ) — — (9,750 ) Total long-term debt, net $ 1,953,906 $ (54,161 ) $ 235,941 $ 2,135,686 (1) Includes PIK interest on the Term Loan and Second Lien Notes of $0.1 million and $3.1 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 repayment obligation Unamortized DFC and discounts (1) Unamortized premium Carrying value Credit Facility, 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% Notes, unsecured, due April 2022 195,035 (15,168 ) — 179,867 7.125% Notes, unsecured, due April 2025 225,000 (14,608 ) — 210,392 Total debt $ 2,044,035 $ (56,650 ) $ 228,096 $ 2,215,481 Less: Current maturities (7,313 ) — — (7,313 ) Total long-term debt, net $ 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. Ultra Resources, Inc. Credit Agreement. In April 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto 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). The semi-annual redetermination in February 2019 resulted in a borrowing base commitment of $1.3 billion, with $975.0 million allocated to the Company’s Term Loan (as defined below) and $325.0 million allocated to the Revolving Credit Facility. In December 2018, Ultra Resources and the parent guarantors entered into the Third Amendment to the Credit Agreement (the “Third Amendment to Credit Agreement”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Third Amendment to Credit Agreement, the parties agreed, among other things, to amend the Credit Agreement to permit the issuance of the Second Lien Notes and the December Exchange Transaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to: • increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Credit Agreement); • removing the ability to create, invest in and utilize unrestricted subsidiaries; • further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Third Amendment to Credit Agreement; and • providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Third Amendment to Credit Agreement. On February 14, 2019, Ultra Resources entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment to Credit Agreement”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Fourth Amendment to Credit Agreement, the borrowing base was reaffirmed at $1.3 billion. Given the Revolving Credit Agreement was amended in February 2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is in October 2019. The Fourth Amendment to Credit Agreement also revised certain covenants and other provisions of the Credit Agreement, including, but not limited to: • amending the Consolidated Net Leverage Ratio financial covenant as described below. In addition, the consolidated net debt component of the consolidated net leverage ratio may be reduced upon receipt of proceeds from the make-whole litigation as described in Note 10; • revising the definition of EBITDAX to (i) provide Ultra Resources with the option of whether to add back certain noncash charges that represent an accrual or reserve for potential cash items in a future period, (ii) provide for the add back of costs and expenses with respect to senior management changes and office closure, consolidation and relocation, (iii) provide for the add back of costs and expenses with respect to debt restructuring activities (whether consummated or not), (iv) exclude from the deductions certain noncash gains that represent the reversal of an accrual or reserve for any anticipated cash charges in any prior period, and (v) provide for a deduction of cash payments with respect to certain noncash charges that Ultra Resources chose to add back (as described in clause (i)); and • amending the Current Ratio financial covenant to exclude from the consolidated current liabilities calculated thereunder, the current required amortization payments under the Term Loan Agreement. At March 31, 2019, Ultra Resources had $38.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million. The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. T he Revolving Credit Facility requires Ultra Resources to maintain (i) a minimum interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, of a minimum of 1.00 to 1.00; and (iii) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. In addition, as of the last day of (i) each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.75 to 1.00, (ii) each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.90 to 1.0, (iii) the fiscal quarter ending September 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.50 to 1.0, and (iv) the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.25 to 1.0. At March 31, 2019, Ultra Resources’ consolidated net leverage ratio and interest coverage ratio were 4.11 to 1.00 and 3.26 to 1.00, respectively, and Ultra Resources was in compliance with each of its debt covenants under the Credit Agreement. Under the Revolving Credit Facility, t he Company is subject to the following minimum hedging requirements: t Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees. The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants. The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated. Term Loan. In April 2017 , Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement (the “Term Loan Agreement”) with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent (the “Term Loan Administrative Agent”), and the other lenders party thereto (collectively, the “Term Loan Lenders”). As part of the Term Loan Agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in the deferred financing costs noted above. 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 December Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payable in cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to: • introducing call protection of 102% until December 21, 2019 and 101% until December 21, 2020; • introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility as more thoroughly described in the Term Loan Amendment; • deleting the ability to increase commitments under the Term Loan; • increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement); • removing the ability to create, invest in and utilize unrestricted subsidiaries; • further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Term Loan Amendment; and • providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term Loan Amendment. At March 31, 2019, Ultra Resources had $975.1 million in outstanding borrowings under the Term Loan Agreement, including PIK interest and current maturities. Borrowings under the Term Loan Agreement bear interest either at a rate equal to (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable-in-kind (“PIK”) upon election by Ultra Resources. Beginning in March 2019, the Company has elected the PIK option and management expects to continue this practice into the future. The borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. Borrowings under the Term Loan Agreement matures 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 exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the 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 March 31, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement. The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement. Second Lien Notes. On December 21, 2018, in connection with the consummation of the December Exchange Transaction, Ultra Resources issued $545.0 million aggregate principal amount of Second Lien Notes and entered into an Indenture, dated as of December 21, 2018 (the “Second Lien Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent. During January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes in a series of Follow-on Exchange Transactions. All Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. As of March 31, 2019, Ultra Resources had approximately $575.1 million in outstanding borrowings under the Second Lien Notes Indenture, including PIK interest. The Second Lien Notes will mature on July 12, 2024. Interest on the Second Lien Notes will accrue at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019. The Company has accounted for such PIK interest as an increase to the principal outstanding. 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 111.00% 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, 2021, 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 105.50% for the twelve-month period beginning on December 21, 2021, 102.75% for the twelve-month period beginning December 21, 2022, and 100.00% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plus accrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes. If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second Lien Notes may require the Issuer to repurchase all or a portion of its Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount of such Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase. The Second Lien Notes Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur or redeem indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) pay cash dividends, (vi) change the nature of its business or operations, (vii) make certain types of investments, (ix) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (x) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Second Lien Notes Indenture); and (xi) create unrestricted and foreign subsidiaries. The covenants in the Second Lien Notes Indenture are subject to important exceptions and qualifications. Subject to conditions, the Second Lien Notes Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Second Lien Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. The Second Lien Notes Indenture contains customary events of default. Unless otherwise noted in the Second Lien Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Second Lien Notes, by notice to the Company and the Trustee, may declare the Second Lien Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) or group of Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Second Lien Notes to become due and payable. In conjunction with the Exchange Transactions, the portion of the Unsecured Notes which were exchanged for Second Lien Notes was accounted for as a troubled debt restructuring. The Company evaluated the quantitative and qualitative factors in the accounting literature and concluded that concessions were granted as the future undiscounted cash flows of the Second Lien Notes was greater than the net carrying value of the senior Unsecured Notes. No gain is recognized, and an effective interest rate is established based on the carrying value of the Second Lien Notes and revised cash flows. The amount of extinguished debt will be amortized over the remaining life of the Second Lien Notes using the effective interest method and recognized as a reduction to interest expense. As a result, our reported interest expense will be significantly less than the contractual cash interest payments throughout the term of the Second Lien Notes. The exchanged debt resulted in a calculation of cancellation of debt income for tax purposes. Our current tax attributes are expected to offset any potential cash tax impacts from the Exchange Transactions. For additional details on the Company’s income taxes, refer to Note 6. Unsecured Notes . In April 2017, Ultra Resources issued $700.0 million of its 2022 Notes and $500.0 million of its 2025 Notes and entered into an Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as Trustee. The Unsecured Notes are treated as a single class of securities for most purposes under the Unsecured Notes Indenture. In December 2018, the Company completed the December Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principal amount, or 55.0%, of the issued and outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes and (b) an aggregate of 10,919,499 new warrants of Ultra Petroleum Corp. each entitling the holder thereof to purchase one common share of Ultra Petroleum Corp. In January and February 2019, the Company completed a series of Follow-on Exchange Transactions, pursuant to which the exchanging noteholders exchanged approximately $44.6 million aggregate principal amount of the issued and outstanding 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes. At March 31, 2019, the aggregate principal amounts outstanding under the Unsecured Notes were approximately $150.4 million with respect to the 2022 Notes and $225.0 million with respect to the 2025 Notes. The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity. In December 2018, Ultra Resources, the Company and its other subsidiaries, as guarantors, and the Trustee entered into the First Supplemental Indenture to the Unsecured Indenture (the “Supplemental Indenture”). Pursuant to the Supplemental Indenture, the parties amended the Unsecured Indenture to, among other things, eliminate or amend substantially all of the restrictive covenants contained in the Unsecured Indenture, other than those relating to the payment of principal and interest. The Supplemental Indenture is binding on all Unsecured Notes that remain outstanding. The Unsecured Notes Indenture contains customary events of default. Unless otherwise noted in the Unsecured Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Unsecured Notes Indenture) or group of Restricted Subsidiaries (as defined in the Unsecured Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable.

Share Based Compensation

Share Based Compensation	3 Months Ended
	Mar. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share Based Compensation	5. SHARE BASED COMPENSATION: Valuation and Expense Information For the Three Months Ended March 31, 2019 2018 Total cost of share-based payment plans $ 1,127 $ 10,910 Amounts capitalized in oil and gas properties and equipment $ 286 $ 2,100 Amounts charged against income, before income tax benefit $ 841 $ 8,810 Amount of related income tax benefit recognized in income before valuation allowance $ 177 $ 1,850 Performance Share Plans : 2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established by our board of directors (the “Board”) pursuant to which 7.5% of the equity in 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 to exclude a change in a majority of the members on the Board; • provide that, with respect to awards granted on or after June 8, 2018, no such awards will vest solely as a result of a Change of Control (as defined in the A&R Stock Incentive Plan) unless expressly provided otherwise in the applicable grant agreement or unless otherwise determined by the Committee; and • make certain other changes related to revisions to the U.S. Internal Revenue Code. In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvested portion of their Initial MIP Grants for new equity awards of time-based restricted stock units (the “2018 RSUs”) effective July 31, 2018 on a one-for-one basis. All 2018 RSUs are time-based awards and vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation (“ASC 718”), the cancellation of an outstanding award of stock-based compensation followed by the issuance of a replacement award is treated as a modification of the original award. The equity award cancellations and subsequent new grants by the Company were considered Type I, probable-to-probable modification in 2018. This type represents modifications where the award was likely to vest prior to modification and is still likely to vest after modification. For these types of modifications, the fair value of the award is assessed both prior to modification and after modification. If the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period. In March 2019, additional Initial MIP Grants were exchanged for new equity awards of time-based and performance-based restricted stock units. The Company evaluated the cancellation of an outstanding award of stock-based compensation followed by the issuance of a replacement award under ASC 718. For this modification, the fair value of the award is assessed both prior to modification and after modification. Per ASC 718, if the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period. Long Term Incentive Awards. In 2018 and March 2019, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The awards cover a performance period of three years and includes time-based and performance-based measures established by the Committee at the beginning of the three-year period. Stock-Based Compensation Cost : Market-Based Condition Awards. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’s total equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an award that is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the awards that include a market condition. FASB ASC 718 requires the expense for an award of stock-based compensation that is subject to a market condition that can be attained at any point during the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and (b) the award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on which the market condition is satisfied. The duration is the period of time from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is actually satisfied. Expense. For the three months ended March 31, 2019, the Company recognized $0.8 million in pre-tax compensation expense, which is included within General and administrative expenses on the Condensed Consolidated Statement of Operations. During the three months ended March 31, 2018, the Company recognized $8.8 million in pre-tax compensation expense, of which $8.6 million related to the Initial MIP Grants.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	6. INCOME TAXES: The Company’s overall effective tax rate on pre-tax income was different than the statutory rate of 21% due primarily to adjustments to the valuation allowances. The Company has recorded a valuation allowance against all deferred tax assets as of March 31, 2019. Some or all of this valuation allowance may be reversed in future periods against future income. On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue to be issued at times. The Company will continue to monitor these new regulations and analyze their applicability and impact on the Company.

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	7. DERIVATIVE FINANCIAL INSTRUMENTS: 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 operations and 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. The Company’s Revolving Credit Facility requires the Company to hedge 65% of forecast proved producing natural gas production, based on its most recent reserve report for 18 months from the end of the given quarter. This requirement is in effect through September 29, 2019. After that time, the requirement decreases to 50% of the estimated proved producing forecast for natural gas through March 30, 2020. This means the Company may unwind hedges beginning September 30, 2019 at its discretion providing the Company remains hedged at the 50% level for natural gas. Additionally, the Revolving Credit Facility limits the amount of hedging to 85% of forecast production for all products within a given quarter. Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the Condensed Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Condensed Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Condensed Consolidated Statements of Cash Flows Commodity Derivative Contracts: At March 31, 2019, the Company had the following open commodity derivative contracts to manage commodity price risks. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price 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 price 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 as published by independent third parties . Refer to Note 8 for more information regarding the Company’s derivative instruments. Type/Year Index Total Volumes Weighted Average Price per Unit Fair Value - March 31, 2019 (in millions) Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 (April through December) NYMEX-Henry Hub 137.8 $ 2.77 $ (2,079 ) 2020 NYMEX-Henry Hub 24.6 2.78 (5,439 ) Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2019 (April through December) NW Rockies Basis Swap 90.2 $ 0.58 $ (18,734 ) 2020 NW Rockies Basis Swap 7.7 0.15 770 Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 (April through December) NYMEX-WTI 1.0 $ 58.64 $ (1,680 ) 2020 NYMEX-WTI 0.1 60.05 51 Type/Year Index Total Volumes Weighted Average Floor Price ($/MMBTU) Weighted Average Ceiling Price ($/MMBTU) Fair Value - March 31, 2019 (in millions) Asset (Liability) Natural gas collars (Mmbtu) 2019 (April through December) NYMEX 2.8 $ 2.85 $ 3.13 $ 264 2020 NYMEX 49.4 $ 2.51 $ 2.97 $ (1,298 ) Natural gas deferred premium put options (Mmbtu) 2020 NYMEX 25.1 $ 2.41 N/A $ (394 ) (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. The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018: For the Three Months Ended March 31, Commodity Derivatives (in thousands): 2019 2018 Realized gain (loss) on commodity derivatives - natural gas (1) $ (81,203 ) $ 1,446 Realized gain (loss) on commodity derivatives - oil (1) 2,572 (370 ) Unrealized gain (loss) on commodity derivatives (1) 14,292 (7,606 ) Total gain (loss) on commodity derivatives $ (64,339 ) $ (6,530 ) (1) Included in Loss on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	8. FAIR VALUE MEASUREMENTS: As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories: Level 1 : Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has 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 $ — $ 10,985 $ — $ 10,985 Long-term derivative asset (1) — 5,715 — 5,715 Total derivative instruments $ — $ 16,700 $ — $ 16,700 Liabilities: Current derivative liability $ — $ 38,483 $ — $ 38,483 Long-term derivative liability (2) — 6,756 — 6,756 Total derivative instruments $ — $ 45,239 $ — $ 45,239 (1) Included in Other assets in the Condensed Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Condensed 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 Revolving Credit Facility. We believe that all of our counterparties are of substantial credit quality. Other than as provided in our Revolving Credit Facility, 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 March 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 7 for additional details on 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 estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, restricted cash, 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. March 31, 2019 December 31, 2018 Principal Estimated Principal Estimated repayment obligation Fair Value repayment obligation Fair Value Credit Facility, secured, due January 2022 $ 38,000 $ 38,000 $ 104,000 $ 104,000 Term Loan, secured, due April 2024 975,068 840,996 975,000 858,000 Second Lien Notes, secured, due July 2024 575,149 342,616 545,000 395,125 6.875% Notes, unsecured, due April 2022 150,439 50,021 195,035 68,262 7.125% Notes, unsecured, due April 2025 225,000 49,500 225,000 69,750 Total debt $ 1,963,656 $ 1,321,133 $ 2,044,035 $ 1,495,137

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Leases	9. LEASES The Company has operating leases for corporate offices, drilling rigs, the Company’s 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 Three Months Ended March 31, 2019 Operating lease cost $ 5,255 Variable lease cost (1) $ 1,694 Short-term lease cost (2) $ 9,910 Total lease cost (3) $ 16,859 (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 is significant as it 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. (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: March 31, 2019 Operating Leases Operating lease right-of-use assets $ 127,861 Operating lease liabilities $ 11,261 Long-term operating lease liabilities 116,613 Total operating lease liabilities $ 127,874 Weighted Average Remaining Lease Term Operating leases 8.6 years Weighted Average Discount Rate Operating leases 7.91 % The following table provides supplemental cash flow information related to the Company’s operating leases: For the Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5,242 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 For the year ending December 31, 2019 (remaining) $ 15,646 2020 20,853 2021 20,750 2022 20,327 2023 19,719 Thereafter 78,239 Total lease payments $ 175,534 Less: imputed interest (47,660 ) Total $ 127,874

Commitments and contingencies

Commitments and contingencies	3 Months Ended
	Mar. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	10. COMMITMENTS AND CONTINGENCIES: Litigation Matters Pending Claims – Ultra Resources Indebtedness On April 29, 2016, the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the U.S. Code in the U.S. 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 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 Quarterly Report on Form 10-Q, the claims resolution process associated with our 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 postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Company’s emergence from bankruptcy, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, the Company distributed $399.0 million from a $400.0 million reserve fund set up in connection with our emergence from chapter 11 proceedings to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate. The Company appealed the court order denying its objections to these claims to the U.S. Court of Appeals for the Fifth Circuit (the “Appellate Court”). During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company. On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to the asserted make-whole and post-petition interest claims and remanding the matter and those determinations to the Bankruptcy Court for further reconsideration. As of March 31, 2019, there were approximately $260 million of claims subject to the Appellate Court decision. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimate disposition of these matters at this time. Royalties On April 19, 2016, the Company received a preliminary determination notice from the U.S. Department of the Interior’s Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under federal oil and gas leases. ONRR also filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims related to these matters. We disputed the preliminary determination and the proof of claim. We have notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice, and we continue to be in discussions with ONRR related to these matters. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material. 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 Pinedale, Wyoming. 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 resolution of all such pending or threatened litigation is not likely to have a material adverse effect on our financial position or results of operations.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	11. SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to March 31, 2019 for material events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation: The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All inter-company transactions and balances have been eliminated.
Cash and Cash Equivalents	Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash	Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. The Company follows Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash
Accounts Receivable, net	Accounts Receivable, net: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. As of March 31, 2019, the allowance for uncollectible accounts was $9.0 million. The carrying amount of the Company’s accounts receivable approximates fair value due to the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.
Property, Plant and Equipment	Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.
Oil and Natural Gas Properties	Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. 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 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. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the three months ended March 31, 2019 or 2018.
Inventories	Inventories: Inventory primarily includes $17.2 million in pipe and production equipment that will be utilized during the 2019-2020 drilling programs and $1.1 million in crude oil inventory as of March 31, 2019. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost.
Deferred Financing Costs ("DFC")	Deferred Financing Costs (“DFC”): The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs for its borrowings under the Term Loan Agreement (as defined below), Second Lien Notes and 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
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Condensed Consolidated Balance Sheets and records the changes in the fair value of its commodity derivatives in the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 7 for additional details.
Income Taxes	Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.
Warrants	Warrants : In December 2018, the Company issued 10,919,499 Warrants. The Warrants are initially exercisable for one common share of Ultra Petroleum Corp., no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the common shares is at least $2.50 per common share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof 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. Under the guidance in FASB ASC 815, the Warrants do not meet the definition of a derivative. The Warrants are classified as equity and recorded at fair value as of the date of issuance on the Company’s Consolidated Balance Sheets and no further adjustments to their valuation are made.
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 payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator using the treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. The following table provides a reconciliation of components of basic and diluted net income per common share: For the Three Months Ended March 31, 2019 2018 (Share amounts in 000's) Net income $ 40,674 $ 47,493 Weighted average common shares outstanding - basic 197,383 196,550 Effect of dilutive instruments 418 — Weighted average common shares outstanding - diluted 197,801 196,550 Net income per common share - basic $ 0.21 $ 0.24 Net income per common share - fully diluted $ 0.21 $ 0.24
Use of Estimates	Use of Estimates: Preparation of condensed consolidated financial statements in accordance with 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. Beginning as of January 1, 2019, the Company revised its estimate of administrative costs associated with its operations and classified as Lease operating expenses on the consolidated statement of operations. During 2018 and 2019, the Company has taken steps to drive efficiencies through its operations which resulted in its overhead costs being less than the inflation adjustment to the overhead rates set by the Council of Petroleum Accountants Societies (“COPAS”). Accordingly, the Company reduced the amount of costs categorized as Lease operating expenses, with General and administrative expenses absorbing a larger portion of the total costs.
Accounting for Share-Based Compensation	Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.
Fair Value Accounting	Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional details.
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 Condensed Consolidated Balance Sheets.
Leases	Leases: The Company adopted ASU 2016-02, , 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 not be provided for dates and periods prior to 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 condensed 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 tested 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. Additionally, 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 (as defined below).
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.
Other Revenues	Other Revenues : Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed .
Capital Cost Accrual	Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.
Reclassifications	Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.
Recently Adopted Accounting Pronouncements	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 condensed consolidated balance sheets but did not have an effect on the Company’s condensed consolidated income statements. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 9 for additional discussion. Cumulative Effect of Recently Adopted Accounting Pronouncements: The following table reflects the cumulative impact of the adoption of ASC 842 using the modified retrospective approach. December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (Amounts 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 stockholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and stockholders' 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): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements. Financial Instruments. In June 2016, The FASB issued ASU 2016-13, "Financial Instruments—Credit Losses (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. ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. Early adoption is permitted for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are currently assessing the impact ASU 2016-13 will have on our Consolidated Financial Statements.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2019
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: For the Three Months Ended March 31, 2019 2018 (Share amounts in 000's) Net income $ 40,674 $ 47,493 Weighted average common shares outstanding - basic 197,383 196,550 Effect of dilutive instruments 418 — Weighted average common shares outstanding - diluted 197,801 196,550 Net income per common share - basic $ 0.21 $ 0.24 Net income per common share - fully diluted $ 0.21 $ 0.24
ASC 842
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 using the modified retrospective approach. December 31, 2018 as reported Impact of ASC 842 January 1, 2019 as adjusted (Amounts 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 stockholders' equity (deficit) (1,048,622 ) 92,818 (955,804 ) Total liabilities and stockholders' equity (deficit) 1,733,288 130,649 1,863,937

Oil and Gas Properties and Eq_2

Oil and Gas Properties and Equipment (Tables)	3 Months Ended
	Mar. 31, 2019
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties and Equipment	March 31, December 31, 2019 2018 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,670,425 $ 11,577,281 Less: Accumulated depletion, depreciation and amortization (10,127,259 ) (10,079,554 ) Oil and gas properties, net $ 1,543,166 $ 1,497,727

Long Term Debt (Tables)

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2019
Outstanding Debt And Other Long Term Obligations Tables [Abstract]
Summary of Debt Instruments	The following tables summarize the Company’s debt instruments as of March 31, 2019 and December 31, 2018: March 31, 2019 Principal repayment obligation (1) Unamortized DFC and discounts (2) Unamortized premium Carrying value Credit Facility, secured, due January 2022 $ 38,000 $ — $ — $ 38,000 Term Loan, secured, due April 2024 975,068 (25,807 ) — 949,261 Second Lien Notes, secured, due July 2024 575,149 — 235,941 811,090 6.875% Notes, unsecured, due April 2022 150,439 (14,189 ) — 136,250 7.125% Notes, unsecured, due April 2025 225,000 (14,165 ) — 210,835 Total debt $ 1,963,656 $ (54,161 ) $ 235,941 $ 2,145,436 Less: Current maturities (9,750 ) — — (9,750 ) Total long-term debt, net $ 1,953,906 $ (54,161 ) $ 235,941 $ 2,135,686 (1) Includes PIK interest on the Term Loan and Second Lien Notes of $0.1 million and $3.1 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 repayment obligation Unamortized DFC and discounts (1) Unamortized premium Carrying value Credit Facility, 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% Notes, unsecured, due April 2022 195,035 (15,168 ) — 179,867 7.125% Notes, unsecured, due April 2025 225,000 (14,608 ) — 210,392 Total debt $ 2,044,035 $ (56,650 ) $ 228,096 $ 2,215,481 Less: Current maturities (7,313 ) — — (7,313 ) Total long-term debt, net $ 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.

Share Based Compensation (Table

Share Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Valuation and Expense Information	Valuation and Expense Information For the Three Months Ended March 31, 2019 2018 Total cost of share-based payment plans $ 1,127 $ 10,910 Amounts capitalized in oil and gas properties and equipment $ 286 $ 2,100 Amounts charged against income, before income tax benefit $ 841 $ 8,810 Amount of related income tax benefit recognized in income before valuation allowance $ 177 $ 1,850

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	At March 31, 2019, Company had the following open commodity derivative contracts to manage commodity price risks. Type/Year Index Total Volumes Weighted Average Price per Unit Fair Value - March 31, 2019 (in millions) Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2019 (April through December) NYMEX-Henry Hub 137.8 $ 2.77 $ (2,079 ) 2020 NYMEX-Henry Hub 24.6 2.78 (5,439 ) Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2019 (April through December) NW Rockies Basis Swap 90.2 $ 0.58 $ (18,734 ) 2020 NW Rockies Basis Swap 7.7 0.15 770 Crude oil fixed price swaps (Bbl) ($/Bbl) 2019 (April through December) NYMEX-WTI 1.0 $ 58.64 $ (1,680 ) 2020 NYMEX-WTI 0.1 60.05 51 Type/Year Index Total Volumes Weighted Average Floor Price ($/MMBTU) Weighted Average Ceiling Price ($/MMBTU) Fair Value - March 31, 2019 (in millions) Asset (Liability) Natural gas collars (Mmbtu) 2019 (April through December) NYMEX 2.8 $ 2.85 $ 3.13 $ 264 2020 NYMEX 49.4 $ 2.51 $ 2.97 $ (1,298 ) Natural gas deferred premium put options (Mmbtu) 2020 NYMEX 25.1 $ 2.41 N/A $ (394 ) (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.
Summary of Pre-tax Realized and Unrealized Gain (Loss) Recognized Related to Derivative Instruments	The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018: For the Three Months Ended March 31, Commodity Derivatives (in thousands): 2019 2018 Realized gain (loss) on commodity derivatives - natural gas (1) $ (81,203 ) $ 1,446 Realized gain (loss) on commodity derivatives - oil (1) 2,572 (370 ) Unrealized gain (loss) on commodity derivatives (1) 14,292 (7,606 ) Total gain (loss) on commodity derivatives $ (64,339 ) $ (6,530 ) (1) Included in Loss on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 10,985 $ — $ 10,985 Long-term derivative asset (1) — 5,715 — 5,715 Total derivative instruments $ — $ 16,700 $ — $ 16,700 Liabilities: Current derivative liability $ — $ 38,483 $ — $ 38,483 Long-term derivative liability (2) — 6,756 — 6,756 Total derivative instruments $ — $ 45,239 $ — $ 45,239 (1) Included in Other assets in the Condensed Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Condensed Consolidated Balance Sheet.
Carrying Values and Estimated Fair Values of Financial Instruments	March 31, 2019 December 31, 2018 Principal Estimated Principal Estimated repayment obligation Fair Value repayment obligation Fair Value Credit Facility, secured, due January 2022 $ 38,000 $ 38,000 $ 104,000 $ 104,000 Term Loan, secured, due April 2024 975,068 840,996 975,000 858,000 Second Lien Notes, secured, due July 2024 575,149 342,616 545,000 395,125 6.875% Notes, unsecured, due April 2022 150,439 50,021 195,035 68,262 7.125% Notes, unsecured, due April 2025 225,000 49,500 225,000 69,750 Total debt $ 1,963,656 $ 1,321,133 $ 2,044,035 $ 1,495,137

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Components of Lease Cost	The following table summarizes the components of lease cost: For the Three Months Ended March 31, 2019 Operating lease cost $ 5,255 Variable lease cost (1) $ 1,694 Short-term lease cost (2) $ 9,910 Total lease cost (3) $ 16,859 (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 is significant as it 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. (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: March 31, 2019 Operating Leases Operating lease right-of-use assets $ 127,861 Operating lease liabilities $ 11,261 Long-term operating lease liabilities 116,613 Total operating lease liabilities $ 127,874 Weighted Average Remaining Lease Term Operating leases 8.6 years Weighted Average Discount Rate Operating leases 7.91 %
Supplemental Cash Flow Information Related to Operating Leases	The following table provides supplemental cash flow information related to the Company’s operating leases: For the Three Months Ended March 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 5,242
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 For the year ending December 31, 2019 (remaining) $ 15,646 2020 20,853 2021 20,750 2022 20,327 2023 19,719 Thereafter 78,239 Total lease payments $ 175,534 Less: imputed interest (47,660 ) Total $ 127,874

Debt Exchanges - Additional Inf

Debt Exchanges - Additional Information (Details) - Ultra Resources, Inc. - Exchange Agreement - USD ($) $ / shares in Units, $ in Millions	Dec. 21, 2018	Dec. 31, 2018	Feb. 28, 2019	Dec. 31, 2018
Debt Conversion [Line Items]
Warrants issued on exchange	10,919,499	10,919,499		10,919,499
Warrants exercise price	$ 0.01	$ 0.01		$ 0.01
Number of common stock issued upon exercise of each warrant	1	1		1
6.875% Senior, Unsecured Notes Due 2022
Debt Conversion [Line Items]
Aggregate principal amount of debt exchanged	$ 505		$ 44.6	$ 505
Aggregate principal amount of debt exchanged, percentage	72.10%			72.10%
Stated interest rate	6.875%
Debt conversion, original debt, due date, year	2022
Principal amount of new debt instrument issued for exchange			27
7.125% Senior, Unsecured Notes Due 2025
Debt Conversion [Line Items]
Aggregate principal amount of debt exchanged	$ 275			$ 275
Aggregate principal amount of debt exchanged, percentage	55.00%			55.00%
Stated interest rate	7.125%
Debt conversion, original debt, due date, year	2025
Senior Secured Second Lien Notes due July 2024
Debt Conversion [Line Items]
Principal amount of new debt instrument issued for exchange	$ 545		$ 27
Debt issued on exchange, paid in kind interest rate percentage	2.00%
Debt issued on exchange, interest rate	9.00%
Debt issued on exchange, maturity date	2024-07

Significant Accounting Polici_4

Significant Accounting Policies - Additional Information (Details) - USD ($)	Dec. 21, 2018	Dec. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts			$ 9,000,000
Discount rate future net revenues			10.00%
Ceiling test limitation			$ 0	$ 0
Inventory		$ 18,757,000	$ 18,277,000		$ 18,757,000
Common share, no par value
Contingently issuable shares			19,200,000	2,800,000
Maximum
Significant Accounting Policies [Line Items]
Lease term			1 year
Ultra Resources, Inc. | Exchange Agreement
Significant Accounting Policies [Line Items]
Warrants issued on exchange	10,919,499	10,919,499			10,919,499
Number of common stock issued upon exercise of each warrant	1	1			1
Initial exercise price	$ 0.01	$ 0.01			$ 0.01
Volume-weighted average price of the common shares for warrants exercise		$ 2.50			$ 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 expiration date		Jul. 14, 2025			Jul. 14, 2025
Pipe and Production Equipment
Significant Accounting Policies [Line Items]
Inventory			$ 17,200,000
Crude Oil Inventory
Significant Accounting Policies [Line Items]
Inventory			$ 1,100,000

Significant Accounting Polici_5

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
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share Reconciliation [Abstract]
Net income	$ 40,674	$ 47,493
Weighted average common shares outstanding - basic	197,383	196,550
Effect of dilutive instruments	418
Weighted average common shares outstanding - diluted	197,801	196,550
Net income per common share - basic	$ 0.21	$ 0.24
Net income per common share - fully diluted	$ 0.21	$ 0.24

Significant Accounting Polici_6

Significant Accounting Policies - Schedule of Cumulative Impact of Adoption of ASC 842 Using Retrospective Approach (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Long-term right-of-use assets	$ 127,861
Total assets	1,834,368		$ 1,733,288
Lease liabilities (current)	11,261
Deferred gain on sale of liquids gathering system			94,636
Long-term lease liabilities	116,613
Total liabilities	2,748,371		2,781,910
Retained earnings (loss)	(3,052,524)		(3,186,016)
Total stockholders' equity (deficit)	(914,003)		(1,048,622)	$ (1,096,734)	$ (1,154,636)
Total liabilities and stockholders' equity (deficit)	$ 1,834,368		$ 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 stockholders' equity (deficit)		(955,804)
Total liabilities and stockholders' 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 stockholders' equity (deficit)		92,818
Total liabilities and stockholders' equity (deficit)		$ 130,649

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details)	3 Months Ended
	Mar. 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.

Oil and Gas Properties and Eq_3

Oil and Gas Properties and Equipment - Schedule of Oil and Gas Properties and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Proven Properties:
Acquisition, equipment, exploration, drilling and abandonment costs	$ 11,670,425	$ 11,577,281
Less: Accumulated depletion, depreciation and amortization	(10,127,259)	(10,079,554)
Oil and gas properties, net	$ 1,543,166	$ 1,497,727

Long Term Debt - Summary of Deb

Long Term Debt - Summary of Debt Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Principal repayment obligation	$ 1,963,656	$ 2,044,035
Unamortized DFC and discounts	(54,161)	(56,650)
Unamortized premium	235,941	228,096
Carrying value	2,145,436	2,215,481
Principal repayment obligation, Current Maturities	(9,750)	(7,313)
Carrying Value, Current maturities	(9,750)	(7,313)
Principal repayment obligation, Total long-term debt, net	1,953,906	2,036,722
Unamortized DFC and discounts, Total long-term debt, net	(54,161)	(56,650)
Unamortized premium, Total long-term debt, net	235,941	228,096
Total long-term debt, net	2,135,686	2,208,168
Credit Facility, Secured Due January 2022
Debt Instrument [Line Items]
Principal repayment obligation	38,000	104,000
Carrying value	38,000	104,000
Term Loan, Secured, Due April 2024
Debt Instrument [Line Items]
Principal repayment obligation	975,068	975,000
Unamortized DFC and discounts	(25,807)	(26,874)
Carrying value	949,261	948,126
Second Lien Notes, Secured, Due July 2024
Debt Instrument [Line Items]
Principal repayment obligation	575,149	545,000
Unamortized premium	235,941	228,096
Carrying value	811,090	773,096
6.875% Notes, Unsecured, Due April 2022
Debt Instrument [Line Items]
Principal repayment obligation	150,439	195,035
Unamortized DFC and discounts	(14,189)	(15,168)
Carrying value	136,250	179,867
7.125% Notes, Unsecured, Due April 2025
Debt Instrument [Line Items]
Principal repayment obligation	225,000	225,000
Unamortized DFC and discounts	(14,165)	(14,608)
Carrying value	$ 210,835	$ 210,392

Long Term Debt - Summary of D_2

Long Term Debt - Summary of Debt Instruments (Parenthetical) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Payable-in-Kind (“PIK”) interest payable	$ 3,183
Credit Facility, 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	$ 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	$ 3,100
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%

Long Term Debt - Ultra Resource

Long Term Debt - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Feb. 14, 2019	Dec. 31, 2018	Nov. 30, 2018
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,963,656		$ 2,044,035
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity	325,000	$ 325,000
Long-term debt, gross	38,000
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base		1,300,000
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Letters of Credit
Debt Instrument [Line Items]
Amount of commitments available for the issuance of letters of credit	$ 50,000
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Interest rate description	The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00.
Minimum required consolidated net leverage ratio, as percentage	400.00%
Interest rate on minimum required consolidated net leverage ratio exceeds 4.00 to 1.00	0.25%
Maximum required consolidated net leverage ratio, as percentage	400.00%
Maturity date	Jan. 12, 2022
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Minimum
Debt Instrument [Line Items]
Variable rate	2.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Maximum
Debt Instrument [Line Items]
Variable rate	3.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Minimum
Debt Instrument [Line Items]
Variable rate	1.50%
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Maximum
Debt Instrument [Line Items]
Variable rate	2.50%
Ultra Resources, Inc. | Credit Agreement | Barclays Bank PLC
Debt Instrument [Line Items]
Long-term debt, gross		975,000
Ultra Resources, Inc. | Third Amendment
Debt Instrument [Line Items]
Percentage of collateral coverage			95.00%	85.00%
Ultra Resources, Inc. | Credit Agreement Fourth Amendment | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base		$ 1,300,000
Next scheduled borrowing base redeterminations date	Oct. 31, 2019
Ultra Resources, Inc. | Credit Agreement Fourth Amendment | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Minimum required interest coverage ratio, as percentage	250.00%
Minimum required current ratio, as percentage	100.00%
Minimum required asset coverage ratio, as percentage on achievement of investment grade	150.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019	475.00%
Maximum required consolidated net leverage ratio, as percentage, for each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020	490.00%
Maximum required consolidated net leverage ratio, as percentage, for fiscal quarter ending September 30, 2020	450.00%
Maximum required consolidated net leverage ratio, as percentage, the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter	425.00%
Consolidated net leverage ratio	411.00%
Consolidated interest coverage ratio	326.00%
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Net leverage ratio through September 29, 2019, minimum required hedging percentage	65.00%
Net leverage ratio beginning on September 30, 2019 and ending on March 30, 2020, minimum required hedging percentage	50.00%
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Net leverage ratio through September 29, 2019, minimum required hedging percentage	65.00%
Net leverage ratio beginning on September 30, 2019 and ending on March 30, 2020, minimum required hedging percentage	50.00%

Long Term Debt - Ultra Resour_2

Long Term Debt - Ultra Resources, Inc. - Term Loan - Additional Information (Details) - USD ($) $ in Thousands	Apr. 30, 2017	Dec. 31, 2018	Mar. 31, 2019
Debt Instrument [Line Items]
Principal repayment obligation		$ 2,044,035	$ 1,963,656
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024
Debt Instrument [Line Items]
Debt, original issue discount as percentage on principal	1.00%
Principal repayment obligation			$ 975,100
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 March 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 2024 | LIBOR
Debt Instrument [Line Items]
Variable rate			4.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Base Rate
Debt Instrument [Line Items]
Variable rate			3.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement
Debt Instrument [Line Items]
Variable rate		1.00%
Percentage of collateral coverage	85.00%	95.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement | Until December 21, 2019
Debt Instrument [Line Items]
Debt instrument call protection percentage		102.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Exchange Agreement | Until December 21, 2020
Debt Instrument [Line Items]
Debt instrument call protection percentage		101.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Cash Notes | Exchange Agreement
Debt Instrument [Line Items]
Variable rate		0.75%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Payment in Kind (PIK) Note | Base Rate
Debt Instrument [Line Items]
Variable rate			0.25%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Payment in Kind (PIK) Note | Exchange Agreement
Debt Instrument [Line Items]
Variable rate		0.25%

Long Term Debt - Ultra Resour_3

Long Term Debt - Ultra Resources, Inc. - Second Lien Notes - Additional Information (Details) - USD ($) $ in Thousands	Dec. 21, 2018	Feb. 28, 2019	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Principal repayment obligation			$ 1,963,656	$ 2,044,035
Ultra Resources, Inc.
Debt Instrument [Line Items]
Repurchase price percentage			101.00%
6.875% Senior, Unsecured Notes Due 2022 | Ultra Resources, Inc.
Debt Instrument [Line Items]
Interest payment terms			The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity.
6.875% Senior, Unsecured Notes Due 2022 | Ultra Resources, Inc. | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange		$ 27,000
Aggregate principal amount of debt exchanged	$ 505,000	44,600		505,000
Principal repayment obligation			$ 150,400
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc.
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.
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc. | Maximum
Debt Instrument [Line Items]
Redemption price percentage of aggregate principal amount			35.00%
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc. | Twelve-Month Period Beginning December 21, 2021
Debt Instrument [Line Items]
Redemption price percentage of principal amount			105.50%
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc. | Twelve-Month Period Beginning December 21, 2022
Debt Instrument [Line Items]
Redemption price percentage of principal amount			102.75%
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc. | Twelve-Month Period Beginning December 21, 2023
Debt Instrument [Line Items]
Redemption price percentage of principal amount			100.00%
Second Lien Notes, Secured, Due 2024 | Ultra Resources, Inc. | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt issued on exchange	$ 545,000	$ 27,000
Aggregate principal amount of debt exchanged				$ 545,000
Principal repayment obligation			$ 575,100
Maturity date	Jul. 12, 2024
Debt issued on exchange, interest rate	9.00%
Debt issued on exchange, paid in kind interest rate percentage	2.00%
Interest payment terms			The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019.

Long Term Debt - Ultra Resour_4

Long Term Debt - Ultra Resources, Inc. - Unsecured Notes - Additional Information (Details) - USD ($)	Dec. 21, 2018	Dec. 31, 2018	Feb. 28, 2019	Mar. 31, 2019	Dec. 31, 2018	Apr. 12, 2017
Debt Instrument [Line Items]
Aggregate principal amounts outstanding		$ 2,044,035,000		$ 1,963,656,000	$ 2,044,035,000
Ultra Resources, Inc. | Exchange Agreement
Debt Instrument [Line Items]
Warrants issued on exchange	10,919,499	10,919,499			10,919,499
Number of common stock issued upon exercise of each warrant	1	1			1
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Debt instrument, face amount						$ 700,000,000
Interest payment terms				The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity.
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged	$ 505,000,000		$ 44,600,000		$ 505,000,000
Aggregate principal amount of debt exchanged, percentage	72.10%				72.10%
Aggregate principal amounts outstanding				$ 150,400,000
Aggregate principal amount of debt issued on exchange			27,000,000
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Debt instrument, face amount						$ 500,000,000
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged	$ 275,000,000				$ 275,000,000
Aggregate principal amount of debt exchanged, percentage	55.00%				55.00%
Aggregate principal amounts outstanding				225,000,000
Ultra Resources, Inc. | Second Lien Notes, Secured, Due 2024 | Exchange Agreement
Debt Instrument [Line Items]
Aggregate principal amount of debt exchanged					$ 545,000,000
Aggregate principal amounts outstanding				$ 575,100,000
Aggregate principal amount of debt issued on exchange	$ 545,000,000		$ 27,000,000
Interest payment terms				The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019.

Share Based Compensation - Sche

Share Based Compensation - Schedule of Valuation and Expense Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of share-based payment plans	$ 1,127	$ 10,910
Amounts capitalized in oil and gas properties and equipment	286	2,100
Amounts charged against income, before income tax benefit	841	8,810
Amount of related income tax benefit recognized in income before valuation allowance	$ 177	$ 1,850

Share Based Compensation - Addi

Share Based Compensation - Additional Information (Details) - USD ($)	Jun. 08, 2018	Apr. 12, 2017	Jul. 31, 2018	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				$ 841,000	$ 8,810,000
Long Term Incentive Award
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance period				3 years
Performance Shares | Stock Incentive Plan 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percent of equity reserved for directors, officers and other employees		7.50%
Performance Shares | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting description						During 2017, management incentive plan grants (the “Initial MIP Grants”) were made to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, such Initial MIP Grants shall automatically expire.
Performance Shares | Management Incentive Plan | 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		$ 6,000,000,000
Performance Shares | Management Incentive Plan | 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		$ 6,000,000,000
Percentage of enterprise value		110.00%
Performance Shares | Amendment and Restatement of Stock Incentive Plan 2017 | Outside Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive awards available for grant value, maximum limit during a single calendar year	$ 750,000
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					8,800,000
Stock-Based Compensation Cost | General And Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				$ 800,000
Stock-Based Compensation Cost | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans					$ 8,600,000

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details)	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Statutory tax rate	21.00%

Derivative Financial Instrume_3

Derivative Financial Instruments - Additional Information (Details) - Bank Of Montreal - Revolving Credit Facility - Ultra Resources, Inc. - Second Amendment	3 Months Ended
	Mar. 31, 2019
Derivative [Line Items]
Hedging percentage on proved producing natural gas production for 18 months through September 29, 2019	65.00%
Hedging percentage on proved producing forecast for natural gas through March 30, 2020	50.00%
Maximum
Derivative [Line Items]
Hedging percentage on proved producing natural gas production for 18 months through September 29, 2019	65.00%
Hedging percentage on proved producing forecast for natural gas through March 30, 2020	50.00%
Line of credit facility maximum hedging percentage on forecast production for all products	85.00%

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands, bbl in Millions, MMBTU in Millions	3 Months Ended
	Mar. 31, 2019USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2018USD ($)
Derivative [Line Items]
Fair Value Asset	$ 10,985	$ 23,374
Fair Value (Liability)	$ (38,483)	$ (62,350)
Commodity Derivative Contract Fixed Price Swaps Two | Crude Oil
Derivative [Line Items]
Year	2020
Index	NYMEX-WTI
Total Volumes | MMBTU	0.1
Weighted Average Price per Unit | $ / MMBTU	60.05
Fair Value Asset	$ 51
Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas
Derivative [Line Items]
Year	2020
Index	NYMEX-Henry Hub
Total Volumes | MMBTU	24.6
Weighted Average Price per Unit | $ / MMBTU	2.78
Fair Value (Liability)	$ (5,439)
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	2019 (April through December)
Index	NYMEX-WTI
Total Volumes | bbl	1
Weighted Average Price per Unit | $ / bbl	58.64
Fair Value (Liability)	$ (1,680)
Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Year	2019 (April through December)
Index	NYMEX-Henry Hub
Total Volumes | MMBTU	137.8
Weighted Average Price per Unit | $ / MMBTU	2.77
Fair Value (Liability)	$ (2,079)
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	2019 (April through December)
Index	NW Rockies Basis Swap
Total Volumes | MMBTU	90.2
Weighted Average Price per Unit | $ / MMBTU	0.58
Fair Value (Liability)	$ (18,734)
Commodity Derivative Basis Swap Contracts Two | Natural Gas
Derivative [Line Items]
Year	2020
Index	NW Rockies Basis Swap
Total Volumes | MMBTU	7.7
Weighted Average Price per Unit | $ / MMBTU	0.15
Fair Value Asset	$ 770
Commodity Derivative Contract Collars | Natural Gas
Derivative [Line Items]
Type	Natural gas collars
Commodity Derivative Contract Collars One | Natural Gas
Derivative [Line Items]
Year	2019 (April through December)
Index	NYMEX
Total Volumes | MMBTU	2.8
Weighted Average Floor Price | $ / MMBTU	2.85
Weighted Average Ceiling Price | $ / MMBTU	3.13
Fair Value Asset	$ 264
Commodity Derivative Contract Collars Two | Natural Gas
Derivative [Line Items]
Year	2020
Index	NYMEX
Total Volumes | MMBTU	49.4
Weighted Average Floor Price | $ / MMBTU	2.51
Weighted Average Ceiling Price | $ / MMBTU	2.97
Fair Value (Liability)	$ (1,298)
Commodity Derivative Contract Deferred Premium Put Options | Natural Gas
Derivative [Line Items]
Type	Natural gas deferred premium put options
Commodity Derivative Contract Deferred Premium Put Options One | Natural Gas
Derivative [Line Items]
Year	2020
Index	NYMEX
Total Volumes | MMBTU	25.1
Weighted Average Floor Price | $ / MMBTU	2.41
Fair Value (Liability)	$ (394)

Derivative Financial Instrume_5

Derivative Financial Instruments - Summary of Pre-tax Realized and Unrealized Gain (Loss) Recognized Related to Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives	$ 14,292	$ (7,606)
Total gain (loss) on commodity derivatives	(64,339)	(6,530)
Commodity Derivative Contract
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives	14,292	(7,606)
Total gain (loss) on commodity derivatives	(64,339)	(6,530)
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	(81,203)	1,446
Commodity Derivative Contract | Oil
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	$ 2,572	$ (370)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		$ 10,985	$ 23,374
Long-term derivative asset	[1]	5,715
Total derivative instruments		16,700
Current derivative liability		38,483	$ 62,350
Long-term derivative liability	[2]	6,756
Total derivative instruments		45,239
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		10,985
Long-term derivative asset	[1]	5,715
Total derivative instruments		16,700
Current derivative liability		38,483
Long-term derivative liability	[2]	6,756
Total derivative instruments		$ 45,239
[1]	Included in Other assets in the Condensed Consolidated Balance Sheet.
[2]	Included in Other long-term obligations in the Condensed 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	Mar. 31, 2019	Dec. 31, 2018
Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	$ 1,963,656	$ 2,044,035
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	1,321,133	1,495,137
Credit Facility, Secured Due January 2022 | Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility	38,000	104,000
Credit Facility, Secured Due January 2022 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility	38,000	104,000
Term Loan, Secured, Due April 2024 | Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	975,068	975,000
Term Loan, Secured, Due April 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	840,996	858,000
Second Lien Notes, Secured, Due July 2024 | Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	575,149	545,000
Second Lien Notes, Secured, Due July 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	342,616	395,125
6.875% Notes, Unsecured, Due April 2022 | Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	150,439	195,035
6.875% Notes, Unsecured, Due April 2022 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	50,021	68,262
7.125% Notes, Unsecured, Due April 2025 | Principal Repayment Obligation
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	225,000	225,000
7.125% Notes, Unsecured, Due April 2025 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	$ 49,500	$ 69,750

Fair Value Measurements - Car_2

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Credit Facility, Secured Due January 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2022-01
Term Loan, Secured, Due April 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2024-04
Second Lien Notes, Secured, Due July 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2024-07
6.875% Notes, Unsecured, Due April 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2022-04
Stated interest rate	6.875%	6.875%
7.125% Notes, Unsecured, Due April 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2025-04
Stated interest rate	7.125%	7.125%

Leases - Additional Information

Leases - Additional Information (Details)	3 Months Ended
	Mar. 31, 2019
Minimum
Lessee Lease Description [Line Items]
Lessee, operating lease, remaining lease term	1 year
Maximum
Lessee Lease Description [Line Items]
Lessee, operating lease, remaining lease term	9 years

Leases - Summary of Components

Leases - Summary of Components of Lease Cost (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 5,255
Variable lease cost	1,694
Short-term lease cost	9,910
Total lease cost	$ 16,859

Leases - Summary of Supplementa

Leases - Summary of Supplemental Balance Sheet Information Related to Operating Leases (Details) $ in Thousands	Mar. 31, 2019USD ($)
Operating Leases
Operating lease right-of-use assets	$ 127,861
Operating lease liabilities	11,261
Long-term operating lease liabilities	116,613
Total operating lease liabilities	$ 127,874
Weighted Average Remaining Lease Term
Operating leases	8 years 7 months 6 days
Weighted Average Discount Rate
Operating leases	7.91%

Leases - Summary of Supplemen_2

Leases - Summary of Supplemental Cash Flow Information Related to Operating Leases (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 5,242

Leases - Summary of Fixed, Futu

Leases - Summary of Fixed, Future Minimum Rental Payments Excluding Variable Costs, for Operating Lease Liabilities (Details) $ in Thousands	Mar. 31, 2019USD ($)
Operating Lease Liabilities Payments Due [Abstract]
2019 (remaining)	$ 15,646
2020	20,853
2021	20,750
2022	20,327
2023	19,719
Thereafter	78,239
Total lease payments	175,534
Less: imputed interest	(47,660)
Total	$ 127,874

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	Oct. 06, 2017	Apr. 19, 2016	Dec. 31, 2018	Mar. 31, 2019	Apr. 14, 2017
Loss Contingencies [Line Items]
Claims settled	$ 399
Bankruptcy claims, undistributed amount returned	1.3
Bankruptcy claims amount of claims settled, make-whole fees	223.8
Bankruptcy claims amount of claims settled, postpetition interest	175.2
Claims subject to Appellate Court decision				$ 260
Settlement Agreements
Loss Contingencies [Line Items]
Settlement agreement, amount claimants agreed to pay			$ 16.4
Indebtedness Claims | Notes holders
Loss Contingencies [Line Items]
Claim reserve account after emergence from bankruptcy					$ 400
Claim reserve account after effective date	$ 400
Royalties | ONRR
Loss Contingencies [Line Items]
Bankruptcy claims amount		$ 35.1