Ultra Petroleum 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 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	Sep. 30, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		197,053,583
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	UPL

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Total operating revenues	$ 203,776	$ 217,631	$ 619,289	$ 651,247
Expenses:
Lease operating expenses	25,817	23,140	71,226	69,365
Facility lease expense	6,875	5,254	19,557	15,706
Production taxes	20,470	22,482	62,623	66,369
Gathering fees	21,810	22,182	69,046	63,753
Depletion, depreciation and amortization	49,672	41,089	151,954	111,516
General and administrative	1,482	8,247	16,233	34,308
Total operating expenses	126,126	122,394	390,639	361,017
Operating income	77,650	95,237	228,650	290,230
Other income (expense), net:
Interest expense	(38,382)	(210,107)	(111,934)	(324,979)
(Loss) gain on commodity derivatives	(21,804)	4,650	(75,607)	12,149
Deferred gain on sale of liquids gathering system	2,638	2,638	7,915	7,915
Contract settlement expense	(2,676)		(2,676)	(52,707)
Other income (expense), net	1,137	92	(404)	(28)
Total other (expense) income, net	(59,087)	(202,727)	(182,706)	(357,650)
Reorganization items, net		(227,123)		142,147
Income (loss) before income tax provision	18,563	(334,613)	45,944	74,727
Income tax (benefit) provision		(6,886)	442	(6,884)
Net income (loss)	$ 18,563	$ (327,727)	$ 45,502	$ 81,611
Basic earnings (loss) per share:
Net income (loss) per common share - basic	$ 0.09	$ (1.67)	$ 0.23	$ 0.53
Fully diluted earnings (loss) per share:
Net income (loss) per common share - fully diluted	$ 0.09	$ (1.67)	$ 0.23	$ 0.53
Weighted average common shares outstanding - basic	197,054	196,331	196,888	152,864
Weighted average common shares outstanding - fully diluted	197,055	196,331	197,288	153,068
Natural Gas Sales
Revenues:
Total operating revenues	$ 156,986	$ 182,949	$ 479,704	$ 551,797
Oil Sales
Revenues:
Total operating revenues	41,523	32,334	125,974	94,415
Other Revenues
Revenues:
Total operating revenues	$ 5,267	$ 2,348	$ 13,611	$ 5,035

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 13,141	$ 16,631
Restricted cash	1,990	1,638
Oil and gas revenue receivable	65,091	86,487
Joint interest billing and other receivables, net	25,521	16,616
Derivative assets	12,728	16,865
Income tax receivable	6,431	10,091
Inventory	20,202	13,450
Other current assets	2,082	5,647
Total current assets	147,186	167,425
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,459,666	1,325,068
Property, plant and equipment, net	10,876	9,569
Other assets	8,097	10,920
Total assets	1,625,825	1,512,982
Current liabilities:
Accounts payable	29,898	59,951
Accrued liabilities	77,016	80,268
Production taxes payable	72,458	51,352
Current portion of long-term debt	4,875
Interest payable	41,821	24,406
Derivative liabilities	61,926
Capital cost accrual	16,468	32,513
Total current liabilities	304,462	248,490
Long-term debt	2,118,329	2,116,211
Deferred gain on sale of liquids gathering system	97,274	105,189
Other long-term obligations	199,874	197,728
Total liabilities	2,719,939	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 September 30, 2018 and December 31, 2017, respectively	2,131,340	2,116,018
Treasury stock	(49)	(49)
Retained loss	(3,225,405)	(3,270,605)
Total shareholders' deficit	(1,094,114)	(1,154,636)
Total liabilities and shareholders' equity	$ 1,625,825	$ 1,512,982

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 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

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Retained (Loss) Earnings	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	15,322	$ 15,322
Net income	45,502		45,502
Initial adoption of ASC 606	1,759		1,759
Ending Balances at Sep. 30, 2018	$ (1,094,114)	$ 2,131,340	$ (3,225,405)	$ (49)
Ending Balances, Shares at Sep. 30, 2018		197,054

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating activities - cash provided by (used in):
Net income for the period	$ 45,502	$ 81,611
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization	151,954	111,516
Unrealized loss (gain) on commodity derivatives	72,557	(4,133)
Deferred gain on sale of liquids gathering system	(7,915)	(7,915)
Stock compensation	11,547	34,182
Non-cash reorganization items, net		(451,099)
Amortization of deferred financing costs	8,333	4,781
Other	(1,046)	(1,014)
Net changes in operating assets and liabilities:
Accounts receivable	12,057	(91)
Other current assets	4,829	9,356
Other non-current assets	368	173
Accounts payable	(14,396)	38,619
Accrued liabilities	(6,439)	89,481
Production taxes payable	21,192	19,006
Interest payable	17,414	231,553
Other long-term obligations	(8,118)	(2,455)
Income taxes payable/receivable	6,844	(4,787)
Net cash provided by operating activities	314,683	148,784
Investing Activities - cash provided by (used in):
Oil and gas property expenditures	(339,918)	(386,754)
Change in capital cost accrual and accounts payable	(31,703)	20,437
Proceeds from sale of oil and gas properties	65,811
Inventory	(7,572)	(5,477)
Proceeds from sale of capital assets	2,872
Purchase of capital assets	(4,612)	(2,203)
Net cash used in investing activities	(315,122)	(373,997)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement	632,000	479,000
Payments under Credit Agreement	(632,000)	(459,000)
Borrowings under Term Loan		975,000
Extinguishment of long-term debt - (chapter 11)		(2,459,000)
Proceeds from issuance of Senior Notes		1,200,000
Deferred financing costs	(638)	(72,913)
Shares issued, net of transaction costs		573,774
Repurchased shares/net share settlements	(2,061)	(9,581)
Net cash (used in) provided by financing activities	(2,699)	227,280
(Decrease) increase in cash during the period	(3,138)	2,067
Cash, cash equivalents, and restricted cash, beginning of period	18,269	405,049
Cash, cash equivalents and restricted cash, end of period	$ 15,131	$ 407,116

Description of the Business

Description of the Business	9 Months Ended
	Sep. 30, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of the Business	DESCRIPTION OF THE BUSINESS: Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, “us”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming. On September 25, 2018, the Company completed the sale of its Utah assets to an unnamed third party for net cash proceeds of $69.3 million, including management fees of $0.6 million. The divested assets consisted primarily of oil and gas properties.

Significant Accounting Policies

Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Significant Accounting Policies	1. SIGNIFICANT ACCOUNTING POLICIES: The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018. The condensed consolidated balance sheet at December 31, 2017, has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2017. (a) Basis of Presentation and Principles of Consolidation: (b) Cash and Cash Equivalents: (c) Restricted Cash: The Company follows Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Current Presentation September 30, 2018 September 30, 2017 Cash and Cash Equivalents $ 13,141 $ 5,419 Restricted Cash 1,990 401,697 Total cash, cash equivalents, and restricted cash $ 15,131 $ 407,116 (d) Accounts Receivable, net: (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 nine months ended September 30, 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: Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. For the three and nine months ended September 30, 2018, the Company had 4.9 million and 2.5 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. For the Three Months Ended For the Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (Share amounts in 000's) Net income (loss) $ 18,563 $ (327,727 ) $ 45,502 $ 81,611 Weighted average common shares outstanding - basic 197,054 196,331 196,888 152,864 Effect of dilutive instruments 1 — 400 204 Weighted average common shares outstanding - diluted 197,055 196,331 197,288 153,068 Net income (loss) per common share - basic $ 0.09 $ (1.67 ) $ 0.23 $ 0.53 Net income (loss) per common share - fully diluted $ 0.09 $ (1.67 ) $ 0.23 $ 0.53 (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, , and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). 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. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, , the Company does not expect to adjust comparative-period financial statements. To facilitate compliance with ASC 842, the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, initiated the process of reviewing its contract portfolio, and implemented appropriate changes to business systems. The Company will continue to evaluate its processes and internal controls during 2018. Additionally, we are evaluating the disclosure requirements under the new standard to ensure the appropriate information will be available for these disclosures. While we are continuing to assess all potential impacts of the standard, we anticipate recognition of additional assets and corresponding liabilities related to leases. The overall financial impact is continuing to be evaluated by the Company. Stock Compensation . In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s consolidated financial statements. 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. Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements. 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 the new revenue standard, 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 nine months ended September 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying the new revenue standard. 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	9 Months Ended
	Sep. 30, 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 condensed consolidated income statement for the nine months ended September 30, 2018 is as follows: For the Nine Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 479,704 $ 479,915 $ (211 ) Oil sales 125,974 125,974 — Other revenues 13,611 13,611 — Total operating revenues 619,289 619,500 (211 ) Costs and expenses: Production taxes 62,623 62,644 (21 ) Gathering fees 69,046 69,072 (26 ) Net income $ 45,502 $ 45,666 $ (164 ) The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method. The Company evaluated the contracts for sales of oil and natural gas utilizing the principal versus agent indicators, noting no change in revenue recognition resulted from the analysis. Revenue Recognition Revenue from Contracts with Customers Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies. Natural gas sales We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the natural gas production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production. Oil sales We sell oil production at (a) the lease automatic custody transfer (“LACT”) meter for Wyoming condensate, (b) the tank battery for Utah wax/condensate, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations. In conjunction with the adoption of ASC 606, for the nine months ended September 30, 2018, there was no change to the method used to recognize oil sales and there was no impact to the condensed 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 nine months ended September 30, 2018, there was no change to the method used to recognize other processing revenues and there was no impact to the condensed 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 nine months ended September 30, 2018, there was no material impact to the condensed consolidated financial statements due to this change in accounting for our production imbalances. Transaction price allocated to remaining performance obligations A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the nine months ended September 30, 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	9 Months Ended
	Sep. 30, 2018
Oil And Gas Property [Abstract]
Oil and Gas Properties and Equipment	3. OIL AND GAS PROPERTIES AND EQUIPMENT: September 30, December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,491,066 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (10,031,400 ) (9,890,495 ) Oil and gas properties, net $ 1,459,666 $ 1,325,068

Debt and Other Long-Term Obliga

Debt and Other Long-Term Obligations	9 Months Ended
	Sep. 30, 2018
Long Term Liabilities [Abstract]
Debt and other long-term obligations	4. DEBT AND OTHER LONG-TERM OBLIGATIONS: September 30, December 31, 2018 2017 Total Debt: Current portion of long-term debt $ 4,875 $ — Term loan, secured due 2024 $ 970,125 $ 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 — — Total long-term debt 2,170,125 2,175,000 Less: Deferred financing costs (51,796 ) (58,789 ) Total debt, net of deferred financing costs $ 2,123,204 $ 2,116,211 Other long-term obligations: Other long-term obligations $ 199,874 $ 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. In April 2018, the administrative agent and the other lenders reaffirmed the borrowing base at $1.4 billion. In September 2018, the borrowing base was reduced to $1.3 billion in connection with the semi-annual redetermination. At September 30, 2018, Ultra Resources had no outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million and a borrowing base of $1.3 billion. The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility 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 that does not exceed (a) 4.50 to 1.00, during the period ending on the last day of the fiscal quarter ending June 30, 2019, (b) 4.25 to 1.00, 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, and (c) 4.00 to 1.00 beginning on the last day of the fiscal quarter ending on March 31, 2020; and (iv) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility. Under the Revolving Credit Facility, t he Company is subject to the following minimum hedging requirements: t Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees. The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants. The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated. Term Loan. In April 2017 , Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement 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 September 30, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement, including current maturities. 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 September 30, 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 Unsecured 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 “Unsecured 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 Unsecured Notes are treated as a single class of securities under the Indenture. The Unsecured 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 Unsecured 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 Unsecured 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 Unsecured 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 Unsecured 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 Unsecured Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At September 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Unsecured 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 Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable. On October 17, 2018, the Company entered into an exchange agreement relating to the Unsecured Notes, as discussed further in Note 11. 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	9 Months Ended
	Sep. 30, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share Based Compensation	5. SHARE BASED COMPENSATION: Valuation and Expense Information For the Three Months For the Nine Months Ended Ended September 30, Ended September 30, 2018 2017 2018 2017 Total cost of share-based payment plans $ 2,148 $ 10,276 $ 15,321 $ 46,166 Amounts capitalized in oil and gas properties and equipment $ 724 $ 2,358 $ 3,774 $ 11,984 Amounts charged against income, before income tax benefit $ 1,424 $ 7,918 $ 11,547 $ 34,182 Amount of related income tax benefit recognized in income before valuation allowance $ 299 $ 3,151 $ 2,425 $ 13,604 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. On June 8, 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of the 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends and restates the 2017 Stock Incentive Plan to, among other things: • provide that consultants, independent contractors and advisors are eligible to participate and receive equity awards in the A&R Stock Incentive Plan; • limit the aggregate incentive awards available to be granted to any outside director during a single calendar year to a maximum of $750,000; • revise the definition of a Change of Control to exclude a change in a majority of the members on the Board; • provide that, with respect to awards granted on or after June 8, 2018, no such awards will vest solely as a result of a Change of Control (as defined in the A&R Stock Incentive Plan) unless expressly provided otherwise in the applicable grant agreement or unless otherwise determined by the Committee; and • make certain other changes related to revisions to the U.S. Internal Revenue Code. In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvested portion of their Initial MIP Grants for a new equity awards of time-based restricted stock units (the “2018 RSUs”) effective July 31, 2018 on a one-for-one basis. All 2018 RSUs are time-based awards and will vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021. 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 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 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 Initial MIP Grants that include a market condition prior to the modification thereof in July 2018. 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 from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is satisfied. Modification. The incremental expense recognized from the modification was $0.6 million for the three and nine months ended September 30, 2018. Expense. For the nine months ended September 30, 2018, the Company recognized $11.5 million in pre-tax compensation expense, of which $10.9 million related to the Initial MIP Grants and is included within General and administrative expenses on the Condensed Consolidated Statement of Operations. During the nine months ended September 30, 2017, the Company recognized $34.2 million in pre-tax compensation expense, of which $32.9 million related to the Initial MIP Grants.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 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. The Company has recorded a valuation allowance against all deferred tax assets as of September 30, 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 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 Alternative Minimum Tax 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 condensed consolidated financial statements are provisional.

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 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 Condensed Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Condensed Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments. Commodity Derivative Contracts: At September 30, 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 . Year Index Total Volumes Weighted Average Price per Unit Fair Value - September 30, 2018 (in millions) Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2018 (October through December) NYMEX-Henry Hub 60.5 $ 2.88 $ (9,536 ) 2019 NYMEX-Henry Hub 163.9 $ 2.82 (188 ) 2020 NYMEX-Henry Hub 15.5 $ 2.76 (1,673 ) Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2018 (October through December) NW Rockies Basis Swap 51.5 $ (0.66 ) $ (4,170 ) 2019 NW Rockies Basis Swap 84.5 $ (0.70 ) (10,523 ) 2020 NW Rockies Basis Swap — $ — — Crude oil fixed price swaps (Bbl) ($/Bbl) 2018 (October through December) NYMEX-WTI 0.6 $ 60.45 $ (7,472 ) 2019 NYMEX-WTI 1.7 $ 58.83 (21,295 ) 2020 NYMEX-WTI 0.1 $ 60.05 (734 ) (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 September 30, 2018 and through October 25, 2018, the Company entered into the following open commodity derivative contracts to manage commodity price risk. Type Index Remaining Contract Period Volume/MMBTU/Day Weighted Average Floor Price ($/MMBTU) Weighted Average Ceiling Price ($/MMBTU) Collars NYMEX January - March 2020 100,000 2.75 3.18 The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three and six months ended September 30, 2018 and 2017: For the Three Months For the Nine Months Ended September 30, Ended September 30, Commodity Derivatives: 2018 2017 2018 2017 Realized gain (loss) on commodity derivatives - natural gas $ (5,468 ) $ 8,884 $ 6,958 $ 8,016 Realized loss on commodity derivatives - oil (5,318 ) — (10,008 ) — Unrealized gain (loss) on commodity derivatives (11,018 ) (4,234 ) (72,557 ) 4,133 Total gain (loss) on commodity derivatives $ (21,804 ) $ 4,650 $ (75,607 ) $ 12,149 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	9 Months Ended
	Sep. 30, 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 $ — $ 12,728 $ — $ 12,728 Long-term derivative asset (1) — 1,454 — 1,454 Total derivative instruments $ — $ 14,182 $ — $ 14,182 Liabilities: Current derivative liability $ — $ 61,926 $ — $ 61,926 Long-term derivative liability (2) — 7,847 — 7,847 Total derivative instruments $ — $ 69,773 $ — $ 69,773 (1) Included in Other assets in the Condensed Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Condensed Consolidated Balance Sheet. The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk. Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract. In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties. In addition, each of our current counterparties are lenders under our Revolving Credit Facility. We believe that all of our counterparties are of substantial credit quality. Other than as provided in our Revolving Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 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 Condensed Consolidated Balance Sheets for cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The 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 consolidated financial position, results of operations or cash flows. September 30, 2018 December 31, 2017 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Term loan, secured, due April 2024 $ 975,000 $ 877,500 $ 975,000 $ 975,000 6.875% Notes, unsecured, due April 2022, issued 2017 700,000 336,000 700,000 701,750 7.125% Notes, unsecured, due April 2025, issued 2017 500,000 209,210 500,000 505,000 Total debt $ 2,175,000 $ 1,422,710 $ 2,175,000 $ 2,181,750

Commitments and contingencies

Commitments and contingencies	9 Months Ended
	Sep. 30, 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 postpetition 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 postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate. The Company 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. On October 16, 2018, the Company reached a settlement agreement with SPMT. Under the terms of the agreement, the Company will pay SPMT a total of $2.0 million. At September 30, 2018, the Company accrued the payment of $2.0 million and wrote off the related receivable of approximately $0.7 million. 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	9 Months Ended
	Sep. 30, 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 Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017: For the Three Months Ended For the Nine Months Ended September 30, 2017 September 30, 2017 Professional fees $ (3,285 ) $ (65,289 ) Gains (losses) (1) — 431,107 Make-whole fees (223,838 ) (223,838 ) Other (2) — 167 Total Reorganization items, net $ (227,123 ) $ 142,147 (1) Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 Notes and 2024 Notes. (2)

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	11. SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to September 30, 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: • On October 16, 2018, the Company reached a settlement agreement with SPMT. Under the terms of the agreement, the Company will pay SPMT a total of $2.0 million. Refer to Note 9 for additional details. • On October 17, 2018, the Company entered into an agreement (the “Exchange Agreement”) with holders (the “Supporting Noteholders”) of (i) approximately $556.4 million aggregate principal amount, or 79.5%, of the 2022 Notes and (ii) approximately $267.1 million aggregate principal amount, or 53.4%, of the 2025 Notes of Ultra Resources, pursuant to which the Supporting Noteholders have agreed to exchange all of the Unsecured Notes held by each such Supporting Noteholder for (a) new 9.00% Cash / 2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “New Notes”) and (b) new warrants of the Company entitling each holder thereof to purchase one common share of the Company at a price of $0.01 per share (the “Warrants”). For each $1,000 aggregate principal amount of 2022 Notes validly exchanged pursuant to the Exchange Agreement, the Supporting Noteholders will receive (i) $720 aggregate principal amount of New Notes issued by Ultra Resources and (ii) 14.0 Warrants issued by the Company; and, for each $1,000 aggregate principal amount of 2025 Notes validly exchanged pursuant to the Exchange Agreement, the Supporting Noteholders will receive (i) $660 aggregate principal amount of New Notes issued by Ultra Resources and (ii) 14.0 Warrants issued by the Company. Each Warrant will be exercisable at the option of the holders thereof for one common share of the Company, at any time following the date on which the volume-weighted average price of the common shares is at least $2.50 for 30 consecutive trading days. In the aggregate, if all Warrants are exercised, total shareholder dilution will be approximately 6%. The obligations of the Supporting Noteholders under the Exchange Agreement, including their obligation to exchange their 2022 Notes and 2025 Notes pursuant to the exchange transaction, are subject to the conditions set forth in the Exchange Agreement, including: (a) the Company receiving a consent of the requisite lenders under the Credit Agreement to the consummation of the transactions contemplated by the Exchange Agreement; (b) the Company receiving a consent of the requisite lenders under the Term Loan Agreement to the consummation of the transactions contemplated by the Exchange Agreement; (c) entry into a customary intercreditor agreement between the agent for the Credit Agreement, the agent for the Term Loan Agreement and trustee collateral agent for the New Notes; and (d) the execution and delivery of an indenture pursuant to which the New Notes will be governed and other definitive documentation. Accordingly, there can be no assurance if or when the Company will consummate the exchange transaction and the other transactions contemplated by the Exchange Agreement. The Exchange Agreement may be terminated by the Company, on the one hand, or the Supporting Noteholders owning at least a majority in aggregate principal amount of each series of the 2022 Notes and the 2025 Notes, on the other hand, on behalf of the Supporting Noteholders, upon written notice of termination to the other parties, if the closing of the exchange transaction has not occurred on or before November 15, 2018 or by any single Supporting Noteholder, solely with respect to itself, if the closing of the exchange transaction has not occurred on or before December 15, 2018. • Subsequent to September 30, 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $13.2 million to the Company. The Company will continue to pursue its appeal against all non-settled parties. See Note 9 for additional information. • In November 2018, the Company announced the appointment of David Honeyfield as Chief Financial Officer, and Andrew Kidd as Senior Vice President and General Counsel. Mr. Honeyfield and Mr. Kidd succeed Garland Shaw and Garrett Smith respectively, who both did not relocate from Houston following the move of the Company’s headquarters to Englewood, Colorado.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 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 Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash Current Presentation September 30, 2018 September 30, 2017 Cash and Cash Equivalents $ 13,141 $ 5,419 Restricted Cash 1,990 401,697 Total cash, cash equivalents, and restricted cash $ 15,131 $ 407,116
Accounts Receivable, net	(d) Accounts Receivable , net:
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 nine months ended September 30, 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: Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. For the three and nine months ended September 30, 2018, the Company had 4.9 million and 2.5 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. For the Three Months Ended For the Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (Share amounts in 000's) Net income (loss) $ 18,563 $ (327,727 ) $ 45,502 $ 81,611 Weighted average common shares outstanding - basic 197,054 196,331 196,888 152,864 Effect of dilutive instruments 1 — 400 204 Weighted average common shares outstanding - diluted 197,055 196,331 197,288 153,068 Net income (loss) per common share - basic $ 0.09 $ (1.67 ) $ 0.23 $ 0.53 Net income (loss) per common share - fully diluted $ 0.09 $ (1.67 ) $ 0.23 $ 0.53
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, , and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). 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. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11, , the Company does not expect to adjust comparative-period financial statements. To facilitate compliance with ASC 842, the Company has formed an implementation work team, developed a project plan, educated departments affected by the standard, initiated the process of reviewing its contract portfolio, and implemented appropriate changes to business systems. The Company will continue to evaluate its processes and internal controls during 2018. Additionally, we are evaluating the disclosure requirements under the new standard to ensure the appropriate information will be available for these disclosures. While we are continuing to assess all potential impacts of the standard, we anticipate recognition of additional assets and corresponding liabilities related to leases. The overall financial impact is continuing to be evaluated by the Company. Stock Compensation . In May 2017, the FASB issued ASU 2017-09, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s consolidated financial statements. 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. Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for the public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements. 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 the new revenue standard, 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 nine months ended September 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying the new revenue standard. 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 Polici_3

Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 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 Condensed Consolidated Balance Sheets that sum to the total of the same amounts shown in the Condensed Consolidated Statements of Cash Flows. Current Presentation September 30, 2018 September 30, 2017 Cash and Cash Equivalents $ 13,141 $ 5,419 Restricted Cash 1,990 401,697 Total cash, cash equivalents, and restricted cash $ 15,131 $ 407,116
Schedule of Earnings Per Share	For the Three Months Ended For the Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (Share amounts in 000's) Net income (loss) $ 18,563 $ (327,727 ) $ 45,502 $ 81,611 Weighted average common shares outstanding - basic 197,054 196,331 196,888 152,864 Effect of dilutive instruments 1 — 400 204 Weighted average common shares outstanding - diluted 197,055 196,331 197,288 153,068 Net income (loss) per common share - basic $ 0.09 $ (1.67 ) $ 0.23 $ 0.53 Net income (loss) per common share - fully diluted $ 0.09 $ (1.67 ) $ 0.23 $ 0.53

Impact of ASC 606 Adoption (Tab

Impact of ASC 606 Adoption (Tables)	9 Months Ended
	Sep. 30, 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 condensed consolidated income statement for the nine months ended September 30, 2018 is as follows: For the Nine Months Ended September 30, 2018 Under ASC 606 Under ASC 605 Increase/ (Decrease) (Amounts in 000's) Revenues: Natural gas sales $ 479,704 $ 479,915 $ (211 ) Oil sales 125,974 125,974 — Other revenues 13,611 13,611 — Total operating revenues 619,289 619,500 (211 ) Costs and expenses: Production taxes 62,623 62,644 (21 ) Gathering fees 69,046 69,072 (26 ) Net income $ 45,502 $ 45,666 $ (164 )

Oil and Gas Properties and Eq_2

Oil and Gas Properties and Equipment (Tables)	9 Months Ended
	Sep. 30, 2018
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties and Equipment	September 30, December 31, 2018 2017 Proven Properties: Acquisition, equipment, exploration, drilling and abandonment costs $ 11,491,066 $ 11,215,563 Less: Accumulated depletion, depreciation and amortization (10,031,400 ) (9,890,495 ) Oil and gas properties, net $ 1,459,666 $ 1,325,068

Debt and Other Long-Term Obli_2

Debt and Other Long-Term Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Outstanding Debt And Other Long Term Obligations Tables [Abstract]
Summary of Outstanding Debt and Other Long Term Obligations	September 30, December 31, 2018 2017 Total Debt: Current portion of long-term debt $ 4,875 $ — Term loan, secured due 2024 $ 970,125 $ 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 — — Total long-term debt 2,170,125 2,175,000 Less: Deferred financing costs (51,796 ) (58,789 ) Total debt, net of deferred financing costs $ 2,123,204 $ 2,116,211 Other long-term obligations: Other long-term obligations $ 199,874 $ 197,728

Share Based Compensation (Table

Share Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Valuation and Expense Information	Valuation and Expense Information For the Three Months For the Nine Months Ended Ended September 30, Ended September 30, 2018 2017 2018 2017 Total cost of share-based payment plans $ 2,148 $ 10,276 $ 15,321 $ 46,166 Amounts capitalized in oil and gas properties and equipment $ 724 $ 2,358 $ 3,774 $ 11,984 Amounts charged against income, before income tax benefit $ 1,424 $ 7,918 $ 11,547 $ 34,182 Amount of related income tax benefit recognized in income before valuation allowance $ 299 $ 3,151 $ 2,425 $ 13,604

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	Year Index Total Volumes Weighted Average Price per Unit Fair Value - September 30, 2018 (in millions) Asset (Liability) Natural gas fixed price swaps (Mmbtu) ($/Mmbtu) 2018 (October through December) NYMEX-Henry Hub 60.5 $ 2.88 $ (9,536 ) 2019 NYMEX-Henry Hub 163.9 $ 2.82 (188 ) 2020 NYMEX-Henry Hub 15.5 $ 2.76 (1,673 ) Natural gas basis swaps (1) (Mmbtu) ($/Mmbtu) 2018 (October through December) NW Rockies Basis Swap 51.5 $ (0.66 ) $ (4,170 ) 2019 NW Rockies Basis Swap 84.5 $ (0.70 ) (10,523 ) 2020 NW Rockies Basis Swap — $ — — Crude oil fixed price swaps (Bbl) ($/Bbl) 2018 (October through December) NYMEX-WTI 0.6 $ 60.45 $ (7,472 ) 2019 NYMEX-WTI 1.7 $ 58.83 (21,295 ) 2020 NYMEX-WTI 0.1 $ 60.05 (734 ) (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 September 30, 2018 and through October 25, 2018, the Company entered into the following open commodity derivative contracts to manage commodity price risk. Type Index Remaining Contract Period Volume/MMBTU/Day Weighted Average Floor Price ($/MMBTU) Weighted Average Ceiling Price ($/MMBTU) Collars NYMEX January - March 2020 100,000 2.75 3.18
Summary of Pre-tax Realized and Unrealized Gain (Loss) Recognized Related to Derivative Instruments	For the Three Months For the Nine Months Ended September 30, Ended September 30, Commodity Derivatives: 2018 2017 2018 2017 Realized gain (loss) on commodity derivatives - natural gas $ (5,468 ) $ 8,884 $ 6,958 $ 8,016 Realized loss on commodity derivatives - oil (5,318 ) — (10,008 ) — Unrealized gain (loss) on commodity derivatives (11,018 ) (4,234 ) (72,557 ) 4,133 Total gain (loss) on commodity derivatives $ (21,804 ) $ 4,650 $ (75,607 ) $ 12,149

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 12,728 $ — $ 12,728 Long-term derivative asset (1) — 1,454 — 1,454 Total derivative instruments $ — $ 14,182 $ — $ 14,182 Liabilities: Current derivative liability $ — $ 61,926 $ — $ 61,926 Long-term derivative liability (2) — 7,847 — 7,847 Total derivative instruments $ — $ 69,773 $ — $ 69,773 (1) Included in Other assets in the Condensed Consolidated Balance Sheet. (2) Included in Other long-term obligations in the Condensed Consolidated Balance Sheet.
Carrying Values and Estimated Fair Values of Financial Instruments	September 30, 2018 December 31, 2017 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Term loan, secured, due April 2024 $ 975,000 $ 877,500 $ 975,000 $ 975,000 6.875% Notes, unsecured, due April 2022, issued 2017 700,000 336,000 700,000 701,750 7.125% Notes, unsecured, due April 2025, issued 2017 500,000 209,210 500,000 505,000 Total debt $ 2,175,000 $ 1,422,710 $ 2,175,000 $ 2,181,750

Chapter 11 Proceedings (Tables)

Chapter 11 Proceedings (Tables)	9 Months Ended
	Sep. 30, 2018
Reorganizations [Abstract]
Schedule of Reorganization Items	The following table summarizes the components included in Reorganization items, net in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017: For the Three Months Ended For the Nine Months Ended September 30, 2017 September 30, 2017 Professional fees $ (3,285 ) $ (65,289 ) Gains (losses) (1) — 431,107 Make-whole fees (223,838 ) (223,838 ) Other (2) — 167 Total Reorganization items, net $ (227,123 ) $ 142,147 (1) Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 Notes and 2024 Notes. (2)

Description of the Business - A

Description of the Business - Additional Information (Details) - Utah - Unnamed Third Party $ in Millions	Sep. 25, 2018USD ($)
Description Of Business [Line Items]
Net proceeds from sale of assets	$ 69.3
Management fees	$ 0.6

Significant Accounting Polici_4

Significant Accounting Policies - Additional Information (Details) - USD ($) shares in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2015	Jan. 01, 2018	Dec. 31, 2017
Significant Accounting Policies [Line Items]
Discount rate future net revenues				10.00%
Ceiling test limitation		$ 0	$ 0
Inventory	$ 20,202,000	$ 20,202,000				$ 13,450,000
Contingently issuable shares	4.9	2.5
Addition to retained earnings	$ (3,225,405,000)	$ (3,225,405,000)				$ (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	19,000,000	19,000,000
Crude Oil Inventory
Significant Accounting Policies [Line Items]
Inventory	$ 1,200,000	$ 1,200,000
Reserve Fund for Interest Claims
Significant Accounting Policies [Line Items]
Restricted cash			$ 400,000,000

Significant Accounting Polici_5

Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Cash Cash Equivalents Restricted Cash And Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 13,141	$ 16,631	$ 5,419
Restricted Cash	1,990	1,638	401,697
Total cash, cash equivalents, and restricted cash	$ 15,131	$ 18,269	$ 407,116	$ 405,049

Significant Accounting Polici_6

Significant Accounting Policies - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Earnings Per Share Reconciliation [Abstract]
Net income (loss)	$ 18,563	$ (327,727)	$ 45,502	$ 81,611	$ 177,140
Weighted average common shares outstanding - basic	197,054	196,331	196,888	152,864
Effect of dilutive instruments	1		400	204
Weighted average common shares outstanding - diluted	197,055	196,331	197,288	153,068
Net income (loss) per common share - basic	$ 0.09	$ (1.67)	$ 0.23	$ 0.53
Net income (loss) per common share - fully diluted	$ 0.09	$ (1.67)	$ 0.23	$ 0.53

Impact of ASC 606 Adoption - Sc

Impact of ASC 606 Adoption - Schedule of Impact of Adoption on Condensed Consolidated Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Revenues:
Total operating revenues	$ 203,776	$ 217,631	$ 619,289	$ 651,247
Expenses:
Production taxes	20,470	22,482	62,623	66,369
Gathering fees	21,810	22,182	69,046	63,753
Net income	18,563	(327,727)	45,502	81,611	$ 177,140
Natural Gas Sales
Revenues:
Total operating revenues	156,986	182,949	479,704	551,797
Oil Sales
Revenues:
Total operating revenues	41,523	32,334	125,974	94,415
Other Revenues
Revenues:
Total operating revenues	$ 5,267	$ 2,348	13,611	$ 5,035
Accounting Standards Update 2014-09 | Increase/ (Decrease)
Revenues:
Total operating revenues			619,500
Expenses:
Production taxes			62,644
Gathering fees			69,072
Net income			45,666
Accounting Standards Update 2014-09 | Increase/ (Decrease)
Revenues:
Total operating revenues			(211)
Expenses:
Production taxes			(21)
Gathering fees			(26)
Net income			(164)
Accounting Standards Update 2014-09 | Natural Gas Sales | Increase/ (Decrease)
Revenues:
Total operating revenues			479,915
Accounting Standards Update 2014-09 | Natural Gas Sales | Increase/ (Decrease)
Revenues:
Total operating revenues			(211)
Accounting Standards Update 2014-09 | Oil Sales | Increase/ (Decrease)
Revenues:
Total operating revenues			125,974
Accounting Standards Update 2014-09 | Other Revenues | Increase/ (Decrease)
Revenues:
Total operating revenues			$ 13,611

Impact of ASC 606 Adoption - Ad

Impact of ASC 606 Adoption - Additional Information (Details)	9 Months Ended
	Sep. 30, 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 Eq_3

Oil and Gas Properties and Equipment - Schedule of Oil and Gas Properties and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Proven Properties:
Acquisition, equipment, exploration, drilling and abandonment costs	$ 11,491,066	$ 11,215,563
Less: Accumulated depletion, depreciation and amortization	(10,031,400)	(9,890,495)
Oil and gas properties, net	$ 1,459,666	$ 1,325,068

Debt and Other Long-Term Obli_3

Debt and Other Long-Term Obligations - Summary of Outstanding Debt and Other Long Term Obligations (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Total Debt:
Current portion of long-term debt	$ 4,875
Total long-term debt	2,170,125	$ 2,175,000
Less: Deferred financing costs	(51,796)	(58,789)
Total debt, net of deferred financing costs	2,123,204	2,116,211
Other long-term obligations:
Other long-term obligations	199,874	197,728
Term Loan Secured Due 2024
Total Debt:
Total long-term debt	970,125	975,000
6.875% Senior, Unsecured Notes Due 2022
Total Debt:
Total long-term debt	700,000	700,000
7.125% Senior, Unsecured Notes Due 2025
Total Debt:
Total long-term debt	$ 500,000	$ 500,000

Debt and Other Long-Term Obli_4

Debt and Other Long-Term Obligations - Summary of Outstanding Debt and Other Long Term Obligations (Parenthetical) (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 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 Obli_5

Debt and Other Long-Term Obligations - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($)	9 Months Ended
	Sep. 30, 2018	Apr. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Apr. 30, 2017
Debt Instrument [Line Items]
Long-term debt, gross	$ 2,170,125,000		$ 2,175,000,000
Ultra Resources, Inc. | Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity	325,000,000			$ 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	$ 1,300,000,000	$ 1,400,000,000		$ 1,400,000,000	$ 1,200,000,000
Borrowing base frequency of redetermination	semi-annual
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
Ultra Resources, Inc. | Credit Agreement | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Interest rate description	The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00.
Minimum required consolidated net leverage ratio, as percentage	400.00%
Interest rate on minimum required consolidated net leverage ratio exceeds 4.00 to 1.00	0.25%
Maximum required consolidated net leverage ratio, as percentage	400.00%
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, during the period ending on the last day of the fiscal quarter ending June 30, 2019	450.00%
Minimum required consolidated net leverage ratio, as percentage, 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	425.00%
Minimum required consolidated net leverage ratio, as percentage, beginning on the last day of the fiscal quarter ending on March 31, 2020	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 | Revolving Credit Facility
Debt Instrument [Line Items]
Net leverage ratio through September 29, 2019, minimum required hedging percentage	65.00%
Net leverage ratio beginning on September 30, 2019 and ending on March 30, 2020, minimum required hedging percentage	50.00%

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	9 Months Ended	12 Months Ended
	Apr. 29, 2017	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Debt Instrument [Line Items]
Long-term debt, gross		$ 2,170,125	$ 2,175,000
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Long-term debt, gross		$ 970,125	$ 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		$ 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 September 30, 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 Obli_2

Debt and Other Long Term Obligations - Ultra Resources, Inc. - Senior Unsecured Notes - Additional Information (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 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 Unsecured 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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of share-based payment plans	$ 2,148	$ 10,276	$ 15,321	$ 46,166
Amounts capitalized in oil and gas properties and equipment	724	2,358	3,774	11,984
Amounts charged against income, before income tax benefit	1,424	7,918	11,547	34,182
Amount of related income tax benefit recognized in income before valuation allowance	$ 299	$ 3,151	$ 2,425	$ 13,604

Share Based Compensation - Addi

Share Based Compensation - Additional Information (Details) - USD ($)	Jun. 08, 2018	Apr. 12, 2017	Jul. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incremental expense recognized from modification				$ 600,000		$ 600,000
Total cost of share based payment plans				$ 1,424,000	$ 7,918,000	11,547,000	$ 34,182,000
General And Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans						11,500,000
Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans							$ 32,900,000
Management Incentive Plan | General And Administrative Expense
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans						$ 10,900,000
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		$ 6,000,000,000
Performance Shares | Management Incentive Plan | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds 110% of $6.0 Billion or $6.6 Billion
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage		0.33%
Total enterprise value		$ 6,000,000,000
Percentage of enterprise value		110.00%
Performance Shares | Amendment and Restatement of Stock Incentive Plan 2017 | Outside Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Incentive awards available for grant value, maximum limit during a single calendar year	$ 750,000
Time-based Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Plan modification unvested portion exchange units percentage			100.00%
Time-based Restricted Stock Units | May 25, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date			May 25, 2019
Time-based Restricted Stock Units | May 25, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date			May 25, 2020
Time-based Restricted Stock Units | May 25, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted stock units vesting date			May 25, 2021

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Statutory tax rate	21.00%	35.00%

Derivative Financial Instrume_3

Derivative Financial Instruments - Additional Information (Details)	9 Months Ended
	Sep. 30, 2018
Maximum
Derivative [Line Items]
Commodity derivatives board authorization	50.00%

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands, bbl in Millions	1 Months Ended	9 Months Ended
	Oct. 25, 2018MMBTU$ / MMBTU	Sep. 30, 2018USD ($)MMBTU$ / MMBTU$ / bblbbl
Derivative [Line Items]
Liability, Fair Value		$ (61,926)
Commodity Derivative Contract Fixed Price Swaps | Crude Oil
Derivative [Line Items]
Type		Crude oil fixed price swaps
Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type		Natural gas fixed price swaps
Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Type		Natural gas basis swaps
Commodity Derivative Contract Collars | Natural Gas | Subsequent Event
Derivative [Line Items]
Type	Collars
Commodity Derivative Contract Collars One | Natural Gas | Subsequent Event
Derivative [Line Items]
Index	NYMEX
Remaining Contract Period	January - March 2020
Volume/Day | MMBTU	100,000
Weighted Average Floor Price | $ / MMBTU	2.75
Weighted Average Ceiling Price | $ / MMBTU	3.18
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps | Crude Oil
Derivative [Line Items]
Year		2,020
Index		NYMEX-WTI
Total Volumes | bbl		0.1
Weighted Average Price per Unit | $ / bbl		60.05
Liability, Fair Value		$ (734)
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Year		2,020
Index		NYMEX-Henry Hub
Total Volumes | MMBTU		15,500,000
Weighted Average Price per Unit | $ / MMBTU		2.76
Liability, Fair Value		$ (1,673)
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps Two | Crude Oil
Derivative [Line Items]
Year		2,019
Index		NYMEX-WTI
Total Volumes | bbl		1.7
Weighted Average Price per Unit | $ / bbl		58.83
Liability, Fair Value		$ (21,295)
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas
Derivative [Line Items]
Year		2,019
Index		NYMEX-Henry Hub
Total Volumes | MMBTU		163,900,000
Weighted Average Price per Unit | $ / MMBTU		2.82
Liability, Fair Value		$ (188)
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps One | Crude Oil
Derivative [Line Items]
Year		2018 (October through December)
Index		NYMEX-WTI
Total Volumes | bbl		0.6
Weighted Average Price per Unit | $ / bbl		60.45
Liability, Fair Value		$ (7,472)
Derivative Financial Instruments, Liabilities | Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Year		2018 (October through December)
Index		NYMEX-Henry Hub
Total Volumes | MMBTU		60,500,000
Weighted Average Price per Unit | $ / MMBTU		2.88
Liability, Fair Value		$ (9,536)
Derivative Financial Instruments, Liabilities | Commodity Derivative Basis Swap Contracts One | Natural Gas
Derivative [Line Items]
Year		2018 (October through December)
Index		NW Rockies Basis Swap
Total Volumes | MMBTU		51,500,000
Weighted Average Price per Unit | $ / MMBTU		(0.66)
Liability, Fair Value		$ (4,170)
Derivative Financial Instruments, Liabilities | Commodity Derivative Basis Swap Contracts Two | Natural Gas
Derivative [Line Items]
Year		2,019
Index		NW Rockies Basis Swap
Total Volumes | MMBTU		84,500,000
Weighted Average Price per Unit | $ / MMBTU		(0.70)
Liability, Fair Value		$ (10,523)
Derivative Financial Instruments, Liabilities | Commodity Derivative Basis Swap Contracts Three | Natural Gas
Derivative [Line Items]
Year		2,020
Index		NW Rockies Basis Swap

Derivative Financial Instrume_5

Derivative Financial Instruments - Summary of Pre-tax Realized and Unrealized Gain (Loss) Recognized Related to Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives			$ (72,557)	$ 4,133
Total gain (loss) on commodity derivatives	$ (21,804)	$ 4,650	(75,607)	12,149
Commodity Derivative Contract
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives	(11,018)	(4,234)	(72,557)	4,133
Total gain (loss) on commodity derivatives	(21,804)	4,650	(75,607)	12,149
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	(5,468)	$ 8,884	6,958	$ 8,016
Commodity Derivative Contract | Oil
Derivative [Line Items]
Realized gain (loss) on commodity derivatives	$ (5,318)		$ (10,008)

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		$ 12,728	$ 16,865
Long-term derivative asset	[1]	1,454
Total derivative instruments		14,182
Current derivative liability		61,926
Long-term derivative liability	[2]	7,847
Total derivative instruments		69,773
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset		12,728
Long-term derivative asset	[1]	1,454
Total derivative instruments		14,182
Current derivative liability		61,926
Long-term derivative liability	[2]	7,847
Total derivative instruments		$ 69,773
[1]	Included in Other assets in the Condensed Consolidated Balance Sheet.
[2]	Included in Other long-term obligations in the Condensed Consolidated Balance Sheet.

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Details) - Level 2 - USD ($) $ in Thousands	Sep. 30, 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	1,422,710	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	877,500	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	336,000	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	$ 209,210	$ 505,000

Fair Value Measurements - Car_2

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	9 Months Ended
	Sep. 30, 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

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands	Oct. 06, 2017	Aug. 31, 2016	Apr. 29, 2016	Apr. 19, 2016	Sep. 30, 2017	Sep. 30, 2017	Oct. 16, 2018	Sep. 30, 2018
Loss Contingencies [Line Items]
Claims settled	$ 399,000
Bankruptcy claims, undistributed amount returned	1,300
Bankruptcy claims amount of claims settled, make-whole fees	223,800				$ 223,838	$ 223,838
Bankruptcy claims amount of claims settled, postpetition interest	175,200
SPMT | Subsequent Event
Loss Contingencies [Line Items]
Accrued payment							$ 2,000
Indebtedness Claims | Notes holders
Loss Contingencies [Line Items]
Claim reserve account after effective date	$ 400,000
Royalties | ONRR
Loss Contingencies [Line Items]
Bankruptcy claims amount				$ 35,100
Oil Sales Contract | SPMT
Loss Contingencies [Line Items]
Bankruptcy claims amount		$ 16,900
Damage sought			$ 38,600
Accrued payment								$ 2,000
Write off of receivable								$ 700
Oil Sales Contract | SPMT | Subsequent Event
Loss Contingencies [Line Items]
Accrued payment							$ 2,000

Chapter 11 Proceedings - Additi

Chapter 11 Proceedings - Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 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) - USD ($) $ in Thousands	Oct. 06, 2017	Sep. 30, 2017	Sep. 30, 2017
Reorganization Items [Abstract]
Professional fees		$ (3,285)	$ (65,289)
Gains (losses)			431,107
Make-whole fees	$ (223,800)	(223,838)	(223,838)
Other			167
Total Reorganization items, net		$ (227,123)	$ 142,147

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Nov. 08, 2018	Oct. 17, 2018	Dec. 31, 2017	Oct. 16, 2018
Subsequent Event [Line Items]
Equitization of Holdco Notes			$ 978,230,000
Subsequent Event | Exchange Agreement
Subsequent Event [Line Items]
Number of common stock issued upon exercise of each warrant		1
Volume-weighted average price of common shares		$ 2.50
Shareholder dilution percentage		6.00%
Subsequent Event | Settlement Agreements
Subsequent Event [Line Items]
Settlement agreement, receivables	$ 13,200,000
Subsequent Event | Ultra Resources, Inc. | Exchange Agreement
Subsequent Event [Line Items]
Debt issued on exchange, maturity date		2024-07
Warrants price per share		$ 0.01
Subsequent Event | 6.875% Senior, Unsecured Notes Due 2022 | Ultra Resources, Inc. | Exchange Agreement
Subsequent Event [Line Items]
Aggregate principal amount of debt exchanged		$ 556,400,000
Aggregate principal amount of debt exchanged, percentage		79.50%
Equitization of Holdco Notes		$ 720
Warrants issued on exchange		14
Subsequent Event | 7.125% Senior, Unsecured Notes Due 2025 | Ultra Resources, Inc. | Exchange Agreement
Subsequent Event [Line Items]
Aggregate principal amount of debt exchanged		$ 267,100,000
Aggregate principal amount of debt exchanged, percentage		53.40%
Equitization of Holdco Notes		$ 660
Warrants issued on exchange		14
Subsequent Event | Senior Secured Second Lien Notes due July 2024 | Ultra Resources, Inc. | Exchange Agreement
Subsequent Event [Line Items]
Debt issued on exchange, maturity date		2024-07
Subsequent Event | Senior Secured Second Lien Notes due July 2024 | Ultra Resources, Inc. | Exchange Agreement | Cash Notes
Subsequent Event [Line Items]
Debt issued on exchange, interest rate		9.00%
Subsequent Event | Senior Secured Second Lien Notes due July 2024 | Ultra Resources, Inc. | Exchange Agreement | Payment in Kind (PIK) Note
Subsequent Event [Line Items]
Debt issued on exchange, interest rate		2.00%
Subsequent Event | SPMT
Subsequent Event [Line Items]
Settlement agreement, accrued payment				$ 2,000,000