Ultra Petroleum 10-Q 10 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 25, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	1,022,646
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		197,053,583
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Trading Symbol	UPL

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Natural gas sales	$ 181,462	$ 188,851
Oil sales	41,284	31,348
Other revenues	2,628	759
Total operating revenues	225,374	220,958
Expenses:
Lease operating expenses	21,764	23,136
Facility lease expense	6,156	5,226
Production taxes	23,270	22,132
Gathering fees	23,055	20,929
Depletion, depreciation and amortization	50,540	31,753
General and administrative	12,688	1,051
Total operating expenses	137,473	104,227
Operating income	87,901	116,731
Other income (expense), net:
Interest expense	(35,837)	(85,447)
Loss on commodity derivatives	(6,530)	(13,218)
Deferred gain on sale of liquids gathering system	2,638	2,638
Contract settlement expense		(52,707)
Other income (expense), net	(245)	(147)
Total other (expense) income, net	(39,974)	(148,881)
Reorganization items, net		(57,546)
Income (loss) before income tax provision	47,927	(89,696)
Income tax provision	434	2
Net income (loss)	$ 47,493	$ (89,698)
Basic earnings (loss) per share:
Net income (loss) per common share - basic	$ 0.24	$ (1.12)
Fully diluted earnings (loss) per share:
Net income (loss) per common share - fully diluted	$ 0.24	$ (1.12)
Weighted average common shares outstanding - basic	196,550	80,018
Weighted average common shares outstanding - fully diluted	196,550	80,018

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 17,782	$ 16,631
Restricted cash	1,573	1,638
Oil and gas revenue receivable	69,638	86,487
Joint interest billing and other receivables	20,603	16,616
Derivative assets	25,118	16,865
Income tax receivable	6,431	10,091
Inventory	18,962	13,450
Other current assets	4,161	5,647
Total current assets	164,268	167,425
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,415,948	1,325,068
Property, plant and equipment, net	10,215	9,569
Other assets	14,959	10,920
Total assets	1,605,390	1,512,982
Current liabilities:
Accounts payable	54,688	59,951
Accrued liabilities	72,628	80,268
Production taxes payable	74,974	51,352
Interest payable	41,578	24,406
Derivative liabilities	21,036
Capital cost accrual	24,434	32,513
Total current liabilities	289,338	248,490
Long-term debt	2,118,515	2,116,211
Deferred gain on sale of liquids gathering system	102,551	105,189
Other long-term obligations	191,721	197,728
Total liabilities	2,702,125	2,667,618
Commitments and contingencies (Note 9)
Shareholders' equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 197,053,583 and 196,346,736 at March 31, 2018 and December 31, 2017, respectively	2,126,727	2,116,018
Treasury stock	(49)	(49)
Retained loss	(3,223,413)	(3,270,605)
Total shareholders' deficit	(1,096,735)	(1,154,636)
Total liabilities and shareholders' equity	$ 1,605,390	$ 1,512,982

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Common stock, No par value
Common stock, Shares authorized	Unlimited	Unlimited
Common stock, Shares issued	197,053,583	196,346,736
Common stock, Shares outstanding	197,053,583	196,346,736

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Retained Loss	Treasury Stock
Beginning Balances at Dec. 31, 2016	$ (2,928,151)	$ 510,063	$ (3,438,165)	$ (49)
Beginning Balances, Shares at Dec. 31, 2016		80,017
Equitization of Holdco Notes	978,230	$ 978,230
Equitization of Holdco Notes, Shares		70,579
Rights Offering, including Backstop	573,774	$ 573,774
Rights Offering, including Backstop, Shares		44,390
Employee stock plan grants, Shares		10
Stock plan grants	26,673	$ 26,673
Stock plan grants, Shares		2,191
Net share settlements	(9,580)		(9,580)
Net share settlements, Shares		(840)
Fair value of employee stock plan grants	27,278	$ 27,278
Net income	177,140		177,140
Ending Balances at Dec. 31, 2017	(1,154,636)	$ 2,116,018	(3,270,605)	(49)
Ending Balances, Shares at Dec. 31, 2017		196,347
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
Net income	47,493		47,493
Initial adoption of ASC 606	1,760		1,760
Ending Balances at Mar. 31, 2018	$ (1,096,735)	$ 2,126,727	$ (3,223,413)	$ (49)
Ending Balances, Shares at Mar. 31, 2018		197,054

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities - cash provided by (used in):
Net income (loss)	$ 47,493	$ (89,698)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion, depreciation and amortization	50,540	31,753
Unrealized loss on commodity derivatives	7,606	13,218
Deferred gain on sale of liquids gathering system	(2,638)	(2,638)
Stock compensation	8,810	851
Non-cash reorganization items, net		43,576
Amortization of deferred financing costs	2,727
Other	209	172
Net changes in operating assets and liabilities:
Accounts receivable	12,561	14,680
Other current assets	2,485	203
Other non-current assets	30
Accounts payable	(5,263)	22,968
Accrued liabilities	(7,486)	38,691
Production taxes payable	23,622	18,512
Interest payable	17,172	85,339
Other long-term obligations	(12,708)	(8,292)
Income taxes payable/receivable	6,836	2,099
Net cash provided by operating activities	151,996	171,434
Investing Activities - cash provided by (used in):
Oil and gas property expenditures	(134,500)	(89,360)
Change in capital cost accrual	(8,079)	(919)
Inventory	(5,074)	(2,302)
Purchase of capital assets	(1,196)	(234)
Net cash used in investing activities	(148,849)	(92,815)
Financing activities - cash provided by (used in):
Repurchased shares/net share settlements	(2,061)	(44)
Net cash used in financing activities	(2,061)	(44)
Increase in cash during the period	1,086	78,575
Cash, cash equivalents, and restricted cash, beginning of period	18,269	405,049
Cash, cash equivalents and restricted cash, end of period	19,355	$ 483,624
Credit Agreement
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement	191,000
Payments under Credit Agreement	$ (191,000)

Description of the Business

Description of the Business	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of the Business	DESCRIPTION OF THE BUSINESS: Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming and its oil reserves in the Uinta Basin in Utah.

Significant Accounting Policies

Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	1. SIGNIFICANT ACCOUNTING POLICIES: The accompanying financial statements, other than the balance sheet data as of December 31, 2017, are unaudited and were prepared from the Company’s records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, 2017 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by GAAP and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K. (a) Basis of Presentation and Principles of Consolidation: (b) Cash and Cash Equivalents: (c) Restricted Cash: The Company follows ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Current Presentation March 31, 2018 March 31, 2017 Cash and Cash Equivalents $ 17,782 $ 479,978 Restricted Cash 1,573 3,646 Total cash, cash equivalents, and restricted cash $ 19,355 $ 483,624 (d) Accounts Receivable: (e) Property, Plant and Equipment: (f) Oil and Natural Gas Properties: 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 (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the quarter ended March 31, 2018 or 2017. (g) Inventories: (h) Deferred Financing Costs: Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (i) Derivative Instruments and Hedging Activities: (j) Income Taxes: (k) Earnings Per Share: 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. For the quarter ended March 31, 2018, the Company had 2.8 million contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met. See Note 5 for additional details. There were no contingently issuable shares outstanding for the quarter ended March 31, 2017. For the Quarter Ended March 31, 2018 2017 (Share amounts in 000's) Net income (loss) $ 47,493 $ (89,698 ) Weighted average common shares outstanding - basic 196,550 80,018 Effect of dilutive instruments (1) — — Weighted average common shares outstanding - diluted 196,550 80,018 Net income (loss) per common share - basic $ 0.24 $ (1.12 ) Net income (loss) per common share - diluted $ 0.24 $ (1.12 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — (1) Due to the net loss for the quarter ended March 31, 2017, 0.5 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share. (l) Use of Estimates: (m) Accounting for Share-Based Compensation: (n) Fair Value Accounting: (o) Asset Retirement Obligation: (p) Revenue Recognition: (q) Other revenues Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed (r) Capital Cost Accrual: (s) Reclassifications: (t) Recent Accounting Pronouncements: Leases. In February 2016, the FASB issued ASU 2016-02, (“ASU No. 2016-02”). The guidance requires that lessees will be required 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. The ASU will also require 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. In January 2018, the FASB issued ASU No. 2018-01, (“ASU No. 2018-01”), which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired before the entity’s adoption of this ASU and that were not previously accounted for as leases. For public companies, the standards will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 and ASU No. 2018-01 on its consolidated financial statements . Stock Compensation . In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The Company adopted ASU 2017-09 on January 1, 2018 and is still evaluating the impact on the Company’s consolidated financial statements. Derivatives. In August 2017, the FASB issued ASU 2017-12, (“ASU No. 2017-12”), which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, and in 2016, the FASB issued ASU 2016-08, , and ASU 2016-10, , which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the cumulative impact of adopting Topic 606, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances. The impact to revenues for the quarter ended March 31, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

Impact of ASC 606 Adoption

Impact of ASC 606 Adoption	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Impact of ASC 606 Adoption	2. In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for the quarter ended March 31, 2018 is as follows: For the Quarter Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 181,462 $ 181,516 $ (54 ) Oil sales 41,284 41,284 — Other revenues 2,628 2,628 — Total operating revenues 225,374 225,428 (54 ) Costs and expenses: Production taxes 23,270 23,275 (5 ) Gathering fees 23,055 23,061 (6 ) Net income $ 47,493 $ 47,536 $ (43 ) The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method. The Company evaluated the contracts for sales of oil and natural gas utilizing the principal vs agent indicators, noting no change in revenue recognition resulted from the analysis. Revenue Recognition Revenue from Contracts with Customers Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies. Natural gas sales We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take 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. In conjunction with the adoption of ASC 606, for the quarter ended March 31, 2018, there was no material impact to the consolidated financial statements for natural gas sales. Oil sales We sell oil production at (a) the lease automatic custody transfer (LACT) meter for Wyoming condensate, (b) the tank battery for Utah wax/condensate, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Consolidated Statement of Operations. In conjunction with the adoption of ASC 606, for the quarter ended March 31, 2018, there was no change to the method used to recognize oil sales and there was no impact to the consolidated financial statements for oil sales. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the oil production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Other revenues Our other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred upon completion of the processing service. The Company is considered the principal and revenue is recognized at the point in time that the control is transferred. In conjunction with the adoption of ASC 606, for the quarter ended March 31, 2018, there was no change to the method used to recognize other processing revenues and there was no impact to the consolidated financial statements for other revenues. Production imbalances Previously, the Company elected to utilize the entitlements method to account for natural gas imbalances, which is no longer allowed under ASC 606. In conjunction with the adoption of ASC 606, for the quarter ended March 31, 2018, there was no material impact to the consolidated financial statements due to this change in accounting for our production imbalances. Transaction price allocated to remaining performance obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. 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 quarter ended March 31, 2018, 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, 2018
Oil And Gas Property [Abstract]
Oil and Gas Properties and Equipment	3. OIL AND GAS PROPERTIES AND EQUIPMENT: March 31, December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,353,426 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (9,937,478 ) (9,890,495 ) $ 1,415,948 $ 1,325,068

Debt and Other Long-Term Obliga

Debt and Other Long-Term Obligations	3 Months Ended
	Mar. 31, 2018
Long Term Liabilities [Abstract]
Debt and other long term liabilities	4. DEBT AND OTHER LONG-TERM OBLIGATIONS: March 31, December 31, 2018 2017 Total Debt: Term loan, secured due 2024 $ 975,000 $ 975,000 6.875% Senior, unsecured Notes due 2022 700,000 700,000 7.125% Senior, unsecured Notes due 2025 500,000 500,000 Credit Agreement — — Long-term debt 2,175,000 2,175,000 Less: Deferred financing costs (56,485 ) (58,789 ) Total long-term debt $ 2,118,515 $ 2,116,211 Other long-term obligations: Other long-term obligations $ 191,721 $ 197,728 Ultra Resources, Inc. Credit Agreement. In April 2017, Ultra Resources, Inc. (“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, and with the other lenders party thereto from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Agreement (defined below)). In September 2017, the administrative agent and the other lenders approved an increase in the borrowing base under the Credit Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the Revolving Credit Facility to an aggregate amount of $425.0 million. At March 31, 2018, Ultra Resources had no outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $425.0 million and a borrowing base of $1.4 billion. As previously disclosed in the Company’s Current Report on Form 8-K filed on April 20, 2018, Ultra Resources, the Bank of Montreal, as administrative agent, and the other lenders party thereto, entered into an amendment to the Credit Agreement (the “Second Amendment”), dated April 19, 2018, which among other things, reaffirmed the borrowing base at $1.4 billion. There are no scheduled borrowing base redeterminations until October 1, 2018. As of April 25, 2018, lender commitments remain at $425.0 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 Company has currently utilized $34.5 million of the commitments available for the issuance of a letter of credit associated with the sale of the Pennsylvania assets that occurred during the fourth quarter of 2017. 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. The interest rate remained the same for the Revolving Credit Facility subsequent to the approved commitments increase noted above. The Revolving Credit Facility loans mature on January 12, 2022. The Revolving Credit Facility requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, of 1.00 to 1.00; (iii) a consolidated net leverage ratio of 4.00 to 1.00, as of the last day of each fiscal quarter; and (iv) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At March 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility. As previously disclosed in the Company’s Current Report on Form 8-K filed on April 20, 2018, the Bank of Montreal, as administrative agent, and the other lenders party thereto, approved the Second Amendment, which among other things, amended the consolidated net leverage ratio covenant in the financial covenants portion of the Credit Agreement. The changes to the consolidated net leverage ratio covenant provide that: (i) during the period beginning on the last day of the fiscal quarter ending June 30, 2018 and ending on the last day of the fiscal quarter ending June 30, 2019, the consolidated net leverage ratio cannot exceed 4.50 to 1.00; (ii) during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ending on the last day of the fiscal quarter ending December 31, 2019, the consolidated net leverage ratio cannot exceed 4.25 to 1.00; and (iii) beginning on the last day of the fiscal quarter ending March 31, 2020, the consolidated net leverage ratio cannot exceed 4.00 to 1.00. In addition, pursuant to the Second Amendment, the Company will be subject to certain minimum hedging requirements. During the period (i) beginning on June 30, 2018 and ending on September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volumes of natural gas from proved developed producing (“PDP”) reserves; and (ii) during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projected volumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement. The Second Amendment also amends the definition of the term “Applicable Margin” as such term is used in the Credit Agreement. The changes to the term “Applicable Margin” provide that 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, the interest rate on such borrowings shall be at a per annum 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 with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of the initial term loan. In September 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under the Term Loan Agreement to $975.0 million. 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. The Term Loan Agreement has capacity to increase the commitments subject to certain conditions. At March 31, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement. The Term Loan Agreement bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points. The Term Loan Agreement amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Agreement matures on April 12, 2024. The Term Loan Agreement is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan 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, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement. The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement. Senior Notes . In April 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, and the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture. The Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act. 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 Notes from the issue date until maturity. Prior to April 15, 2019, 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 2022 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 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, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes. Prior to April 15, 2020, 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 2025 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 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, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes. If Ultra Resources experiences certain change of control triggering events as set forth in the Indenture, each holder of the Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus any accrued but unpaid interest to the date of repurchase. The 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 indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At March 31, 2018, Ultra Resources was in compliance with all of its debt covenants under the Notes. The Indenture contains customary events of default. Unless otherwise noted in the Indenture, upon a continuing event of default, the trustee under the Indenture (the “Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to the Company and the Trustee, may, declare the 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 Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Notes to become due and payable. Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

Share Based Compensation

Share Based Compensation	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share Based Compensation	5. SHARE BASED COMPENSATION: Valuation and Expense Information For the Quarter Ended Ended March 31, 2018 2017 Total cost of share-based payment plans $ 10,910 $ 1,211 Amounts capitalized in oil and gas properties and equipment $ 2,100 $ 360 Amounts charged against income, before income tax benefit $ 8,810 $ 851 Amount of related income tax benefit recognized in income before valuation allowance $ 1,850 $ 339 Performance Share Plans : 2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established 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”). During 2017, Management Incentive Plan Grants (the “Initial MIP Grants”) were made to members of the board of directors (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 the fifth anniversary of the Effective Date, as defined in Note 10, such Initial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time. 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 quarter 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. During the quarter ended March 31, 2017, the Company recognized $0.9 million in pre-tax compensation expense, of which $0.7 million related to the awards of restricted stock units under the Company’s 2015 long-term incentive plan. The Company expects the total expense associated with the portion of the Initial MIP Grant that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $21.4 million and the portion of the Initial MIP Grant that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $20.3 million, respectively.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
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 valuation allowances. During the year ended December 31, 2017, the Company recorded an expected benefit for the recovery of the Company’s carryforward Alternative Minimum Tax (“AMT”) credits. During the quarter ended March 31, 2018, the Company recorded income tax expense of approximately $0.4 million related to the Internal Revenue Service effect of a 6.6% sequestration rate on the expected AMT credit. The Company has recorded a valuation allowance against all deferred tax assets as of March 31, 2018. 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 (“TCJA”) was enacted into law. The new legislation, which became effective on January 1, 2018, decreased the U.S. corporate federal income tax rate from 35% to 21%. The TCJA also included a number of provisions, including the elimination of loss carrybacks and limitations on the use of future losses, repeal of the AMT regime, the limitation on the deductibility of certain expenses, including interest expense, and changes in the way that capital costs are recovered. Given the significant complexity of the TCJA and anticipated additional implementation guidance from the Internal Revenue Service, further implications of TCJA may be identified in future periods. Amounts recorded in the consolidated financial statements are provisional.

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2018
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 capital investment program. These types of instruments may include fixed price swaps, costless collars, or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices. The Company’s hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval. During the quarter ended March 31, 2018, the Board approved all commodity derivative hedge contracts for volumes exceeding 50% of forecasted production volumes. Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the 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 Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. Commodity Derivative Contracts: At March 31, 2018, 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. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties . Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Price /MMBTU Fair Value - March 31, 2018 Natural Gas Asset (Liability) Fixed price swaps NYMEX-Henry Hub Apr - Oct 2018 770,000 $ 2.88 $ 13,951 NYMEX-Henry Hub Nov - Dec 2018 290,000 $ 2.87 (1,485 ) NYMEX-Henry Hub Nov 2018 - Mar 2019 350,000 $ 2.95 (2,734 ) NYMEX-Henry Hub Jan - Mar 2019 250,000 $ 3.02 (441 ) NYMEX-Henry Hub Jan - Dec 2019 100,000 $ 2.79 (217 ) NYMEX-Henry Hub Nov 2018 - Dec 2019 70,000 $ 2.80 (377 ) Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Differential /MMBTU Fair Value - March 31, 2018 Natural Gas Asset (Liability) Basis swap contracts (1) NW Rockies Basis Swap Apr - Oct 2018 140,000 $ (0.62 ) $ 4,640 NW Rockies Basis Swap Apr - Dec 2018 50,000 $ (0.65 ) 1,506 NW Rockies Basis Swap Apr 2018- Dec 2019 70,000 $ (0.78 ) (112 ) NW Rockies Basis Swap Jan-Dec 2019 50,000 $ (0.76 ) 488 Type Commodity Reference Price Remaining Contract Period Volume - Bbls/Day Average Price /Bbls Fair Value - March 31, 2018 Crude Oil Asset (Liability) Fixed price swaps NYMEX-WTI Apr - Dec 2018 5,000 $ 60.25 $ (4,075 ) NYMEX-WTI Jan - Mar 2019 3,000 $ 58.76 (422 ) NYMEX-WTI Jan - June 2019 1,000 $ 57.70 (365 ) NYMEX-WTI Jan - Dec 2019 1,000 $ 56.75 (701 ) NYMEX-WTI Apr - June 2019 2,000 $ 58.21 (173 ) NYMEX-WTI July - Sep 2019 1,000 $ 57.75 (34 ) NYMEX-WTI Apr 2018-Mar 2020 1,000 $ 60.05 (88 ) (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. Subsequent to March 31, 2018 and through April 25, 2018, the Company has entered into the following open commodity derivative contracts to manage commodity price risk. Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Price /MMBTU Natural Gas Fixed price swaps NYMEX-Henry Hub Nov 2018-Mar 2019 50,000 $ 2.98 NYMEX-Henry Hub Apr 2019-Mar 2020 50,000 $ 2.77 Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Differential /MMBTU Natural Gas Basis swap contracts (1) NW Rockies Basis Swap May-Oct 2018 70,000 $ (0.77 ) NW Rockies Basis Swap May-Dec 2018 70,000 $ (0.78 ) NW Rockies Basis Swap Dec 2018-Mar 2019 90,000 $ (0.69 ) NW Rockies Basis Swap Jan - Mar 2019 40,000 $ (0.71 ) Type Commodity Reference Price Remaining Contract Period Volume - Bbls/Day Average Price /Bbls Crude Oil Fixed price swaps NYMEX-WTI May-June 2018 500 $ 64.88 NYMEX-WTI June 2018 400 $ 66.40 NYMEX-WTI July-Sep 2018 500 $ 65.23 NYMEX-WTI Oct-Dec 2018 500 $ 63.25 NYMEX-WTI July-Sep 2019 1,000 $ 59.80 (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 Consolidated Statements of Operations for the quarters ended March 31, 2018 and 2017: For the Quarter Ended Ended March 31, Commodity Derivatives: 2018 2017 Realized gain on commodity derivatives - natural gas (1) $ 1,446 $ — Realized loss on commodity derivatives - oil (1) (370 ) — Unrealized loss on commodity derivatives (1) (7,606 ) (13,218 ) Total loss on commodity derivatives $ (6,530 ) $ (13,218 ) (1) Included in Loss on commodity derivatives in the Consolidated Statements of Operations. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
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. Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 25,118 $ — $ 25,118 Long-term derivative asset (1) — 7,697 — 7,697 Total derivative instruments $ — $ 32,815 $ — $ 32,815 Liabilities: Current derivative liability $ — $ 21,036 $ — $ 21,036 Long-term derivative liability (2) — 2,418 — 2,418 Total derivative instruments $ — $ 23,454 $ — $ 23,454 (1) Included in other assets in the Consolidated Balance Sheet. (2) Included in other long-term obligations in the Consolidated Balance Sheet. The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk. Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract. In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties. In addition, each of our current counterparties are lenders under our 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, 2018, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts. 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 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 Company uses available market data and valuation methodologies to estimate the fair value of its debt. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s financial position, results of operations or cash flows. March 31, 2018 December 31, 2017 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Term loan, secured, due April 2024 $ 975,000 $ 972,563 $ 975,000 $ 975,000 6.875% Notes, unsecured, due April 2022, issued 2017 700,000 610,316 700,000 701,750 7.125% Notes, unsecured, due April 2025, issued 2017 500,000 410,000 500,000 505,000 Credit Facility, secured, due January 2022 — — — — $ 2,175,000 $ 1,992,879 $ 2,175,000 $ 2,181,750

Commitments and contingencies

Commitments and contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	9. COMMITMENTS AND CONTINGENCIES: The Plan (defined below) 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. Pending Claims – Ultra Resources Indebtedness Our chapter 11 filings as described in Note 10 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 (as defined in Note 10), asserting various claims against us, including claims for unpaid postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. We disputed the claims made by the holders of the Ultra Resources’ indebtedness for certain make-whole amounts and post-petition interest at the default rates provided for in the prepetition debt agreements. As previously disclosed, on September 22, 2017, the Bankruptcy Court denied our objection to the pending make-whole and postpetition interest claims. Further, on October 6, 2017, the Bankruptcy Court entered an order requiring us to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, we 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 post-petition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate. The Company is appealing the court order denying its objections to these claims, but 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 dispute 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. Oil Sales Contract On April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and on December 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of contract by SPMT during the prepetition period (as amended, the “Sunoco Adversary”). In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters addressed in its proof of claim. Litigation related to this matter is proceeding in the Bankruptcy Court. At this time, we are not able to determine the likelihood or range of damages owed to SPMT, if any, related to this matter, or, if and when such amounts are 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 all these claims 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 routine disputes and allegations is not likely to have a material adverse effect on our financial position or results of operations.

Chapter 11 Proceedings

Chapter 11 Proceedings	3 Months Ended
	Mar. 31, 2018
Reorganizations [Abstract]
Chapter 11 Proceedings	10. CHAPTER 11 PROCEEDINGS Voluntary Reorganization Under Chapter 11 On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp. On February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), on March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization Plan of Reorganization Pursuant to the Plan, the significant transactions that occurred upon our emergence from chapter 11 proceedings were as follows: • On November 21, 2016, we entered into a Plan Support Agreement (as amended, the “PSA”) with certain holders of the Company’s prepetition indebtedness and outstanding common stock as well as a Backstop Commitment Agreement (“BCA”). Pursuant to the BCA, we agreed to conduct a rights offering for new common stock in the Company to be issued upon the effectiveness of the Plan for an aggregate purchase price of $580.0 million (the “Rights Offering”). • On February 8, 2017, we entered into a commitment letter with Barclays Bank PLC (“Barclays”) (as amended, the “Commitment Letter”) pursuant to which, in connection with the consummation of the Plan, Barclays agreed to provide us with secured and unsecured financings in an aggregate amount of up to $2.4 billion (the “Debt Financings”). • On the Effective Date, the principal obligations outstanding of $999.0 million under the prepetition credit agreement and $1.46 billion under the prepetition senior notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under the prepetition credit agreement and the prepetition senior notes were cancelled and extinguished as provided in the Plan. • On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 million related to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full, each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan. • On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy. Fresh Start Accounting As previously disclosed, we were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims. Bankruptcy Claims Resolution Process The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims are not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained. As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed. Costs of Reorganization During 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below. The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the quarter ended March 31, 2017: For the Quarter Ended March 31, 2017 Professional fees $ (57,691 ) Other (1) 145 Total Reorganization items, net $ (57,546 ) (1)

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	11. SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to March 31, 2018 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below. Credit Agreement As previously disclosed in the Company’s Current Report on Form 8-K filed on April 20, 2018, the Bank of Montreal, as administrative agent, and the other parties thereto, approved the Second Amendment to the Credit Agreement, which, among other things, included the following: ( i ) The Borrowing Base (as defined in the Credit Agreement) was reaffirmed at $1.4 billion. (ii) The Consolidated Net Leverage Ratio (the “Leverage Ratio”) covenant was amended to state that: (i) during the period beginning on the last day of the fiscal quarter ending June 30, 2018 and ending on the last day of the fiscal quarter ending June 30, 2019, the Company will not permit the Leverage Ratio to exceed 4.50 to 1.00; (ii) during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ending on the last day of the fiscal quarter ending December 31, 2019, the Company will not permit the Leverage Ratio to exceed 4.25 to 1.00; and (iii) beginning on the last day of the fiscal quarter ending March 31, 2020, the Company will not permit the Leverage Ratio to exceed 4.00 to 1.00. As part of the Second Amendment, the Company will be subject to certain minimum hedging requirements. During the period (i) beginning on June 30, 2018 and ending on September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volume of natural gas from PDP reserves; and (ii) during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projected volume of natural gas from PDP reserves. Beginning on April 1, 2020, the Company will no longer be subject to a minimum hedging requirement. (iii) The Applicable Margin (as defined in the Credit Agreement) was modified to state that if borrowings are outstanding during a period that the Company’s Leverage Ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter, the interest rate on such borrowings shall be at a per annum The summary of the Second Amendment does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Second Amendment, which was filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 20, 2018 and is incorporated by reference herein. Closing of Houston Office On May 10, 2018, the Company announced the closing of the Houston, Texas office and the relocation of the Company’s corporate headquarters from Houston to Englewood, Colorado, effective September 30, 2018. The office closure is expected to result in a workforce reduction impacting up to 14 employees.

Significant Accounting Polici19

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	(a) Basis of Presentation and Principles of Consolidation:
Cash and Cash Equivalents	(b) Cash and Cash Equivalents:
Restricted Cash	(c) Restricted Cash: The Company follows ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Current Presentation March 31, 2018 March 31, 2017 Cash and Cash Equivalents $ 17,782 $ 479,978 Restricted Cash 1,573 3,646 Total cash, cash equivalents, and restricted cash $ 19,355 $ 483,624
Accounts Receivable	(d) Accounts Receivable:
Property, Plant and Equipment	(e) Property, Plant and Equipment:
Oil and Natural Gas Properties	(f) Oil and Natural Gas Properties: 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 (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the quarter ended March 31, 2018 or 2017.
Inventories	(g) Inventories:
Deferred Financing Costs	(h) Deferred Financing Costs: Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
Derivative Instruments and Hedging Activities	(i) Derivative Instruments and Hedging Activities:
Income Taxes	(j) Income Taxes:
Earnings Per Share	(k) Earnings Per Share: 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. For the quarter ended March 31, 2018, the Company had 2.8 million contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met. See Note 5 for additional details. There were no contingently issuable shares outstanding for the quarter ended March 31, 2017. For the Quarter Ended March 31, 2018 2017 (Share amounts in 000's) Net income (loss) $ 47,493 $ (89,698 ) Weighted average common shares outstanding - basic 196,550 80,018 Effect of dilutive instruments (1) — — Weighted average common shares outstanding - diluted 196,550 80,018 Net income (loss) per common share - basic $ 0.24 $ (1.12 ) Net income (loss) per common share - diluted $ 0.24 $ (1.12 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — (1) Due to the net loss for the quarter ended March 31, 2017, 0.5 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.
Use of Estimates	(l) Use of Estimates:
Accounting for Share-Based Compensation	(m) Accounting for Share-Based Compensation:
Fair Value Accounting	(n) Fair Value Accounting:
Asset Retirement Obligation	(o) Asset Retirement Obligation:
Revenue Recognition	(p) Revenue Recognition:
Other Revenues	(q) 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	(r) Capital Cost Accrual:
Reclassifications	(s) Reclassifications:
Recent Accounting Pronouncements	(t) Recent Accounting Pronouncements: Leases. In February 2016, the FASB issued ASU 2016-02, (“ASU No. 2016-02”). The guidance requires that lessees will be required 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. The ASU will also require 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. In January 2018, the FASB issued ASU No. 2018-01, (“ASU No. 2018-01”), which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired before the entity’s adoption of this ASU and that were not previously accounted for as leases. For public companies, the standards will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 and ASU No. 2018-01 on its consolidated financial statements . Stock Compensation . In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The Company adopted ASU 2017-09 on January 1, 2018 and is still evaluating the impact on the Company’s consolidated financial statements. Derivatives. In August 2017, the FASB issued ASU 2017-12, (“ASU No. 2017-12”), which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, and in 2016, the FASB issued ASU 2016-08, , and ASU 2016-10, , which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the cumulative impact of adopting Topic 606, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances. The impact to revenues for the quarter ended March 31, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

Significant Accounting Polici20

Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Reconciliation of Cash, Cash Equivalents, and Restricted Cash	See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statements of Cash Flows. Current Presentation March 31, 2018 March 31, 2017 Cash and Cash Equivalents $ 17,782 $ 479,978 Restricted Cash 1,573 3,646 Total cash, cash equivalents, and restricted cash $ 19,355 $ 483,624
Schedule of Earnings Per Share	For the Quarter Ended March 31, 2018 2017 (Share amounts in 000's) Net income (loss) $ 47,493 $ (89,698 ) Weighted average common shares outstanding - basic 196,550 80,018 Effect of dilutive instruments (1) — — Weighted average common shares outstanding - diluted 196,550 80,018 Net income (loss) per common share - basic $ 0.24 $ (1.12 ) Net income (loss) per common share - diluted $ 0.24 $ (1.12 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares — — (1) Due to the net loss for the quarter ended March 31, 2017, 0.5 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.

Impact of ASC 606 Adoption (Tab

Impact of ASC 606 Adoption (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Standards Update 2014-09
Schedule of Impact of Adoption on Consolidated Income Statement	In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for the quarter ended March 31, 2018 is as follows: For the Quarter Ended March 31, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 181,462 $ 181,516 $ (54 ) Oil sales 41,284 41,284 — Other revenues 2,628 2,628 — Total operating revenues 225,374 225,428 (54 ) Costs and expenses: Production taxes 23,270 23,275 (5 ) Gathering fees 23,055 23,061 (6 ) Net income $ 47,493 $ 47,536 $ (43 )

Oil and Gas Properties and Eq22

Oil and Gas Properties and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties and Equipment	March 31, December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,353,426 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (9,937,478 ) (9,890,495 ) $ 1,415,948 $ 1,325,068

Debt and Other Long-Term Obli23

Debt and Other Long-Term Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Outstanding Debt And Other Long Term Obligations Tables [Abstract]
Summary of Outstanding Debt and Other Long Term Obligations	March 31, December 31, 2018 2017 Total Debt: Term loan, secured due 2024 $ 975,000 $ 975,000 6.875% Senior, unsecured Notes due 2022 700,000 700,000 7.125% Senior, unsecured Notes due 2025 500,000 500,000 Credit Agreement — — Long-term debt 2,175,000 2,175,000 Less: Deferred financing costs (56,485 ) (58,789 ) Total long-term debt $ 2,118,515 $ 2,116,211 Other long-term obligations: Other long-term obligations $ 191,721 $ 197,728

Share Based Compensation (Table

Share Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Valuation and Expense Information	Valuation and Expense Information For the Quarter Ended Ended March 31, 2018 2017 Total cost of share-based payment plans $ 10,910 $ 1,211 Amounts capitalized in oil and gas properties and equipment $ 2,100 $ 360 Amounts charged against income, before income tax benefit $ 8,810 $ 851 Amount of related income tax benefit recognized in income before valuation allowance $ 1,850 $ 339

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Price /MMBTU Fair Value - March 31, 2018 Natural Gas Asset (Liability) Fixed price swaps NYMEX-Henry Hub Apr - Oct 2018 770,000 $ 2.88 $ 13,951 NYMEX-Henry Hub Nov - Dec 2018 290,000 $ 2.87 (1,485 ) NYMEX-Henry Hub Nov 2018 - Mar 2019 350,000 $ 2.95 (2,734 ) NYMEX-Henry Hub Jan - Mar 2019 250,000 $ 3.02 (441 ) NYMEX-Henry Hub Jan - Dec 2019 100,000 $ 2.79 (217 ) NYMEX-Henry Hub Nov 2018 - Dec 2019 70,000 $ 2.80 (377 ) Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Differential /MMBTU Fair Value - March 31, 2018 Natural Gas Asset (Liability) Basis swap contracts (1) NW Rockies Basis Swap Apr - Oct 2018 140,000 $ (0.62 ) $ 4,640 NW Rockies Basis Swap Apr - Dec 2018 50,000 $ (0.65 ) 1,506 NW Rockies Basis Swap Apr 2018- Dec 2019 70,000 $ (0.78 ) (112 ) NW Rockies Basis Swap Jan-Dec 2019 50,000 $ (0.76 ) 488 Type Commodity Reference Price Remaining Contract Period Volume - Bbls/Day Average Price /Bbls Fair Value - March 31, 2018 Crude Oil Asset (Liability) Fixed price swaps NYMEX-WTI Apr - Dec 2018 5,000 $ 60.25 $ (4,075 ) NYMEX-WTI Jan - Mar 2019 3,000 $ 58.76 (422 ) NYMEX-WTI Jan - June 2019 1,000 $ 57.70 (365 ) NYMEX-WTI Jan - Dec 2019 1,000 $ 56.75 (701 ) NYMEX-WTI Apr - June 2019 2,000 $ 58.21 (173 ) NYMEX-WTI July - Sep 2019 1,000 $ 57.75 (34 ) NYMEX-WTI Apr 2018-Mar 2020 1,000 $ 60.05 (88 ) (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. Subsequent to March 31, 2018 and through April 25, 2018, the Company has entered into the following open commodity derivative contracts to manage commodity price risk. Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Price /MMBTU Natural Gas Fixed price swaps NYMEX-Henry Hub Nov 2018-Mar 2019 50,000 $ 2.98 NYMEX-Henry Hub Apr 2019-Mar 2020 50,000 $ 2.77 Type Commodity Reference Price Remaining Contract Period Volume - MMBTU/Day Average Differential /MMBTU Natural Gas Basis swap contracts (1) NW Rockies Basis Swap May-Oct 2018 70,000 $ (0.77 ) NW Rockies Basis Swap May-Dec 2018 70,000 $ (0.78 ) NW Rockies Basis Swap Dec 2018-Mar 2019 90,000 $ (0.69 ) NW Rockies Basis Swap Jan - Mar 2019 40,000 $ (0.71 ) Type Commodity Reference Price Remaining Contract Period Volume - Bbls/Day Average Price /Bbls Crude Oil Fixed price swaps NYMEX-WTI May-June 2018 500 $ 64.88 NYMEX-WTI June 2018 400 $ 66.40 NYMEX-WTI July-Sep 2018 500 $ 65.23 NYMEX-WTI Oct-Dec 2018 500 $ 63.25 NYMEX-WTI July-Sep 2019 1,000 $ 59.80 (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	For the Quarter Ended Ended March 31, Commodity Derivatives: 2018 2017 Realized gain on commodity derivatives - natural gas (1) $ 1,446 $ — Realized loss on commodity derivatives - oil (1) (370 ) — Unrealized loss on commodity derivatives (1) (7,606 ) (13,218 ) Total loss on commodity derivatives $ (6,530 ) $ (13,218 ) (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, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 25,118 $ — $ 25,118 Long-term derivative asset (1) — 7,697 — 7,697 Total derivative instruments $ — $ 32,815 $ — $ 32,815 Liabilities: Current derivative liability $ — $ 21,036 $ — $ 21,036 Long-term derivative liability (2) — 2,418 — 2,418 Total derivative instruments $ — $ 23,454 $ — $ 23,454 (1) Included in other assets in the Consolidated Balance Sheet. (2) Included in other long-term obligations in the Consolidated Balance Sheet.
Carrying Values and Estimated Fair Values of Financial Instruments	March 31, 2018 December 31, 2017 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Term loan, secured, due April 2024 $ 975,000 $ 972,563 $ 975,000 $ 975,000 6.875% Notes, unsecured, due April 2022, issued 2017 700,000 610,316 700,000 701,750 7.125% Notes, unsecured, due April 2025, issued 2017 500,000 410,000 500,000 505,000 Credit Facility, secured, due January 2022 — — — — $ 2,175,000 $ 1,992,879 $ 2,175,000 $ 2,181,750

Chapter 11 Proceedings (Tables)

Chapter 11 Proceedings (Tables)	3 Months Ended
	Mar. 31, 2018
Reorganizations [Abstract]
Schedule of Reorganization Items	The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the quarter ended March 31, 2017: For the Quarter Ended March 31, 2017 Professional fees $ (57,691 ) Other (1) 145 Total Reorganization items, net $ (57,546 ) (1)

Significant Accounting Polici28

Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Cash And Cash Equivalents And Restricted Cash At Carrying Value [Abstract]
Cash and cash equivalents	$ 17,782	$ 16,631	$ 479,978
Restricted Cash	1,573	1,638	3,646
Total cash, cash equivalents, and restricted cash	$ 19,355	$ 18,269	$ 483,624	$ 405,049

Significant Accounting Polici29

Significant Accounting Policies - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Jan. 01, 2018	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Discount rate future net revenues	10.00%
Ceiling test limitation	$ 0	$ 0
Inventory	$ 18,962,000			$ 13,450,000
Contingently issuable shares	2,800,000	0
Addition to retained earnings	$ (3,223,413,000)			$ (3,270,605,000)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Significant Accounting Policies [Line Items]
Addition to retained earnings			$ 1,800,000
Pipe and Production Equipment
Significant Accounting Policies [Line Items]
Inventory	17,400,000
Crude Oil Inventory
Significant Accounting Policies [Line Items]
Inventory	$ 1,600,000

Significant Accounting Polici30

Significant Accounting Policies - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Earnings Per Share Reconciliation [Abstract]
Net income (loss)	$ 47,493	$ (89,698)	$ 177,140
Weighted average common shares outstanding - basic	196,550	80,018
Weighted average common shares outstanding - diluted	196,550	80,018
Net income (loss) per common share - basic	$ 0.24	$ (1.12)
Net income (loss) per common share - diluted	$ 0.24	$ (1.12)

Significant Accounting Polici31

Significant Accounting Policies - Schedule of Earnings Per Share (Parenthetical) (Details) shares in Millions	3 Months Ended
	Mar. 31, 2017shares
Options and Restricted Stock Units
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	0.5

Impact of ASC 606 Adoption - Sc

Impact of ASC 606 Adoption - Schedule of Impact of Adoption on Consolidated Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenues:
Natural gas sales	$ 181,462	$ 188,851
Oil sales	41,284	31,348
Other revenues	2,628
Total operating revenues	225,374	220,958
Expenses:
Production taxes	23,270	22,132
Gathering fees	23,055	20,929
Net income	47,493	$ (89,698)	$ 177,140
Accounting Standards Update 2014-09 | Under ASC 605
Revenues:
Natural gas sales	181,516
Oil sales	41,284
Other revenues	2,628
Total operating revenues	225,428
Expenses:
Production taxes	23,275
Gathering fees	23,061
Net income	47,536
Accounting Standards Update 2014-09 | Increase/ (Decrease)
Revenues:
Natural gas sales	(54)
Total operating revenues	(54)
Expenses:
Production taxes	(5)
Gathering fees	(6)
Net income	$ (43)

Impact of ASC 606 Adoption - Ad

Impact of ASC 606 Adoption - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue, practical expedient in ASC 606-10-50-14	true
Revenue, practical expedient in ASC 606-10-50-14(a), description	For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Oil and Gas Properties and Eq34

Oil and Gas Properties and Equipment - Schedule of Oil and Gas Properties and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Proven Properties:
Acquisition, equipment, exploration, drilling and abandonment costs	$ 11,353,426	$ 11,215,563
Less: Accumulated depletion, depreciation and amortization	(9,937,478)	(9,890,495)
Proven	$ 1,415,948	$ 1,325,068

Debt and Other Long-Term Obli35

Debt and Other Long-Term Obligations - Summary of Outstanding Debt and Other Long Term Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Total Debt:
Long-term debt	$ 2,175,000	$ 2,175,000
Less: Deferred financing costs	(56,485)	(58,789)
Long-term debt	2,118,515	2,116,211
Other long-term obligations:
Other long-term obligations	191,721	197,728
Term Loan Secured Due 2024
Total Debt:
Long-term debt	975,000	975,000
6.875% Senior, Unsecured Notes Due 2022
Total Debt:
Long-term debt	700,000	700,000
7.125% Senior, Unsecured Notes Due 2025
Total Debt:
Long-term debt	$ 500,000	$ 500,000

Debt and Other Long-Term Obli36

Debt and Other Long-Term Obligations - Summary of Outstanding Debt and Other Long Term Obligations (Parenthetical) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Maturity date	Apr. 12, 2024	Apr. 12, 2024
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2022	Apr. 15, 2022
Stated interest rate	6.875%	6.875%
7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2025	Apr. 15, 2025
Stated interest rate	7.125%	7.125%

Debt and Other Long-Term Obli37

Debt and Other Long-Term Obligations - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($)	Apr. 20, 2018	Mar. 31, 2018	Apr. 25, 2018	Apr. 19, 2018	Dec. 31, 2017	Sep. 30, 2017	Apr. 30, 2017
Debt Instrument [Line Items]
Long-term debt, gross		$ 2,175,000,000			$ 2,175,000,000
Second Amendment | Subsequent Event
Debt Instrument [Line Items]
Credit facility, current borrowing capacity			$ 425,000,000
Second Amendment | Bank Of Montreal | Subsequent Event
Debt Instrument [Line Items]
Borrowing Base				$ 1,400,000,000
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity		425,000,000				$ 425,000,000	$ 400,000,000
Long-term debt, gross		0
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base		1,400,000,000				$ 1,400,000,000	$ 1,200,000,000
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		50,000,000
Amount of commitments utilized		$ 34,500,000
Ultra Resources, Inc. | Credit Agreement | 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 consolidated net leverage ratio, as percentage		400.00%
Minimum required asset coverage ratio, as percentage on achievement of investment grade		150.00%
Line of credit facility, covenant compliance		Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.
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. | Second Amendment | Bank Of Montreal | Subsequent Event
Debt Instrument [Line Items]
Borrowing Base				$ 1,400,000,000
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Subsequent Event | Revolving Credit Facility
Debt Instrument [Line Items]
Minimum required consolidated net leverage ratio, as percentage beginning on last day of June 30, 2018 and ending on last day of June 30, 2019	450.00%
Maximum required consolidated net leverage ratio, as percentage beginning on last day of September 30, 2019 and ending on last day of December 31, 2019	425.00%
Maximum required consolidated net leverage ratio, as percentage beginning on last day of March 31, 2020	400.00%
Net leverage ratio beginning on June 30, 2018 and ending on 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%
Interest rate on minimum required consolidated net leverage ratio exceeds 4.00 to 1.00	0.25%

Debt and Other Long Term Obliga

Debt and Other Long Term Obligations - Ultra Resources, Inc. - Term Loan - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Apr. 29, 2017	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017
Debt Instrument [Line Items]
Long-term debt, gross		$ 2,175,000	$ 2,175,000
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Long-term debt, gross		$ 975,000	$ 975,000
Maturity date		Apr. 12, 2024	Apr. 12, 2024
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024
Debt Instrument [Line Items]
Credit Agreement, initial term loan	$ 800,000
Credit Agreement, initial term loan upon emergence from chapter 11	600,000
Credit Agreement, incremental term loan	$ 200,000			$ 175,000
Long-term debt, gross		$ 975,000
Debt, original issue discount as percentage on principal	1.00%
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, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | LIBOR
Debt Instrument [Line Items]
Variable rate		3.00%
Ultra Resources, Inc. | Barclays Bank PLC | Term Loan Secured Due 2024 | Base Rate
Debt Instrument [Line Items]
Variable rate		2.00%

Debt and Other Long Term Obli39

Debt and Other Long Term Obligations - Ultra Resources, Inc. - Senior Notes - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Apr. 12, 2017
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Stated interest rate	6.875%	6.875%
Maturity date	Apr. 15, 2022	Apr. 15, 2022
7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Stated interest rate	7.125%	7.125%
Maturity date	Apr. 15, 2025	Apr. 15, 2025
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 Notes from the issue date until maturity.
Repurchase price percentage	101.00%
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Debt instrument, face amount			$ 700,000,000
Stated interest rate			6.875%
Maturity date	Apr. 15, 2022
Redemption price percentage of principal amount	106.875%
Redemption criteria	If at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering.
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Maximum
Debt Instrument [Line Items]
Redemption price percentage of aggregate principal amount	35.00%
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Twelve-Month Period Beginning on April 15, 2019
Debt Instrument [Line Items]
Redemption price percentage of principal amount	103.438%
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Twelve-Month Period Beginning April 15, 2020
Debt Instrument [Line Items]
Redemption price percentage of principal amount	101.719%
Ultra Resources, Inc. | 6.875% Senior, Unsecured Notes Due 2022 | Twelve-Month Period Beginning April 15, 2021
Debt Instrument [Line Items]
Redemption price percentage of principal amount	100.00%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Debt instrument, face amount			$ 500,000,000
Stated interest rate			7.125%
Maturity date	Apr. 15, 2025
Redemption price percentage of principal amount	107.125%
Redemption criteria	If at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering.
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Maximum
Debt Instrument [Line Items]
Redemption price percentage of aggregate principal amount	35.00%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Twelve-Month Period Beginning April 15, 2020
Debt Instrument [Line Items]
Redemption price percentage of principal amount	105.344%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Twelve-Month Period Beginning April 15, 2021
Debt Instrument [Line Items]
Redemption price percentage of principal amount	103.563%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Twelve-Month Period Beginning April 15, 2022
Debt Instrument [Line Items]
Redemption price percentage of principal amount	101.781%
Ultra Resources, Inc. | 7.125% Senior, Unsecured Notes Due 2025 | Twelve-Month Period Beginning April 15, 2023
Debt Instrument [Line Items]
Redemption price percentage of principal amount	100.00%

Share Based Compensation - Sche

Share Based Compensation - Schedule of Valuation and Expense Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of share-based payment plans	$ 10,910	$ 1,211
Amounts capitalized in oil and gas properties and equipment	2,100	360
Amounts charged against income, before income tax benefit	8,810	851
Amount of related income tax benefit recognized in income before valuation allowance	$ 1,850	$ 339

Share Based Compensation - Addi

Share Based Compensation - Additional Information (Details) - USD ($) $ in Thousands	Apr. 12, 2017	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans		$ 8,810	$ 851
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 of directors (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 the fifth anniversary of the Effective Date, as defined in Note 10, 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
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
Percentage of enterprise value	110.00%
Stock-Based Compensation Cost
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans		$ 8,800	900
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
Stock-Based Compensation Cost | 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]
Total enterprise value		6,000,000
Expected share-based compensation expense		21,400
Stock-Based Compensation Cost | 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]
Total enterprise value		6,600,000
Expected share-based compensation expense		$ 20,300
Stock-Based Compensation Cost | Long Term Incentive Plan 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans			$ 700

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Taxes [Line Items]
Statutory tax rate	21.00%		35.00%
Income tax expense	$ 434	$ 2
Internal Revenue Service
Income Taxes [Line Items]
Income tax expense	$ 400
Sequestration rate based on alternative minimum tax credit	6.60%

Derivative Financial Instrume43

Derivative Financial Instruments - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Maximum
Derivative [Line Items]
Commodity derivatives board authorization	50.00%

Derivative Financial Instrume44

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands		1 Months Ended	3 Months Ended
		Apr. 25, 2018MMBTU$ / MMBTU	Mar. 31, 2018USD ($)MMBTU$ / MMBTU	Dec. 31, 2017USD ($)
Derivative [Line Items]
Liability, Fair Value | $			$ (21,036)
Assets, Fair Value | $			25,118	$ 16,865
Liability, Fair Value | $	[1]		(2,418)
Liability, Fair Value | $			(23,454)
Assets, Fair Value | $			$ 32,815
Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type			Fixed price swaps
Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Nov - Dec 2018
Volume -MMBTU/Day | MMBTU			290,000
Average Price/MMBTU | $ / MMBTU			2.87
Liability, Fair Value | $			$ (1,485)
Commodity Derivative Contract Fixed Price Swaps Three | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Nov 2018 - Mar 2019
Volume -MMBTU/Day | MMBTU			350,000
Average Price/MMBTU | $ / MMBTU			2.95
Liability, Fair Value | $			$ (2,734)
Commodity Derivative Contract Fixed Price Swaps Four | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Jan - Mar 2019
Volume -MMBTU/Day | MMBTU			250,000
Average Price/MMBTU | $ / MMBTU			3.02
Liability, Fair Value | $			$ (441)
Commodity Derivative Contract Fixed Price Swaps Five | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Jan - Dec 2019
Volume -MMBTU/Day | MMBTU			100,000
Average Price/MMBTU | $ / MMBTU			2.79
Liability, Fair Value | $			$ (217)
Commodity Derivative Contract Fixed Price Swaps Six | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Nov 2018 - Dec 2019
Volume -MMBTU/Day | MMBTU			70,000
Average Price/MMBTU | $ / MMBTU			2.80
Liability, Fair Value | $			$ (377)
Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Type			Basis swap contracts
Commodity Derivative Basis Swap Contracts Two | Natural Gas | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NW Rockies Basis Swap
Remaining Contract Period			Apr 2018- Dec 2019
Volume -MMBTU/Day | MMBTU			70,000
Average Differential/MMBTU | $ / MMBTU			(0.78)
Liability, Fair Value | $			$ (112)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps | Derivative Contract, Liabillity
Derivative [Line Items]
Type			Fixed price swaps
Crude Oil | Commodity Derivative Contract Fixed Price Swaps One | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Apr - Dec 2018
Volume -MMBTU/Day | MMBTU			5,000
Average Price/MMBTU | $ / MMBTU			60.25
Liability, Fair Value | $			$ (4,075)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Two | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Jan - Mar 2019
Volume -MMBTU/Day | MMBTU			3,000
Average Price/MMBTU | $ / MMBTU			58.76
Liability, Fair Value | $			$ (422)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Three | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Jan - June 2019
Volume -MMBTU/Day | MMBTU			1,000
Average Price/MMBTU | $ / MMBTU			57.70
Liability, Fair Value | $			$ (365)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Four | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Jan - Dec 2019
Volume -MMBTU/Day | MMBTU			1,000
Average Price/MMBTU | $ / MMBTU			56.75
Liability, Fair Value | $			$ (701)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Five | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Apr - June 2019
Volume -MMBTU/Day | MMBTU			2,000
Average Price/MMBTU | $ / MMBTU			58.21
Liability, Fair Value | $			$ (173)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Six | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			July - Sep 2019
Volume -MMBTU/Day | MMBTU			1,000
Average Price/MMBTU | $ / MMBTU			57.75
Liability, Fair Value | $			$ (34)
Crude Oil | Commodity Derivative Contract Fixed Price Swaps Seven | Derivative Contract, Liabillity
Derivative [Line Items]
Commodity Reference Price			NYMEX-WTI
Remaining Contract Period			Apr 2018-Mar 2020
Volume -MMBTU/Day | MMBTU			1,000
Average Price/MMBTU | $ / MMBTU			60.05
Liability, Fair Value | $			$ (88)
Derivative Contract, Assets | Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Commodity Reference Price			NYMEX-Henry Hub
Remaining Contract Period			Apr - Oct 2018
Volume -MMBTU/Day | MMBTU			770,000
Average Price/MMBTU | $ / MMBTU			2.88
Assets, Fair Value | $			$ 13,951
Derivative Contract, Assets | Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Commodity Reference Price			NW Rockies Basis Swap
Remaining Contract Period			Apr - Oct 2018
Volume -MMBTU/Day | MMBTU			140,000
Average Differential/MMBTU | $ / MMBTU			(0.62)
Assets, Fair Value | $			$ 4,640
Derivative Contract, Assets | Commodity Derivative Basis Swap Contracts One | Natural Gas
Derivative [Line Items]
Commodity Reference Price			NW Rockies Basis Swap
Remaining Contract Period			Apr - Dec 2018
Volume -MMBTU/Day | MMBTU			50,000
Average Differential/MMBTU | $ / MMBTU			(0.65)
Assets, Fair Value | $			$ 1,506
Derivative Contract, Assets | Commodity Derivative Basis Swap Contracts Three | Natural Gas
Derivative [Line Items]
Commodity Reference Price			NW Rockies Basis Swap
Remaining Contract Period			Jan-Dec 2019
Volume -MMBTU/Day | MMBTU			50,000
Average Differential/MMBTU | $ / MMBTU			(0.76)
Assets, Fair Value | $			$ 488
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type		Fixed price swaps
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NYMEX-Henry Hub
Remaining Contract Period		Nov 2018-Mar 2019
Volume -MMBTU/Day | MMBTU		50,000
Average Price/MMBTU | $ / MMBTU		2.98
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NYMEX-Henry Hub
Remaining Contract Period		Apr 2019-Mar 2020
Volume -MMBTU/Day | MMBTU		50,000
Average Price/MMBTU | $ / MMBTU		2.77
Subsequent Event | Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Type		Basis swap contracts
Subsequent Event | Commodity Derivative Basis Swap Contracts One | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NW Rockies Basis Swap
Remaining Contract Period		May-Oct 2018
Volume -MMBTU/Day | MMBTU		70,000
Average Differential/MMBTU | $ / MMBTU		(0.77)
Subsequent Event | Commodity Derivative Basis Swap Contracts Two | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NW Rockies Basis Swap
Remaining Contract Period		May-Dec 2018
Volume -MMBTU/Day | MMBTU		70,000
Average Differential/MMBTU | $ / MMBTU		(0.78)
Subsequent Event | Commodity Derivative Basis Swap Contracts Three | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NW Rockies Basis Swap
Remaining Contract Period		Dec 2018-Mar 2019
Volume -MMBTU/Day | MMBTU		90,000
Average Differential/MMBTU | $ / MMBTU		(0.69)
Subsequent Event | Commodity Derivative Basis Swap Contracts Four | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NW Rockies Basis Swap
Remaining Contract Period		Jan - Mar 2019
Volume -MMBTU/Day | MMBTU		40,000
Average Differential/MMBTU | $ / MMBTU		(0.71)
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps
Derivative [Line Items]
Commodity Reference Price		NYMEX-WTI
Remaining Contract Period		May-June 2018
Volume -MMBTU/Day | MMBTU		500
Average Price/MMBTU | $ / MMBTU		64.88
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps One
Derivative [Line Items]
Commodity Reference Price		NYMEX-WTI
Remaining Contract Period		June 2,018
Volume -MMBTU/Day | MMBTU		400
Average Price/MMBTU | $ / MMBTU		66.40
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps Two
Derivative [Line Items]
Commodity Reference Price		NYMEX-WTI
Remaining Contract Period		July-Sep 2018
Volume -MMBTU/Day | MMBTU		500
Average Price/MMBTU | $ / MMBTU		65.23
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps Three
Derivative [Line Items]
Commodity Reference Price		NYMEX-WTI
Remaining Contract Period		Oct-Dec 2018
Volume -MMBTU/Day | MMBTU		500
Average Price/MMBTU | $ / MMBTU		63.25
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps Four
Derivative [Line Items]
Commodity Reference Price		NYMEX-WTI
Remaining Contract Period		July-Sep 2019
Volume -MMBTU/Day | MMBTU		1,000
Average Price/MMBTU | $ / MMBTU		59.80
[1]	Included in other long-term obligations in the Consolidated Balance Sheet.

Derivative Financial Instrume45

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, 2018	Mar. 31, 2017
Derivative [Line Items]
Unrealized loss on commodity derivatives	$ (7,606)	$ (13,218)
Loss on commodity derivatives	(6,530)	(13,218)
Commodity Derivative Contract
Derivative [Line Items]
Unrealized loss on commodity derivatives	(7,606)	(13,218)
Loss on commodity derivatives	(6,530)	$ (13,218)
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	1,446
Commodity Derivative Contract | Oil
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	$ (370)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands		Mar. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		$ 25,118	$ 16,865
Long-term derivative asset	[1]	7,697
Total derivative instruments		32,815
Current derivative liability		21,036
Long-term derivative liability	[2]	2,418
Total derivative instruments		23,454
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		25,118
Long-term derivative asset	[1]	7,697
Total derivative instruments		32,815
Current derivative liability		21,036
Long-term derivative liability	[2]	2,418
Total derivative instruments		$ 23,454
[1]	Included in other assets in the Consolidated Balance Sheet.
[2]	Included in other long-term obligations in the Consolidated Balance Sheet.

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Details) - Level 2 - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	$ 2,175,000	$ 2,175,000
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	1,992,879	2,181,750
Term Loan, Secured Due April 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	975,000	975,000
Term Loan, Secured Due April 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	972,563	975,000
6.875% Notes, Unsecured, Due April 2022, Issued 2017 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	700,000	700,000
6.875% Notes, Unsecured, Due April 2022, Issued 2017 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	610,316	701,750
7.125% Notes, Unsecured, Due April 2025, Issued 2017 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	500,000	500,000
7.125% Notes, Unsecured, Due April 2025, Issued 2017 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	$ 410,000	$ 505,000

Fair Value Measurements - Car48

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	3 Months Ended
	Mar. 31, 2018
Term Loan, Secured Due April 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2024-04
6.875% Notes, Unsecured, Due April 2022, Issued 2017
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2022-04
Stated interest rate	6.875%
Debt instrument issuance year	2,017
7.125% Notes, Unsecured, Due April 2025, Issued 2017
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2025-04
Stated interest rate	7.125%
Debt instrument issuance year	2,017
Credit Facility Secured Due January 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year	2022-01

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions	Oct. 06, 2017	Aug. 31, 2016	Apr. 29, 2016	Apr. 19, 2016
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
Indebtedness Claims | Notes holders
Loss Contingencies [Line Items]
Claim reserve account after effective date	$ 400
Royalties | ONRR
Loss Contingencies [Line Items]
Bankruptcy claims amount				$ 35.1
Oil Sales Contract | SPMT
Loss Contingencies [Line Items]
Bankruptcy claims amount		$ 16.9
Damage sought			$ 38.6

Chapter 11 Proceedings - Additi

Chapter 11 Proceedings - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Oct. 06, 2017	Apr. 12, 2017	Feb. 08, 2017
Bankruptcy Proceedings [Line Items]
Petition date	Apr. 29, 2016
Court where petition was filed	United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”)
Plan confirmed date	Mar. 14, 2017
Plan expected to be effective date	Apr. 12, 2017
Claims settled		$ 399
Senior Unsecured Notes Due 2018
Bankruptcy Proceedings [Line Items]
Claims settled			$ 450
5.75% Senior Notes Due 2018
Bankruptcy Proceedings [Line Items]
Stated interest rate			5.75%
Senior Unsecured Notes Due 2024
Bankruptcy Proceedings [Line Items]
Claims settled			$ 850
6.125% Senior Notes Due 2024
Bankruptcy Proceedings [Line Items]
Stated interest rate			6.125%
Prepetition Credit Agreement
Bankruptcy Proceedings [Line Items]
Claims settled			$ 999
Prepetition Senior Notes
Bankruptcy Proceedings [Line Items]
Claims settled			1,460
Barclays Bank PLC
Bankruptcy Proceedings [Line Items]
Secured and unsecured financing provided by Barclays				$ 2,400
BCA
Bankruptcy Proceedings [Line Items]
Rights offering, aggregate purchase price			$ 580

Chapter 11 Proceedings - Costs

Chapter 11 Proceedings - Costs of Reorganization (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Reorganization Items [Abstract]
Professional fees	$ (57,691)
Other	145
Total Reorganization items, net	$ (57,546)

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Subsequent Event $ in Billions	May 10, 2018Employee	Apr. 20, 2018	Apr. 19, 2018USD ($)
Houston Office
Subsequent Event [Line Items]
Number of expected reduction in employees | Employee	14
Second Amendment | Bank Of Montreal
Subsequent Event [Line Items]
Borrowing Base			$ 1.4
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal
Subsequent Event [Line Items]
Borrowing Base			$ 1.4
Ultra Resources, Inc. | Second Amendment | Bank Of Montreal | Revolving Credit Facility
Subsequent Event [Line Items]
Minimum required consolidated net leverage ratio, as percentage beginning on last day of June 30, 2018 and ending on last day of June 30, 2019		450.00%
Maximum required consolidated net leverage ratio, as percentage beginning on last day of September 30, 2019 and ending on last day of December 31, 2019		425.00%
Maximum required consolidated net leverage ratio, as percentage beginning on last day of March 31, 2020		400.00%
Net leverage ratio beginning on June 30, 2018 and ending on 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%
Interest rate on minimum required consolidated net leverage ratio exceeds 4.00 to 1.00		0.25%