Ultra Petroleum 10-K 28 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 15, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	1,022,646
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2,130,019,725
Entity Common Stock, Shares Outstanding		196,346,736
Trading Symbol	UPL

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Natural gas sales	$ 748,682	$ 609,756	$ 696,730
Oil sales	133,368	111,335	142,381
Other revenues	9,823
Total operating revenues	891,873	721,091	839,111
Expenses:
Lease operating expenses	92,326	89,134	106,906
Facility lease expense	21,749	20,686	20,647
Production taxes	91,067	69,737	72,774
Gathering fees	86,953	86,809	87,904
Transportation charges		20,049	83,803
Depletion, depreciation and amortization	161,945	125,121	401,200
Ceiling test and other impairments			3,144,899
General and administrative	39,548	9,179	7,387
Total operating expenses	493,588	420,715	3,925,520
Operating income (loss)	398,285	300,376	(3,086,409)
Other (expense) income, net:
Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016)	(361,367)	(66,565)	(171,918)
Gain on commodity derivatives	28,412		42,611
Deferred gain on sale of liquids gathering system	10,553	10,553	10,553
Litigation expense			(4,401)
Restructuring expenses		(7,176)
Contract settlement	(52,707)	(131,106)
Other (expense) income, net	(237)	(3,082)	(2,060)
Total other (expense) income, net	(375,346)	(197,376)	(125,215)
Reorganization items, net	140,907	(47,503)	0
Income (loss) before income tax benefit	163,846	55,497	(3,211,624)
Income tax benefit	(13,294)	(654)	(4,404)
Net income (loss)	$ 177,140	$ 56,151	$ (3,207,220)
Basic Earnings (Loss) per Share:
Net income (loss) per common share — basic	$ 1.08	$ 0.70	$ (40.14)
Fully Diluted Earnings (Loss) per Share:
Net income (loss) per common share — fully diluted	$ 1.08	$ 0.70	$ (40.14)
Weighted average common shares outstanding — basic	163,824	79,996	79,899
Weighted average common shares outstanding — fully diluted	163,976	80,363	79,899

Consolidated Statement of Oper3

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

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 16,631	$ 401,478
Restricted cash	1,638	3,571
Oil and gas revenue receivable	86,487	79,179
Joint interest billing and other receivables	16,616	10,781
Derivative asset	16,865
Income tax receivable	10,091	2,099
Inventory	13,450	4,906
Deposits and retainers		13,359
Other current assets	5,647	6,020
Total current assets	167,425	521,393
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,325,068	1,010,466
Property, plant and equipment	9,569	7,695
Other	10,920	1,374
Total assets	1,512,982	1,540,928
Current liabilities:
Accounts payable	59,951	28,171
Accrued liabilities	80,268	53,348
Production taxes payable	51,352	44,329
Interest payable	24,406
Capital cost accrual	32,513	12,360
Total current liabilities	248,490	138,208
Long-term debt	2,116,211
Deferred gain on sale of liquids gathering system	105,189	115,742
Other long-term obligations	197,728	177,088
Total liabilities not subject to compromise	2,667,618	431,038
Liabilities subject to compromise	0	4,038,041
Commitments and contingencies (Note 11)
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding shares — 196,346,736 and 80,017,020, at December 31, 2017 and 2016, respectively	2,116,018	510,063
Treasury stock	(49)	(49)
Retained loss	(3,270,605)	(3,438,165)
Total shareholders’ deficit	(1,154,636)	(2,928,151)
Total liabilities and shareholders’ equity	$ 1,512,982	$ 1,540,928

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Common stock, No par value
Common stock, Shares authorized	Unlimited	Unlimited
Common stock, Shares issued	196,346,736	80,017,020
Common stock, Shares outstanding	196,346,736	80,017,020

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Retained Loss	Treasury Stock
Beginning Balances at Dec. 31, 2014	$ 211,660	$ 495,913	$ (278,040)	$ (6,213)
Beginning Balances, Shares at Dec. 31, 2014		79,745
Employee stock plan grants	700	$ 700
Employee stock plan grants, Shares		274
Shares re-issued from treasury			(6,037)	6,037
Net share settlements	(2,514)		(2,514)
Net share settlements, Shares		(86)
Fair value of employee stock plan grants	5,437	$ 5,437
Net income (loss)	(3,207,220)		(3,207,220)
Ending Balances at Dec. 31, 2015	(2,991,937)	$ 502,050	(3,493,811)	(176)
Ending Balances, Shares at Dec. 31, 2015		79,933
Employee stock plan grants, Shares		145
Shares re-issued from treasury			(127)	127
Net share settlements	(378)		(378)
Net share settlements, Shares		(61)
Fair value of employee stock plan grants	8,013	$ 8,013
Net income (loss)	56,151		56,151
Ending Balances at Dec. 31, 2016	(2,928,151)	$ 510,063	(3,438,165)	(49)
Ending Balances, Shares at Dec. 31, 2016		80,017
Equitization of Holdco Notes	978,230	$ 978,230
Equitization of Holdco Notes, Shares		70,579
Rights Offering, including Backstop	573,774	$ 573,774
Rights Offering, including Backstop, Shares		44,390
Employee stock plan grants, Shares		10
Stock plan grants	26,673	$ 26,673
Stock plan grants, Shares		2,191
Net share settlements	(9,580)		(9,580)
Net share settlements, Shares		(841)
Fair value of employee stock plan grants	27,278	$ 27,278
Net income (loss)	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		196,346

Consolidated Statements of Sha7

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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss) for the period	$ 177,140	$ 56,151	$ (3,207,220)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion, depreciation and amortization	161,945	125,121	401,200
Ceiling test and other impairments			3,144,899
Deferred and current non-cash income taxes		1	(990)
Unrealized (gain) loss on commodity derivatives	(16,966)		104,190
Deferred gain on sale of liquids gathering system	(10,553)	(10,553)	(10,553)
Stock compensation	39,977	5,562	4,128
Non-cash reorganization items, net	(453,909)	42,523
Amortization of deferred financing costs	7,483	4,194	5,190
Other	(1,047)	2,676	4,027
Net changes in operating assets and liabilities:
Accounts receivable	(14,483)	(19,635)	65,132
Other current assets	14,136	(15,647)	(20,106)
Other non-current assets	479	(539)	21,112
Accounts payable	34,349	(63,924)	13,815
Accrued liabilities	89,935	133,144	1,655
Production taxes payable	7,023	(7,944)	(3,312)
Interest payable	36,220	57,117	(3,441)
Other long-term obligations	4,737	276	(5,770)
Current taxes payable/receivable	(11,198)	2,547	1,580
Net cash provided by operating activities	65,268	311,070	515,536
Investing Activities:
Oil and gas property expenditures	(557,029)	(269,314)	(494,025)
Acquisition of oil and gas properties			3,964
Sale of oil and gas properties	114,263
Change in capital cost accrual	20,076	(8,134)	(25,380)
Inventory	(8,916)	(1,123)	3,235
Purchase of property, plant and equipment	(3,705)	(329)	(551)
Net cash used in investing activities	(435,311)	(278,900)	(512,757)
Financing activities:
Extinguishment of long-term debt (chapter 11)	(2,459,000)
Proceeds from issuance of Senior Notes	1,200,000
Deferred financing costs	(73,092)		6
Shares issued, net of transaction costs	573,774
Repurchased shares/net share settlements	(9,581)	(379)	(2,514)
Payment of contingent consideration			(17,049)
Debt extinguishment costs	(223,838)
Net cash (used in) provided by financing activities	(16,737)	368,621	(7,557)
(Decrease)/Increase in cash during the period	(386,780)	400,791	(4,778)
Cash, cash equivalents, and restricted cash at beginning of period	405,049	4,258	9,036
Cash, cash equivalents, and restricted cash end of period	18,269	405,049	4,258
Cash paid for:
Interest	317,120	4,793	169,867
Income taxes		94
Credit Agreement
Financing activities:
Borrowings under Credit / Term Loan Agreement	773,000	$ 369,000	1,165,000
Payments under Credit Agreement	(773,000)		$ (1,153,000)
Term Loan Agreement
Financing activities:
Borrowings under Credit / Term Loan Agreement	$ 975,000

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Description of the Business	DESCRIPTION OF THE BUSINESS: Ultra Petroleum Corp. (the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Green River Basin of Wyoming – the Pinedale and Jonah fields and its oil reserves in the Uinta Basin in Utah.

Chapter 11 Proceedings

Chapter 11 Proceedings	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Chapter 11 Proceedings	Chapter 11 Proceedings Voluntary Reorganization Under Chapter 11and Ability to Continue as a Going Concern On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, “the Debtors”) filed voluntary petitions under chapter 11 of title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization As a result of its improved financial condition and successful emergence from chapter 11, the Company believes it has sufficient liquidity along with funds generated from ongoing operations, to fund anticipated cash requirements for operations, capital expenditures and working capital purposes. As a result, substantial doubt no longer exists regarding the Company’s ability to meet its obligations as they become due within one year after the date that the financial statements are issued. Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing On November 21, 2016, each of the Ultra Entities entered into a Plan Support Agreement (“PSA”) with (i) holders of at least 66.67% of the principal amount of the Company’s outstanding 5.750% Senior Notes due 2018 and 6.125% Senior Notes due 2024 and (ii) shareholders who own at least a majority of the Company’s outstanding common stock or the economic interests therein (collectively, the “Plan Support Parties”) and a Backstop Commitment Agreement (“BCA”) with a subset thereof (collectively, the “Commitment Parties”). Plan Support Agreement : The PSA enumerated the terms and conditions pursuant to which the Ultra Entities and the Commitment Parties agreed to seek and support a joint plan of reorganization. The Plan consummated on the Effective Date was the joint plan of reorganization contemplated in the PSA. Rights Offering : In accordance with the Plan, the BCA and the Rights Offering procedures submitted by the Company in connection with the Plan, the Company offered eligible debt and equity holders, including the Commitment Parties, the right to purchase shares of new common stock in the Company upon effectiveness of the Plan for an aggregate purchase price of $580.0 million. The Rights Offering was consummated upon the Company’s emergence from bankruptcy on the Effective Date. Pursuant to the Rights Offering: • HoldCo Noteholders were granted rights (the “HoldCo Noteholder Rights Offering”) entitling each such holder to subscribe for the Rights Offering in an amount up to its pro rata share of new common stock (the “HoldCo Noteholder Rights Offering Shares”), which HoldCo Noteholder Rights Offering Shares, collectively, reflected an aggregate purchase price of $435.0 million. • HoldCo Equityholders were granted rights (the “HoldCo Equityholder Rights Offering”) entitling each such holder to subscribe for the Rights Offering in an amount up to its pro rata share of new common stock (the “HoldCo Equityholder Rights Offering Shares” and, together with the HoldCo Noteholder Rights Offering Shares, the “Rights Offering Shares”), which HoldCo Equityholder Rights Offering Shares, collectively, reflected an aggregate purchase price of $145.0 million. Backstop Commitment Agreement : Under the BCA, the Commitment Parties agreed to purchase the HoldCo Noteholder Rights Offering Shares and the HoldCo Equityholder Rights Offering Shares, as applicable, that were not duly subscribed for pursuant to the HoldCo Noteholder Rights Offering or the HoldCo Equityholder Rights Offering, as applicable, by parties other than Commitment Parties (the “Backstop Commitment”) at an implied 20% discount to the Plan Value, which is the price for the rights offering set forth in the PSA (the “Rights Offering Price”). In connection with our emergence from bankruptcy on the Effective Date, the Commitment Parties performed the Backstop Commitment as and to the extent provided for in the BCA. In addition, on the Effective Date, the Company paid the Commitment Parties a Commitment Premium equal to 6.0% of the $580.0 million committed amount. The commitment premium was paid in the form of new common stock at the Rights Offering Price. Exit Financing : On February 8, 2017, the Debtors obtained a commitment letter (as amended, the “Commitment Letter”) from Barclays Bank PLC (including any affiliates that may perform its responsibilities thereunder, “Barclays”), pursuant to which, in connection with the consummation of the Plan, Barclays agreed to provide us with secured and unsecured financing in an aggregate amount of up to $2.4 billion. On the Effective Date, in connection with the consummation of our Plan: • Ultra Resources entered into a Credit Agreement dated April 12, 2017 with Bank of Montreal, as administrative agent, and with the other lenders party thereto (the “RBL Credit Agreement”), providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million; • Ultra Resources entered into a Senior Secured Term Loan Agreement dated April 12, 2017 with Barclays Bank PLC, as administrative agent, and with 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; ▪ Ultra Resources entered into an Indenture dated April 12, 2017 with Wilmington Trust, as trustee (the “Indenture”), and also issued the $700.0 million of its 6.875% unsecured senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% unsecured senior notes due 2025 (the “2025 Notes” and, collectively with the 2022 Notes, the “Notes”), as contemplated in the Purchase Agreement. The 2022 Notes were sold at an issue price of 100% and the 2025 Notes were sold at an issue price of 98.507%, and the issuance of the 2022 Notes and the 2025 Notes resulted in net proceeds (after deducting purchasers’ discounts and commissions) to Ultra Resources of $1.185 billion. • 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 Prepetition Senior Notes were cancelled and extinguished as provided in the Plan. • The claims of $450.0 million related to the unsecured 2018 Notes and $850.0 million related to the unsecured 2024 Notes were allowed in full, each holder of a claim related to the 2018 and 2024 Notes received a distribution of common stock in the amount of the holders’ applicable claim and the Company’s obligations under the 2018 Notes and 2024 Notes were cancelled and extinguished as provided in the Plan. Ultra Resources’ obligations under the RBL Credit Agreement, the Term Loan Agreement, the Indenture, and the Notes are guaranteed by the Company and each of its subsidiaries (other than Ultra Resources). In addition, on the Effective Date, the Company and each of its subsidiaries (other than Ultra Resources) entered into a Guaranty and Collateral Agreement in favor of Bank of Montreal, as administrative agent, for the benefit of the secured parties under the RBL Credit Agreement and the Term Loan Agreement. The Company’s obligations under the Revolving Credit Facility and the Term Loan Agreement are secured by first priority, perfected liens and security interests on 85% of the total value of proved oil and gas properties evaluated in reserve reports delivered to the lenders under the Revolving Credit Facility, as well as a negative pledge on substantially all non-mortgaged assets of the Company and other guarantors under the Revolving Credit Facility For further description of the emergence financing and for other information and changes to the Company’s debt financing subsequent to the Effective Date, see Note 5. Fresh Start Accounting As previously disclosed, we are 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. Liabilities Subject to Compromise The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through December 31, 2017: December 31, 2017 Liabilities subject to compromise at December 31, 2016 4,038,041 Debt extinguishment-cash (2,521,493 ) Debt extinguishment-non-cash (1,339,740 ) Contract settlement (169,600 ) Reclassified to accrued liabilities (7,208 ) Liabilities subject to compromise at December 31, 2017 $ — Bankruptcy Claims Resolution Process The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained. As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed. Costs of Reorganization We have incurred significant costs associated with our reorganization and the chapter 11 proceedings. We expect these costs, which are being expensed as incurred, will significantly affect our results of operations. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below. The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended December 31, 2017, 2016, and 2015: For the Twelve Months Ended December 31, 2017 2016 2015 Professional fees (1) $ (66,529 ) $ (11,781 ) $ — Gains (losses) (2) 431,107 — — Deferred financing costs — (18,742 ) — Contract settlements — (17,350 ) — Make-whole fees (3) (223,838 ) — — Other (4) 167 370 — Total Reorganization items, net $ 140,907 $ (47,503 ) $ — (1) The year ended December 31, 2017 includes $1.1 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings. (2) Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 and 2024 Notes. (3) Make-whole fees represent the Bankruptcy Court order denying our objection to the make-whole claims, as further described in Note 11. (4) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies	1. SIGNIFICANT ACCOUNTING POLICIES: (a) Basis of presentation and principles of consolidation (b) Cash and Cash Equivalents: (c) Restricted Cash: (d) Accounts Receivable: (e) Property, Plant and Equipment: (f) Oil and Natural Gas Properties: The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as The Company did not have any write-downs related to the full cost ceiling limitation in 2017 or 2016. During 2015, the Company recorded a $3.1 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve-month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials. (g) Inventories: (h) Derivative Instruments and Hedging Activities: (i) Deferred Financing Costs: Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (j) Income Taxes: (k) Equity Interests: (l) Earnings (Loss) Per Share: In conjunction with our emergence from chapter 11 proceedings, on the Effective Date, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred on January 1, 2015. 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 year ended December 31, 2017, the Company had 3.9 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 6). There were no contingently issuable shares outstanding for the years ended December 31, 2016 and 2015. The following table provides a reconciliation of components of basic and diluted net income (loss) per common share: December 31, 2017 2016 2015 Net income (loss) $ 177,140 $ 56,151 $ (3,207,220 ) Weighted average common shares outstanding during the period 163,824 79,996 79,899 Effect of dilutive instruments 152 367 — Weighted average common shares outstanding during the period including the effects of dilutive instruments 163,976 80,363 79,899 Net income (loss) per common share — basic $ 1.08 $ 0.70 $ (40.14 ) Net income (loss) per common share — fully diluted $ 1.08 $ 0.70 $ (40.14 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares (1) — 749 — (1) Due to the net loss for the year ended December 31, 2015, 1.7 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share. (m) Use of Estimates: (n) Accounting for Share-Based Compensation: (o) Fair Value Accounting: (p) Asset Retirement Obligation: (q) Revenue Recognition: Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. The Company’s imbalance obligations as of December 31, 2017 and December 31, 2016 were immaterial. (r) Other revenues: (s) Capitalized Interest: (t) Capital Cost Accrual: (u) Reclassifications: (v) Deposits and Retainers: (w) Recent Accounting Pronouncements: Statement of Cash Flows: In November 2016, the FASB issued ASU 2016-18, (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. The ASU also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. We early adopted ASU 2016-18 at December 31, 2017 and disclosure revisions have been made for the years presented on the Consolidated Statements of Cash Flows. All prior periods have been adjusted to conform, which resulted in a (decrease)/increase in cash flows from operating activities of approximately ($1.9) million, $3.5 million, and ($0.2) million for the years ended December 31, 2017, 2016, and 2015 respectively. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statement of Cash Flows. Current Presentation December 31, 2017 December 31, 2016 December 31, 2015 Cash and Cash Equivalents $ 16,631 $ 401,478 $ 4,143 Restricted Cash 1,638 3,571 115 Total cash, cash equivalents, and restricted cash $ 18,269 $ 405,049 $ 4,258 Statement of Cash Flows: In August 2016, the FASB issued ASU 2016-15, (“ASU No. 2016-15”). ASU 2016-15 provides guidance on eight specific cash flow issues with the objective of reducing diversity in practice in regard to how cash receipts and cash payments are presented and classified in the statement of cash flows. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. We early adopted ASU 2016-15 at December 31, 2017. The guidance was applied retrospectively as required by the standard. For the year ended December 31, 2017, the material impact to the Consolidated Statement of Cash Flows was the reclassification of costs related to the extinguishment of long-term debt from cash flows provided by operating activities to cash flows used in financing activities totaling $223.8 million. There was no material impact to the Consolidated Statement of Cash Flows for the years ended December 31, 2016 and 2015. Leases: In February 2016, the FASB issued ASU 2016-02, (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. 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. The Company is evaluating the impact of ASU No. 2016-02 on its financial position and results of operations. Stock Compensation: In May 2017, the FASB issued ASU 2017-9, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of ASU No. 2017-08 to have a material impact on its 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. Revenues from Contracts with Customers: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, 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. We have evaluated the provisions of ASU 2014-09 and assessed the impact it may have on our financial position and results of operations. As part of our assessment work, we have done the following: • We have completed training of the new ASU’s revenue recognition model, dedicated resources to its implementation, and initiated contract review and documentation; including analyzing the standard’s impact on our contract portfolio, comparing historical accounting policies and practices to the requirements of the new standard, and identifying differences from applying the requirements of the new standards to our contracts. • We have evaluated each revenue stream, including sales of oil, natural gas, and other revenues, noting no significant changes to revenue recognition under the new standard except as noted below. • We had previously elected to utilize the entitlements method, which will no longer be applicable under ASU 2014-09. We do not anticipate the change from the entitlements method to have a material impact on our financial statements. • We evaluated our product sales contracts in order to determine if there were remaining performance obligations. We have determined that our product sales are primarily short-term in nature with contract periods of one year or less. We have evaluated product sales contracts with terms greater than one year and anticipate using the practical expedient in ASC 606-10-50-14(a) which will not require disclosure of the transaction price allocated to remaining performance obligations. • We have evaluated our product sales contracts and do not anticipate them to give rise to contract assets or liabilities. • We have evaluated the expanded disclosure requirements under the new standard and reviewed our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures. We do not anticipate any issues in providing the appropriate information to be available for the disclosures. The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the modified retrospective method). The Company will adopt the standard as of January 1, 2018 using the modified retrospective method. The Company is currently estimating the impact to beginning retained earnings to be immaterial to the overall consolidated financial statements based on implementation through the modified retrospective approach .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	2. ASSET RETIREMENT OBLIGATIONS: The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended: December 31, 2017 2016 Asset retirement obligations at beginning of period $ 157,173 $ 146,210 Accretion expense 11,689 10,252 Liabilities incurred 8,174 1,317 Liabilities divested (1) (4,812 ) — Liabilities acquired 1,456 — Liabilities settled (598 ) (170 ) Revisions of estimated liabilities 18 (436 ) Asset retirement obligations at end of period 173,100 157,173 Less: current asset retirement obligations (263 ) (239 ) Long-term asset retirement obligations $ 172,837 $ 156,934 (1) During the quarter ended December 31, 2017, the Company divested certain non-core properties in north-central Pennsylvania for net cash proceeds of approximately $115.0 million, subject to post-close adjustments.

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2017
Oil And Gas Property [Abstract]
Oil and Gas Properties	3. OIL AND GAS PROPERTIES: December 31, 2017 December 31, 2016 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,215,563 $ 10,752,642 Less: Accumulated depletion, depreciation and amortization (9,890,495 ) (9,742,176 ) 1,325,068 1,010,466 On a unit basis, DD&A was $0.59, $0.44 and $1.38 per Mcfe for the years ended December 31, 2017, 2016 and 2015, respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	4. PROPERTY, PLANT AND EQUIPMENT: December 31, 2017 2016 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 3,018 (2,464 ) 554 603 Office equipment 309 (214 ) 95 138 Leasehold improvements 486 (366 ) 120 185 Land 4,637 — 4,637 4,637 Other 15,773 (11,610 ) 4,163 2,132 Property, plant and equipment, net $ 24,223 $ (14,654 ) $ 9,569 $ 7,695

Debt and Other Long-Term Liabil

Debt and Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2017
Long Term Liabilities [Abstract]
Debt and other long term liabilities	5. DEBT AND OTHER LONG-TERM LIABILITIES: December 31, 2017 December 31, 2016 Total Debt: Term loan, secured, due 2024 $ 975,000 $ — 6.875% Senior, unsecured Notes due 2022 700,000 — 7.125% Senior, unsecured Notes due 2025 500,000 — 6.125% Senior Notes due 2024 — 850,000 5.75% Senior Notes due 2018 — 450,000 Senior Notes issued by Ultra Resources, Inc. — 1,460,000 Credit Agreement — 999,000 Total long-term debt 2,175,000 3,759,000 Less: Deferred financing costs (58,789 ) — Less: Liabilities subject to compromise (1) (See Note 1) — (3,759,000 ) Total long-term debt not subject to compromise $ 2,116,211 $ — Other long-term obligations: Other long-term obligations $ 197,728 $ 177,088 Aggregate maturities of debt at December 31, 2017: 2018 2019 2020 2021 2022 Beyond 5 years Total $ — $ 7,313 $ 9,750 $ 9,750 $ 709,750 $ 1,438,437 $ 2,175,000 (1) All of our indebtedness that was outstanding as of December 31, 2016 was classified as liabilities subject to compromise in the Consolidated Balance Sheets. See below for information about the indebtedness we incurred in connection with, and that is now outstanding following our emergence from bankruptcy. On the Effective Date, all principal, prepetition interest and other undisputed amounts were paid in full for the amounts owed under the Prepetition Credit Agreement and the Prepetition Senior Notes shown in the table above and the Company’s obligations under the Prepetition Credit Agreement and Prepetition Senior Notes were cancelled and extinguished. The claims related to the 2018 and 2024 Notes, shown in the table above were allowed in full, each claim holder received a distribution of our comment stock in the amount of the applicable claim, and the Company’s obligations under the 2018 and 2024 Notes were cancelled and extinguished. Ultra Resources, Inc. Credit Agreement. On April 12, 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a 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 (as amended, the “RBL Credit Agreement”), 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 Facility (defined below)). On September 19, 2017, the Bank of Montreal, as administrative agent, and the other lenders party thereto, approved an increase in the borrowing base under the RBL Credit Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the RBL Credit Agreement to an aggregate amount of $425.0 million. At December 31, 2017, Ultra Resources did not have any outstanding borrowings under the RBL Credit Agreement, had total commitments under the RBL Credit Agreement of $425.0 million, and a borrowing base of $1.4 billion. There are no scheduled borrowing base redeterminations until April 1, 2018. The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions, and had $50.0 million of the commitments available for the issuance of letters of credit. During the quarter ended December 31, 2017, the Company utilized $34.5 million of the commitments available for the issuance of a letter of credit associated with the Pennsylvania Asset Sale. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. The interest rate remained the same for the Revolving Credit Facility subsequent to the approved commitments increase noted above. The Revolving Credit Facility loans mature on January 12, 2022. The RBL Credit Agreement requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility of 1.00 to 1.00; (iii) a consolidated net leverage ratio of (A) 4.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and (B) 4.00 to 1.00, as of the last day of any fiscal quarter thereafter; and (iv) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. At December 31, 2017, Ultra Resources was in compliance with all of its debt covenants under the RBL Credit Agreement. 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 RBL Credit Agreement 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 RBL Credit 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 RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated. Term Loan. On April 12, 2017 , Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement 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. On September 29, 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under the Term Loan Agreement to $975.0 million (the “Term Loan Facility”). As part of the Term Loan agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in deferred financing costs noted above. The Term Loan Agreement has capacity to increase the commitments subject to certain conditions. At December 31, 2017, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Facility. The Term Loan Facility 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 Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Facility matures seven years after the Effective Date. The Term Loan Facility is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan Facility. The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At December 31, 2017, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Facility. The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement. Senior Notes . On April 12, 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture. The Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act. The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Notes from the issue date until maturity. Prior to April 15, 2019, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2022 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes. Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes. If Ultra Resources experiences certain change of control triggering events set forth in the Indenture, each holder of the Notes may require Ultra Resources to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus any accrued but unpaid interest to the date of repurchase. The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distribution from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At December 31, 2017, Ultra Resources was in compliance with all of its debt covenants under the Notes. The Indenture contains customary events of default (each, an “Event of Default”). Unless otherwise noted in the Indenture, upon a continuing Event of Default, the trustee under the Indenture (“the Trustee”), by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Notes, by notice to the Company and the Trustee, may, declare the Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries (as defined in the Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Notes to become due and payable. Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.

Share Based Compensation

Share Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share Based Compensation	The Company sponsors a share based compensation plan: the 2017 Stock Incentive Plan (“2017 Plan”). The Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”). The share based compensation plan is an important component of the total compensation package offered to the Company’s key service providers, and reflects the importance that the Company places on motivating and rewarding superior results. The 2017 Plan was established on the Effective Date, pursuant to which 7.5% of the equity in the reorganized 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 reorganized Company (the “Reserve”). Valuation and Expense Information Year Ended December 31, 2017 2016 2015 Total cost of share-based payment plans $ 53,952 $ 8,013 $ 6,137 Amounts capitalized in oil and gas properties and equipment $ 13,975 $ 2,451 $ 2,009 Amounts charged against income, before income tax benefit $ 39,977 $ 5,562 $ 4,128 Amount of related income tax benefit recognized in income before valuation allowances $ 15,927 $ 2,216 $ 1,645 Securities Authorized for Issuance Under Equity Compensation Plans As of December 31, 2017, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury. Plan Category Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (000’s) Equity compensation plans approved by security holders 14,457 Equity compensation plans not approved by security holders n/a Total 14,457 Changes in Stock Options and Stock Options Outstanding As provided in the Plan, all plans or programs calling for stock grants, stock issuances, stock reserves, or stock options were cancelled as of the Effective Date and all outstanding awards established prior to the Effective Date were cancelled and extinguished as of the Effective Date. PERFORMANCE SHARE PLANS: 2017 Stock Incentive Plan. As mentioned above, the 2017 Stock Incentive Plan was established on the Effective Date which stated that 7.5% of the equity of the reorganized Company is reserved for grants to be made to directors, officers, and other employees of the Company. Also on the Effective Date, 40% of the Reserve, (“Initial MIP Grants”) was granted to members of the board of directors, officers, and other employees of the reorganized 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 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, such Initial MIP Grants shall automatically expire. Long Term Incentive Plans. Subsequent to December 31, 2017, the Board approved the establishment of a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The LTIP established covers a performance period of three years and includes time-based and performance-based measures established by the Committee at the beginning of the three-year period. Stock-Based Compensation Cost: Modification. On the Effective Date, as provided in the Plan, all outstanding awards established prior to the Effective Date were cancelled and extinguished, and participants received no payment or other distribution on account of the outstanding awards. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation (“FASB ASC 718”), the cancellation of an outstanding award of stock based compensation followed by the issuance of a replacement award is treated as a modification of the original award. The equity award cancellations and subsequent new grants by the Company were considered Type I, probable to probable modification. This type represents modifications where the award was likely to vest prior to modification and is still likely to vest after modification. For these types of modifications, the fair value of the award is assessed both prior to modification and after modification. If the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period Market Based Conditions. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’s total equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an award that is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the awards that include a market condition. FASB ASC 718 requires the expense for an award of stock based compensation that is subject to a market condition that can be attained at any point during the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and (b) award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on which the market condition is satisfied. The duration is the period of time from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is actually satisfied. Expense. For the year ended December 31, 2017, the Company recognized $40.0 million in pre-tax compensation expense, of which $38.5 million related to the Initial MIP Grants. For the year ended December 31, 2016, the Company recognized $5.6 million in pre-tax compensation expense, of which $4.7 million related to the 2015 and 2014 LTIP awards. For the year ended December 31, 2015, the Company recognized $4.1 million in pre-tax compensation expense, of which $2.9 million related to the 2015, 2014 and 2013 LTIP awards. The Company expects the total expense associated with the portion of the Initial MIP Grants that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $21.3 million and the portion of the Initial MIP grants that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $20.1 million, respectively. One-third of the Initial MIP Grants were paid in shares of the Company’s stock to members of its board of directors, as well as its officers and other employees on the Effective Date and totaled $26.1 million (1,238,665 shares) of which a portion was capitalized into oil and gas properties as noted in the valuation and expense information above.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	7. 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 amounts of resources hedged to not more than 50% of its forecasted production volumes without Board approval. Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Consolidated Statements of Cash Flows. Commodity Derivative Contracts: At December 31, 2017, the Company had the following open commodity derivative contracts to manage commodity price risk. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable to the counterparty. For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below the floor on a notional quantity. The reference prices of these commodity derivative contracts are typically referenced to index prices published by independent third parties. Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Price/MMBTU Fair Value - December 31, 2017 Natural Gas Asset (Liability) Fixed price swaps NYMEX-Henry Hub April-Oct 2018 380,000 $ 2.97 $ 15,419 Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Floor Price ($/MMBTU) Ceiling Price ($/MMBTU) Fair Value - December 31, 2017 Collars NYMEX-Henry Hub Jan-Mar 2018 40,000 $ 3.23 $ 3.54 $ 1,446 Subsequent to December 31, 2017 and through February 15, 2018, the Company has entered into the following open commodity derivative contracts to manage commodity price risk. Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Price/MMBTU Natural Gas Fixed price swaps NYMEX-Henry Hub April-Oct 2018 390,000 $ 2.79 NYMEX-Henry Hub Nov-Dec 2018 400,000 $ 2.88 NYMEX-Henry Hub Jan-Mar 2019 200,000 $ 2.91 Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Differential/MMBTU Natural Gas Basis Swap Contracts(1) NW Rockies Basis Swap Mar-Dec 2018 30,000 $ (0.58 ) NW Rockies Basis Swap April-Oct 2018 140,000 $ (0.62 ) Type Commodity Reference Price Remaining Contract Period Volume/ Bbls/day Average Price/Bbls Crude Oil Fixed price swaps NYMEX-WTI Feb-Dec 2018 2,000 $ 62.17 NYMEX-WTI Mar-Dec 2018 2,000 $ 57.43 (1) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period. The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, Commodity Derivatives: 2017 2016 2015 Realized gain on commodity derivatives-natural gas (1) $ 11,446 $ — $ 146,801 Unrealized gain (loss) on commodity derivatives (1) 16,966 — (104,190 ) Total gain on commodity derivatives $ 28,412 $ — $ 42,611 (1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	8. FAIR VALUE MEASUREMENTS: As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories: Level 1 : Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Level 2 : Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps. Level 3 : Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 16,865 $ — $ 16,865 Assets and Liabilities Measured on a Non-Recurring Basis The Company uses fair value to determine the value of its asset retirement obligations. The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs. Fair Value of Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt and the fair values presented in the tables below reflect original maturity dates for each of the debt instruments. The inputs utilized to estimate the fair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows. December 31, 2017 December 31, 2016 (1) Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Term Loan, secured due 2024 $ 975,000 $ 975,000 $ — $ — 6.875% Senior, unsecured Notes, due 2022 700,000 701,750 — — 7.125% Senior, unsecured Notes, due 2025 500,000 505,000 — — Credit Agreement, secured — — — — 7.31% Notes due March 2016, issued 2009 — — 62,000 64,266 4.98% Notes due January 2017, issued 2010 — — 116,000 123,967 5.92% Notes due March 2018, issued 2008 — — 200,000 224,025 5.75% Notes due December 2018, issued 2013 — — 450,000 465,630 7.77% Notes due March 2019, issued 2009 — — 173,000 204,854 5.50% Notes due January 2020, issued 2010 — — 207,000 233,932 4.51% Notes due October 2020, issued 2010 — — 315,000 337,528 5.60% Notes due January 2022, issued 2010 — — 87,000 99,983 4.66% Notes due October 2022, issued 2010 — — 35,000 38,225 6.125% Notes due October 2024, issued 2014 — — 850,000 893,325 5.85% Notes due January 2025, issued 2010 — — 90,000 106,299 4.91% Notes due October 2025, issued 2010 — — 175,000 193,665 Credit Facility due October 2016 — — 999,000 999,000 $ 2,175,000 $ 2,181,750 $ 3,759,000 $ 3,984,699 (1) At December 31, 2016, the debt included in the table above is a component of liabilities subject to compromise in our Consolidated Balance Sheets. See Note 1.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	9. INCOME TAXES: Income (loss) before income tax benefit is as follows: Year Ended December 31, 2017 2016 2015 United States $ (197,136 ) $ 134,959 $ (3,249,590 ) Foreign 360,982 (79,462 ) 37,966 Total $ 163,846 $ 55,497 $ (3,211,624 ) The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2017 2016 2015 Current tax: U.S. federal, state and local $ (13,296 ) $ (72 ) $ — Foreign 2 (583 ) (3,414 ) Total current tax (benefit) (13,294 ) (655 ) (3,414 ) Deferred tax: Foreign — 1 (990 ) Total deferred tax (benefit) expense — 1 (990 ) Total income tax (benefit) $ (13,294 ) $ (654 ) $ (4,404 ) The income tax provision (benefit) from continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following: Year Ended December 31, 2017 2016 2015 Income tax provision (benefit) computed at the U.S. statutory rate $ 57,346 $ 19,424 $ (1,124,069 ) State income tax (benefit) provision net of federal effect (25,519 ) (2,335 ) (12,998 ) Valuation allowance (562,491 ) (31,083 ) 1,147,619 Tax effect of rate change 463,113 — 12,898 Sale of Pennsylvania assets 130,552 — 0 Foreign rate differential (3,150 ) 17,388 (26,740 ) Reorganization items (78,549 ) — — Other, net 5,404 (4,048 ) (1,114 ) Total income tax (benefit) $ (13,294 ) $ (654 ) $ (4,404 ) The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows: December 31, 2017 2016 Deferred tax assets: Property and equipment 181,524 603,045 Deferred gain 22,256 40,867 U.S. federal tax credit carryforwards 987 15,967 U.S. net operating loss carryforwards 450,623 428,212 U.S. state net operating loss carryforwards 4,038 71,323 Non-U.S. net operating loss carryforwards 6,556 30,211 Asset retirement obligations 36,624 55,700 Liabilities subject to compromise-contract settlement — 59,166 Incentive compensation/other, net 8,308 16,088 710,916 1,320,579 Valuation allowance (707,348 ) (1,270,935 ) Net deferred tax assets $ 3,568 $ 49,644 Deferred tax liabilities: Derivative instruments, net 3,568 — Liabilities subject to compromise-interest — 35,498 Liabilities subject to compromise-interest (non-U.S.) — 14,146 Other — non-US — — Net tax liabilities $ 3,568 $ 49,644 Net tax asset $ — $ — In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible or before the attributes expire unused. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies. At December 31, 2017 and 2016, the Company recorded a valuation allowance against certain deferred tax assets of $0.7 billion and $1.3 billion, respectively. Some or all of this valuation allowance may be reversed in future periods if future taxable income of the appropriate character is available to recognize certain deferred tax assets. The Company has a U.S. federal tax net operating loss carryforward of $2.1 billion which will be carried forward to offset taxable income generated in future years, and if unutilized, will expire between 2033 and 2037. The Company has Utah state tax net operating loss carry forwards of $102.2 million which will expire between 2033 and 2037. The Company has immaterial Canadian Federal and Provincial and U.S. State tax net operating loss carry forwards in which minimal or no oil and gas operations exist. The ownership change that occurred as a result of the Company’s chapter 11 restructuring did not significantly impair the ability to utilize the net operating loss carryforwards to offset future taxable income. Without regard to the recorded valuation allowance, if the Company experiences an additional ownership change as determined under Section 382 of the Internal Revenue Code, our ability to utilize our substantial net operating loss carryforwards and other tax attributes may be limited, if we can use them at all. The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2017. Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits. The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. With certain exceptions, the income tax years 2014 through 2017 remain open to examination by the major taxing jurisdictions in which the Company has business activity. The Company has been notified that Canada intends to audit tax years 2015 and 2016. Management does not expect the results of the audit to materially impact the Company’s financial statements. The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. It is not practical to estimate the amount of unrecognized deferred tax liability related to undistributed foreign earnings at this time. No provision for Canadian income taxes and/or withholding taxes has been provided thereon. On December 22, 2017, the Tax Cuts and Jobs Act (“TCJA”) was enacted into law. The new legislation decreases the U.S. corporate federal income tax rate from 35% to 21% effective January 1, 2018. The Company does not expect any impact on recorded deferred tax balances as the re-measurement of net deferred tax assets will be offset by a change in the valuation allowance. The Act also includes a number of other 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 capital costs are recovered. These provisions are not expected to have an immediate effect on the Company. TCJA did not make significant changes to the Company’s ability to deduct intangible development costs or depletion. The Company’s significant net operating loss carryforwards generated in 2017 and before are grandfathered under the provisions of TCJA and should not be subject to the limitations imposed by the act. Further, the elimination of the Alternative Minimum Tax is beneficial because it allows the Company to recover its AMT credit carryforwards in 2018 through 2021. The amount of this expected benefit has been recorded in the financial statements as of and for the year ended December 31, 2017. Given the significant complexity of the TCJA and anticipated additional implementation guidance from the Internal Revenue Service, the remeasurement is considered provisional, and further implications of the TCJA may be identified in future periods.

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2017
Compensation And Retirement Disclosure [Abstract]
Employee Benefits	10. EMPLOYEE BENEFITS: The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $2.4 million, $2.3 million and $2.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments And Contingencies	11. COMMITMENTS AND CONTINGENCIES: The Plan provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Annual Report on Form 10-K, the claims resolution process associated with chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time. Indebtedness Claims Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest dates, unpaid post-petition interest (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Effective Date, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and post-petition interest at the default rates provided for in the debt agreements. On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, $399.0 million was distributed from the Reserve Fund to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above, which are included in reorganization items in the Consolidated Statements of Operations and $175.2 million representing the postpetition interest at the default rate, as described above, which is included in interest expense in the Consolidated Statements of Operations. 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 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) the Company had breached, by anticipatory repudiation, a contract for the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and on December 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of the contract by SPMT during the prepetition period (as amended, the “Sunoco Adversary”). In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters addressed in its proof of claim. Litigation related to this matter is proceeding in the Bankruptcy Court. At this time, we are not able to determine the likelihood or range of damages owed by or to SPMT, if any, related to this matter, or, if and when such amounts are assessed, whether such amounts would be material. Operating Lease During December 2012, the Company sold a system of pipelines and central gathering facilities (the “Pinedale LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Pinedale Lease Agreement”) relating to the use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the Pinedale LGS at the sole discretion of the Company. Annual rent for the initial term under the Pinedale Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Pinedale Lease Agreement will total approximately $213.2 million. All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases. Office space lease The Company maintains office space in Colorado, Texas, Wyoming and Utah with total remaining commitments for office leases of $5.7 million at December 31, 2017; ($1.4 million in 2018; $1.3 million in 2019; $1.3 million in 2020; $1.1 million in 2021; and $0.6 million in 2022 with the remainder due beyond five years). During the years ended December 31, 2017, 2016 and 2015, the Company recognized expense associated with its office leases in the amount of $1.6 million, $1.5 million, and $1.3 million, respectively. Delivery Commitments With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2018, the Company has long-term natural gas delivery commitments of 12.6 MMMBtu in 2019 under existing agreements. As of February 9, 2018, the Company has long-term crude oil delivery commitments of 1.7 MMBbls in 2018 and 0.3 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments. Other Claims The Company is party to disputes with respect to overriding royalty interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, and as no damage claim amount has been asserted by the claimants, we cannot reasonably estimate the potential impact of these claims. We are defending these cases vigorously, and expect these claims to be resolved in our chapter 11 proceedings. The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2017
Risks And Uncertainties [Abstract]
Concentration of Credit Risk	12. CONCENTRATION OF CREDIT RISK: The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivative contracts associated with the Company’s hedging program. The Company’s revenues related to natural gas and oil sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time. The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2017. A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2017, the Company had no single customer that represented more than 10% of its total revenues.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	13. SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to December 31, 2017 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: Leadership Changes On January 30, 2018, the Company announced the retirement of Mr. Michael D. Watford from his roles as President, Chief Executive Officer and Chairman of the Board of Directors of the Company, effective February 28, 2018. The Company concurrently announced the appointment of Brad Johnson, who has served the Company as Senior Vice President, Operations since April 2014, as interim Chief Executive Officer and a director of the Board effective February 28, 2018. The Board has not approved and the Company has not entered into any new compensation arrangements with Mr. Johnson as of the date of this Annual Report on Form 10-K. On January 30, 2018, the Company also announced that, pursuant to the Cooperation Agreement described below, effective February 28, 2018, Dr. W. Charles Helton and Mr. Roger A. Brown will resign from their positions on the Board and that Evan Lederman, an investment professional with Fir Tree Capital Management LP (“Fir Tree”), and another individual to be selected and identified based on the terms and conditions of the Cooperation Agreement (collectively, the “New Directors”) would be appointed to the Board. No changes to the composition of committees of the Board or any compensation arrangements with the New Directors have been approved by the Board or entered into by the Company as of the date of this Annual Report on Form 10-K. Cooperation Agreement with Fir Tree On January 30, 2018, the Company entered into a Cooperation Agreement (the “Cooperation Agreement”) with Fir Tree Capital Management LP (“Fir Tree”) regarding the membership and composition of the Company’s Board of Directors and related matters. Pursuant to the Cooperation Agreement, effective February 28, 2018, the Company has appointed Mr. Lederman to the Board of Directors to fill the vacancy resulting from Dr. Helton’s resignation from the Board (as discussed above). In addition, the Company will also appoint the other New Director to the Board of Directors to fill the vacancy resulting from Mr. Brown’s resignation from the Board (as discussed above) once such individual has been selected and identified as contemplated in the Cooperation Agreement. Pursuant to the Cooperation Agreement, the Company has also agreed that Fir Tree may replace either New Director in the event either New Director resigns or can no longer serve on the Board due to death, disability or other reasons prior to the later of (x) April 12, 2019 and (y) the date on which such New Director is next up for election at a meeting of the Company’s shareholders, subject to such candidate meeting certain criteria as set forth in the Cooperation Agreement. In addition, pursuant to the Cooperation Agreement, Fir Tree has agreed to abide by certain standstill provisions during a standstill period (the “Standstill Period”) ending on the Standstill End Date. In the Cooperation Agreement, “Standstill End Date” means (i) if the Company shall have delivered to Fir Tree no later than thirty calendar days prior to the deadline for submission for nominations for election to the Board at the 2019 annual meeting of shareholders a written confirmation that the New Directors (or their respective replacements or proposed replacements) will be nominated for election to the Board at the 2019 annual meeting of shareholders of the Company, the earlier of (a) fifteen calendar days prior to the deadline for submission of nominations for election to the Board at the 2020 annual meeting of shareholders of the Company pursuant to the Company’s Amended and Restated Bylaw No. 1 and (b) April 19, 2020; or (ii) if the Company shall have failed to deliver the written confirmation pursuant to clause (i) of this definition, the earlier of (c) fifteen calendar days prior to the deadline for submission for nominations for election to the Board at the 2019 annual meeting of shareholders of the Company and (d) April 19, 2019. Pursuant to the Cooperation Agreement, Fir Tree has agreed to vote its shares of the Company’s common stock in favor of the Company’s nominees and other proposals at each Annual Meeting during the Standstill Period, subject to certain limited exceptions set forth in the Cooperation Agreement. Separation Agreement In connection with his resignation from his positions as Chairman of the Board of Directors and President and Chief Executive Officer of the Company, Mr. Michael D. Watford and the Company entered into a Separation and Release Agreement (the “Separation Agreement”) dated and effective as of February 23, 2018. The release portion of the Separation Agreement will be executed by Mr. Watford and the Company following the conclusion of his employment with the Company on February 28, 2018, and will be fully effective on March 8th, 2018 provided that Mr. Watford does not revoke his acceptance thereof prior to such date. As set forth in and pursuant to the Separation Agreement, the Company will pay Mr. Watford the severance payments and benefits specified in the Employment Agreement dated as of November 6, 2017 between Mr. Watford and the Company, which was filed on November 9, 2017 as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for its quarter ended September 30, 2017. These payments and benefits are comprised of certain accrued amounts, including Mr. Watford’s base salary through February 28, 2018, a cash severance payment in the amount of $3,762,950, and the vesting and delivery of 1,226,102 shares of common stock in the Company. In addition, the Company will make available to Mr. Watford, at the Company’s expense, continued participation in the Company’s welfare benefits plans, including disability, life and health insurance for a period of up to 24 months following February 28, 2018. The foregoing description of the Separation Agreement is a summary, is not complete and is qualified in its entirety by reference to the Separation Agreement, which is filed as Exhibit 10.16 to this Annual Report on Form 10-K.

Summarized Quarterly Financial

Summarized Quarterly Financial Information	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Information (Unaudited)	14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 220,958 $ 212,657 $ 217,631 $ 240,627 $ 891,873 Gain (loss) on commodity derivatives (13,218 ) 20,717 4,650 16,263 28,412 Operating expenses 104,227 134,393 122,394 132,574 493,588 Other income (expense), net: Interest expense (85,447 ) (29,425 ) (210,107 ) (36,388 ) (361,367 ) Contract settlement (52,707 ) — — — (52,707 ) Other income (expense), net 2,491 2,665 2,730 2,430 10,316 Total other (expense) income, net (135,663 ) (26,760 ) (207,377 ) (33,958 ) (403,758 ) Reorganization items, net (57,546 ) 426,816 (227,123 ) (1,240 ) 140,907 Income (loss) before income tax provision (benefit) (89,696 ) 499,037 (334,613 ) 89,118 163,846 Income tax provision (benefit) 2 — (6,886 ) (6,410 ) (13,294 ) Net (loss) income $ (89,698 ) $ 499,037 $ (327,727 ) $ 95,528 $ 177,140 Net income (loss) per common share — basic $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 Net income (loss) per common share — fully diluted $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 2016 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 159,386 $ 146,591 $ 199,253 $ 215,861 $ 721,091 Operating expenses 126,868 94,746 99,788 99,313 420,715 Other income (expense), net: Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016) (49,903 ) (16,662 ) — — (66,565 ) Restructuring expenses (5,579 ) (1,569 ) (28 ) — (7,176 ) Contract settlement — — — (131,106 ) (131,106 ) Other income (expense), net 943 2,411 2,124 1,993 7,471 Total other (expense) income, net (54,539 ) (15,820 ) 2,096 (129,113 ) (197,376 ) Reorganization items, net — (22,183 ) (3,109 ) (22,211 ) (47,503 ) Income (loss) before income tax (benefit) provision (22,021 ) 13,842 98,452 (34,776 ) 55,497 Income tax (benefit) provision (190 ) (160 ) 45 (349 ) (654 ) Net (loss) income $ (21,831 ) $ 14,002 $ 98,407 $ (34,427 ) $ 56,151 Net income (loss) per common share — basic $ (0.27 ) $ 0.18 $ 1.23 $ (0.43 ) $ 0.70 Net income (loss) per common share — fully diluted $ (0.27 ) $ 0.17 $ 1.22 $ (0.43 ) $ 0.70

Disclosure About Oil and Gas Pr

Disclosure About Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Disclosure About Oil and Gas Producing Activities (Unaudited)	15. DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures: A. OIL AND GAS RESERVES: Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Senior Director — Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 15 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. The estimates of proved reserves and future net revenue as of December 31, 2017, are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment. The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years. The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2017, 2016 and 2015 in this annual report. Our internal professional staff works closely with our independent engineers, NSAI, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report. The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over 7 years of prior industry experience. He graduated from graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA. The following unaudited tables as of December 31, 2017, 2016 and 2015 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2017, 2016 and 2015. All such reserves are located in the Green River Basin in Wyoming and the Uinta Basin in Utah for the year ended December 31, 2017 and in Green River Basin in Wyoming, the Appalachian Basin in Pennsylvania and the Uinta Basin in Utah for the years ended December 31, 2016 and 2015. B. ANALYSES OF CHANGES IN PROVEN RESERVES: United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Reserves, December 31, 2014 67,766 4,831,194 21,993 Extensions, discoveries and additions 166 17,415 3 Sales — — — Acquisitions — — — Production (3,533 ) (268,954 ) — Revisions (42,224 ) (2,243,375 ) (12,156 ) Reserves, December 31, 2015 22,175 2,336,280 9,840 Extensions, discoveries and additions 3,519 251,634 530 Sales — — — Acquisitions — — — Production (2,912 ) (264,278 ) — Revisions (1,307 ) (2,023 ) (467 ) Reserves, December 31, 2016 21,475 2,321,613 9,903 Extensions, discoveries and additions 1,117 50,312 — Sales — (89,315 ) — Acquisitions 153 22,400 — Production (2,775 ) (260,009 ) — Revisions 7,148 910,991 (9,832 ) Reserves, December 31, 2017 27,118 2,955,992 71 United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Proved: Developed 28,481 2,245,004 9,118 Undeveloped 39,285 2,586,190 12,875 Total Proved — 2014 67,766 4,831,194 21,993 Developed 22,175 2,336,280 9,840 Undeveloped — — — Total Proved — 2015 22,175 2,336,280 9,840 Developed 21,475 2,321,613 9,903 Undeveloped — — — Total Proved — 2016 21,475 2,321,613 9,903 Developed 21,652 2,261,289 71 Undeveloped 5,466 694,703 — Total Proved — 2017 27,118 2,955,992 71 Changes in proved developed reserves : During 2017, substantially all of the changes were attributable to wells drilled in 2017. Changes in proved undeveloped reserves : As of December 31, 2016 and 2015, the Company did not include PUD reserves in its total proved reserve estimates due to uncertainty regarding its ability to continue as a going concern and the availability of capital that would be required to develop the PUD reserves. Upon emergence from chapter 11 proceedings the Company began recognizing PUDs as the substantial doubt regarding the Company’s ability to continue as a going concern had been alleviated. The changes to the Company’s proved undeveloped reserves (PUDs) during 2017 include the addition of PUDs associated with the current development plan. As there were no PUDs recognized at December 31, 2016, there are no additions, transfers or conversions to record. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years. The Company annually reviews all PUDs to ensure an appropriate development plan exists. Development plan : The development plan underlying the Company’s proved undeveloped reserves, if any, adopted each year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data, and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions of previously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders. NGLs : During 2014, the Company acquired contracts related to NGLs providing an annual election to process NGLs beginning in 2017. During 2017, the Company renegotiated its existing gas processing contracts in Wyoming. The new gas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include the NGL volumes in its reserves. C. STANDARDIZED MEASURE: The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2017, 2016 and 2015 was $2.59, $2.07 and $2.21 per Mcf, respectively, for natural gas, and $48.05, $37.90 and $42.36 per barrel, respectively, for oil and condensate. During 2014, the Company acquired contracts related to NGLs providing an annual election to process NGLs beginning in 2017. During 2017, the Company renegotiated its existing gas processing contracts in Wyoming. The new gas processing contracts are keep-whole contracts in which the Company shares in the economic benefit of processing and accordingly does not include the NGL volumes in its reserves. For 2016, and 2015 the average sales price utilized for purposes of estimating the Company’s proved reserves and future net revenues associated with NGLs was $19.17 and $20.61 per barrel, respectively. The prices utilized in the reserve report are based upon the average of prices in effect on the first day of the month for the preceding twelve-month period. The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers. As of December 31, 2017 2016 2015 Future cash inflows $ 8,965,949 $ 5,812,234 $ 6,312,095 Future production costs (3,587,581 ) (2,665,082 ) (3,006,265 ) Future development costs (1,001,024 ) (355,923 ) (358,848 ) Future income taxes — — — Future net cash flows 4,377,344 2,791,229 2,946,982 Discount at 10% (1,993,016 ) (1,100,283 ) (1,081,333 ) Standardized measure of discounted future net cash flows $ 2,384,328 $ 1,690,946 $ 1,865,649 The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. D. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: December 31, 2017 2016 2015 Standardized measure, beginning $ 1,690,946 $ 1,865,649 $ 5,233,483 Net revisions of previous quantity estimates 840,505 (9,623 ) (2,126,998 ) Extensions, discoveries and other changes 53,549 209,603 15,254 Sales of reserves in place (83,887 ) — — Acquisition of reserves 21,903 — — Changes in future development costs (329,635 ) 11,556 1,618,068 Sales of oil and gas, net of production costs (589,621 ) (454,725 ) (550,879 ) Net change in prices and production costs 572,224 (72,939 ) (6,996,416 ) Development costs incurred during the period that reduce future development costs 8,007 22,523 548,112 Accretion of discount 169,095 186,565 709,736 Net changes in production rates and other 31,242 (67,663 ) 1,551,413 Net change in income taxes — — 1,863,876 Aggregate changes 693,382 (174,703 ) (3,367,834 ) Standardized measure, ending $ 2,384,328 $ 1,690,946 $ 1,865,649 There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely. E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES: Years Ended December 31, 2017 2016 2015 United States Property Acquisitions: Unproved $ 1,399 $ 983 $ 13,845 Proved 9,147 — — Exploration* 510,710 224,277 18,164 Development 35,934 44,300 461,458 Total $ 557,190 $ 269,560 $ 493,467 * Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field. F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: Years Ended December 31, 2017 2016 2015 United States Oil and gas revenue $ 891,873 $ 721,091 $ 839,111 Production expenses (292,095 ) (266,366 ) (288,231 ) Depletion and depreciation (161,945 ) (125,121 ) (401,200 ) Ceiling test and other impairments — — (3,144,899 ) Income tax benefit (expense) (168,355 ) 83,112 (9,841 ) Total $ 269,478 $ 412,716 $ (3,005,060 ) G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2017 2016 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,215,563 $ 10,752,642 Less: accumulated depletion, depreciation and amortization (9,890,495 ) (9,742,176 ) $ 1,325,068 $ 1,010,466

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2017
Supplemental Financial Statement Information [Abstract]
Supplemental Financial Statement Information	16. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: Following are the financial statements of Ultra Petroleum Corp. (the “Parent Company”), which are included to provide additional information with respect to the Parent Company’s results of operations, financial position and cash flows on a stand-alone basis: CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2017 2016 2015 General and administrative expense $ 428 $ 650 $ 308 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) (71,876 ) (26,590 ) (81,069 ) Income (loss) from unconsolidated affiliates (183,840 ) 157,450 (3,152,078 ) Guarantee fee income — 6,073 23,029 Other expense 90 (64,888 ) (1,684 ) Reorganization items, net 433,196 (15,827 ) — Income (loss) before income taxes 177,142 55,568 (3,212,110 ) Income tax provision (benefit) 2 (583 ) (4,890 ) Net income (loss) $ 177,140 $ 56,151 $ (3,207,220 ) CONDENSED BALANCE SHEET December 31, 2017 December 31, 2016 ASSETS Current Assets: Cash and cash equivalents $ 803 $ 3,009 Accounts receivable from related companies 29,940 29,939 Other current assets — 2,100 Total current assets 30,743 35,048 Other non-current assets — — Total assets $ 30,743 $ 35,048 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ 21 $ 47 Total current liabilities 21 47 Advances from unconsolidated affiliates 1,185,359 1,623,414 Total liabilities not subject to compromise 1,185,380 1,623,461 Liabilities subject to compromise — 1,339,739 Total shareholders’ deficit (1,154,637 ) (2,928,152 ) Total liabilities and shareholders’ equity $ 30,743 $ 35,048 CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2017 2016 2015 Net cash (used in) operating activities $ (2,206 ) $ (21,309 ) $ (101,277 ) Investing Activities: Investment in subsidiaries (588,677 ) — — Dividends received — 24,089 96,297 Net cash (used in) provided by investing activities (588,677 ) 24,089 96,297 Financing activities: Deferred financing costs — — 6 Shares issued 573,774 — — Repurchased shares/net share settlements 14,903 43 — Shares re-issued from treasury — (337 ) 4,725 Net cash provided by (used in) financing activities 588,677 (294 ) 4,731 (Decrease) increase in cash during the period (2,206 ) 2,486 (249 ) Cash and cash equivalents, beginning of period 3,009 523 772 Cash and cash equivalents, end of period $ 803 $ 3,009 $ 523

Significant Accounting Polici27

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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:
Accounts Receivable	(d) Accounts Receivable:
Property, Plant and Equipment	(e) Property, Plant and Equipment:
Oil and Natural Gas Properties	(f) Oil and Natural Gas Properties: The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as The Company did not have any write-downs related to the full cost ceiling limitation in 2017 or 2016. During 2015, the Company recorded a $3.1 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve-month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials.
Inventories	(g) Inventories:
Derivative Instruments and Hedging Activities	(h) Derivative Instruments and Hedging Activities:
Deferred Financing Costs	(i) Deferred Financing Costs: Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
Income Taxes	(j) Income Taxes:
Equity Interests	(k) Equity Interests:
Earnings (Loss) Per Share	(l) Earnings (Loss) Per Share: In conjunction with our emergence from chapter 11 proceedings, on the Effective Date, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred on January 1, 2015. 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 year ended December 31, 2017, the Company had 3.9 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 6). There were no contingently issuable shares outstanding for the years ended December 31, 2016 and 2015. The following table provides a reconciliation of components of basic and diluted net income (loss) per common share: December 31, 2017 2016 2015 Net income (loss) $ 177,140 $ 56,151 $ (3,207,220 ) Weighted average common shares outstanding during the period 163,824 79,996 79,899 Effect of dilutive instruments 152 367 — Weighted average common shares outstanding during the period including the effects of dilutive instruments 163,976 80,363 79,899 Net income (loss) per common share — basic $ 1.08 $ 0.70 $ (40.14 ) Net income (loss) per common share — fully diluted $ 1.08 $ 0.70 $ (40.14 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares (1) — 749 — (1) Due to the net loss for the year ended December 31, 2015, 1.7 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.
Use of Estimates	(m) Use of Estimates:
Accounting for Share-Based Compensation	(n) Accounting for Share-Based Compensation:
Fair Value Accounting	(o) Fair Value Accounting:
Asset Retirement Obligation	(p) Asset Retirement Obligation:
Revenue Recognition	(q) Revenue Recognition: Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. The Company’s imbalance obligations as of December 31, 2017 and December 31, 2016 were immaterial.
Other Revenues	(r) Other revenues:
Capitalized Interest	(s) Capitalized Interest:
Capital Cost Accrual	(t) Capital Cost Accrual:
Reclassifications	(u) Reclassifications:
Deposits and Retainers	(v) Deposits and Retainers:
Recent Accounting Pronouncements	(w) Recent Accounting Pronouncements: Statement of Cash Flows: In November 2016, the FASB issued ASU 2016-18, (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. The ASU also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. We early adopted ASU 2016-18 at December 31, 2017 and disclosure revisions have been made for the years presented on the Consolidated Statements of Cash Flows. All prior periods have been adjusted to conform, which resulted in a (decrease)/increase in cash flows from operating activities of approximately ($1.9) million, $3.5 million, and ($0.2) million for the years ended December 31, 2017, 2016, and 2015 respectively. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statement of Cash Flows. Current Presentation December 31, 2017 December 31, 2016 December 31, 2015 Cash and Cash Equivalents $ 16,631 $ 401,478 $ 4,143 Restricted Cash 1,638 3,571 115 Total cash, cash equivalents, and restricted cash $ 18,269 $ 405,049 $ 4,258 Statement of Cash Flows: In August 2016, the FASB issued ASU 2016-15, (“ASU No. 2016-15”). ASU 2016-15 provides guidance on eight specific cash flow issues with the objective of reducing diversity in practice in regard to how cash receipts and cash payments are presented and classified in the statement of cash flows. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. We early adopted ASU 2016-15 at December 31, 2017. The guidance was applied retrospectively as required by the standard. For the year ended December 31, 2017, the material impact to the Consolidated Statement of Cash Flows was the reclassification of costs related to the extinguishment of long-term debt from cash flows provided by operating activities to cash flows used in financing activities totaling $223.8 million. There was no material impact to the Consolidated Statement of Cash Flows for the years ended December 31, 2016 and 2015. Leases: In February 2016, the FASB issued ASU 2016-02, (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. 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. The Company is evaluating the impact of ASU No. 2016-02 on its financial position and results of operations. Stock Compensation: In May 2017, the FASB issued ASU 2017-9, (“ASU No. 2017-09”) which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of ASU No. 2017-08 to have a material impact on its 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. Revenues from Contracts with Customers: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, 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. We have evaluated the provisions of ASU 2014-09 and assessed the impact it may have on our financial position and results of operations. As part of our assessment work, we have done the following: • We have completed training of the new ASU’s revenue recognition model, dedicated resources to its implementation, and initiated contract review and documentation; including analyzing the standard’s impact on our contract portfolio, comparing historical accounting policies and practices to the requirements of the new standard, and identifying differences from applying the requirements of the new standards to our contracts. • We have evaluated each revenue stream, including sales of oil, natural gas, and other revenues, noting no significant changes to revenue recognition under the new standard except as noted below. • We had previously elected to utilize the entitlements method, which will no longer be applicable under ASU 2014-09. We do not anticipate the change from the entitlements method to have a material impact on our financial statements. • We evaluated our product sales contracts in order to determine if there were remaining performance obligations. We have determined that our product sales are primarily short-term in nature with contract periods of one year or less. We have evaluated product sales contracts with terms greater than one year and anticipate using the practical expedient in ASC 606-10-50-14(a) which will not require disclosure of the transaction price allocated to remaining performance obligations. • We have evaluated our product sales contracts and do not anticipate them to give rise to contract assets or liabilities. • We have evaluated the expanded disclosure requirements under the new standard and reviewed our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures. We do not anticipate any issues in providing the appropriate information to be available for the disclosures. The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the modified retrospective method). The Company will adopt the standard as of January 1, 2018 using the modified retrospective method. The Company is currently estimating the impact to beginning retained earnings to be immaterial to the overall consolidated financial statements based on implementation through the modified retrospective approach .

Chapter 11 Proceedings (Tables)

Chapter 11 Proceedings (Tables)	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Schedule of Liabilities Subject to Compromise	The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through December 31, 2017: December 31, 2017 Liabilities subject to compromise at December 31, 2016 4,038,041 Debt extinguishment-cash (2,521,493 ) Debt extinguishment-non-cash (1,339,740 ) Contract settlement (169,600 ) Reclassified to accrued liabilities (7,208 ) Liabilities subject to compromise at December 31, 2017 $ —
Schedule of Reorganization Items	The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the years ended December 31, 2017, 2016, and 2015: For the Twelve Months Ended December 31, 2017 2016 2015 Professional fees (1) $ (66,529 ) $ (11,781 ) $ — Gains (losses) (2) 431,107 — — Deferred financing costs — (18,742 ) — Contract settlements — (17,350 ) — Make-whole fees (3) (223,838 ) — — Other (4) 167 370 — Total Reorganization items, net $ 140,907 $ (47,503 ) $ — (1) The year ended December 31, 2017 includes $1.1 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings. (2) Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 and 2024 Notes. (3) Make-whole fees represent the Bankruptcy Court order denying our objection to the make-whole claims, as further described in Note 11. (4) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Significant Accounting Polici29

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Reconciliation of Components of Basic and Diluted Net Income Per Common Share	Share based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. For the year ended December 31, 2017, the Company had 3.9 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 6). There were no contingently issuable shares outstanding for the years ended December 31, 2016 and 2015. The following table provides a reconciliation of components of basic and diluted net income (loss) per common share: December 31, 2017 2016 2015 Net income (loss) $ 177,140 $ 56,151 $ (3,207,220 ) Weighted average common shares outstanding during the period 163,824 79,996 79,899 Effect of dilutive instruments 152 367 — Weighted average common shares outstanding during the period including the effects of dilutive instruments 163,976 80,363 79,899 Net income (loss) per common share — basic $ 1.08 $ 0.70 $ (40.14 ) Net income (loss) per common share — fully diluted $ 1.08 $ 0.70 $ (40.14 ) Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares (1) — 749 — (1) Due to the net loss for the year ended December 31, 2015, 1.7 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.
Reconciliation of Cash, Cash Equivalents, and Restricted Cash	Statement of Cash Flows: In November 2016, the FASB issued ASU 2016-18, (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. The ASU also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. We early adopted ASU 2016-18 at December 31, 2017 and disclosure revisions have been made for the years presented on the Consolidated Statements of Cash Flows. All prior periods have been adjusted to conform, which resulted in a (decrease)/increase in cash flows from operating activities of approximately ($1.9) million, $3.5 million, and ($0.2) million for the years ended December 31, 2017, 2016, and 2015 respectively. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statement of Cash Flows. Current Presentation December 31, 2017 December 31, 2016 December 31, 2015 Cash and Cash Equivalents $ 16,631 $ 401,478 $ 4,143 Restricted Cash 1,638 3,571 115 Total cash, cash equivalents, and restricted cash $ 18,269 $ 405,049 $ 4,258

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
Schedule of Asset Retirement Obligations	The following table summarizes the activities for the Company’s asset retirement obligations for the years ended: December 31, 2017 2016 Asset retirement obligations at beginning of period $ 157,173 $ 146,210 Accretion expense 11,689 10,252 Liabilities incurred 8,174 1,317 Liabilities divested (1) (4,812 ) — Liabilities acquired 1,456 — Liabilities settled (598 ) (170 ) Revisions of estimated liabilities 18 (436 ) Asset retirement obligations at end of period 173,100 157,173 Less: current asset retirement obligations (263 ) (239 ) Long-term asset retirement obligations $ 172,837 $ 156,934 (1) During the quarter ended December 31, 2017, the Company divested certain non-core properties in north-central Pennsylvania for net cash proceeds of approximately $115.0 million, subject to post-close adjustments.

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2017
Oil And Gas Property [Abstract]
Schedule of Oil and Gas Properties	December 31, 2017 December 31, 2016 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,215,563 $ 10,752,642 Less: Accumulated depletion, depreciation and amortization (9,890,495 ) (9,742,176 ) 1,325,068 1,010,466

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Schedule of Property, Plant and Equipment	December 31, 2017 2016 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 3,018 (2,464 ) 554 603 Office equipment 309 (214 ) 95 138 Leasehold improvements 486 (366 ) 120 185 Land 4,637 — 4,637 4,637 Other 15,773 (11,610 ) 4,163 2,132 Property, plant and equipment, net $ 24,223 $ (14,654 ) $ 9,569 $ 7,695

Debt and Other Long-Term Liab33

Debt and Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Outstanding Debt And Other Long Term Obligations Tables [Abstract]
Summary of Outstanding Debt and Other Long Term Obligations	December 31, 2017 December 31, 2016 Total Debt: Term loan, secured, due 2024 $ 975,000 $ — 6.875% Senior, unsecured Notes due 2022 700,000 — 7.125% Senior, unsecured Notes due 2025 500,000 — 6.125% Senior Notes due 2024 — 850,000 5.75% Senior Notes due 2018 — 450,000 Senior Notes issued by Ultra Resources, Inc. — 1,460,000 Credit Agreement — 999,000 Total long-term debt 2,175,000 3,759,000 Less: Deferred financing costs (58,789 ) — Less: Liabilities subject to compromise (1) (See Note 1) — (3,759,000 ) Total long-term debt not subject to compromise $ 2,116,211 $ — Other long-term obligations: Other long-term obligations $ 197,728 $ 177,088
Summary of Aggregate Maturities of Debt	Aggregate maturities of debt at December 31, 2017: 2018 2019 2020 2021 2022 Beyond 5 years Total $ — $ 7,313 $ 9,750 $ 9,750 $ 709,750 $ 1,438,437 $ 2,175,000 (1) All of our indebtedness that was outstanding as of December 31, 2016 was classified as liabilities subject to compromise in the Consolidated Balance Sheets. See below for information about the indebtedness we incurred in connection with, and that is now outstanding following our emergence from bankruptcy.

Share Based Compensation (Table

Share Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Valuation and Expense Information	Valuation and Expense Information Year Ended December 31, 2017 2016 2015 Total cost of share-based payment plans $ 53,952 $ 8,013 $ 6,137 Amounts capitalized in oil and gas properties and equipment $ 13,975 $ 2,451 $ 2,009 Amounts charged against income, before income tax benefit $ 39,977 $ 5,562 $ 4,128 Amount of related income tax benefit recognized in income before valuation allowances $ 15,927 $ 2,216 $ 1,645
Securities Authorized for Issuance Under Equity Compensation Plans	Plan Category Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (000’s) Equity compensation plans approved by security holders 14,457 Equity compensation plans not approved by security holders n/a Total 14,457

Derivative Financial Instrume35

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Open Commodity Derivative Contracts	At December 31, 2017, the Company had the following open commodity derivative contracts to manage commodity price risk. Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Price/MMBTU Fair Value - December 31, 2017 Natural Gas Asset (Liability) Fixed price swaps NYMEX-Henry Hub April-Oct 2018 380,000 $ 2.97 $ 15,419 Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Floor Price ($/MMBTU) Ceiling Price ($/MMBTU) Fair Value - December 31, 2017 Collars NYMEX-Henry Hub Jan-Mar 2018 40,000 $ 3.23 $ 3.54 $ 1,446 Subsequent to December 31, 2017 and through February 15, 2018, the Company has entered into the following open commodity derivative contracts to manage commodity price risk. Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Price/MMBTU Natural Gas Fixed price swaps NYMEX-Henry Hub April-Oct 2018 390,000 $ 2.79 NYMEX-Henry Hub Nov-Dec 2018 400,000 $ 2.88 NYMEX-Henry Hub Jan-Mar 2019 200,000 $ 2.91 Type Commodity Reference Price Remaining Contract Period Volume/ MMBTU/day Average Differential/MMBTU Natural Gas Basis Swap Contracts(1) NW Rockies Basis Swap Mar-Dec 2018 30,000 $ (0.58 ) NW Rockies Basis Swap April-Oct 2018 140,000 $ (0.62 ) Type Commodity Reference Price Remaining Contract Period Volume/ Bbls/day Average Price/Bbls Crude Oil Fixed price swaps NYMEX-WTI Feb-Dec 2018 2,000 $ 62.17 NYMEX-WTI Mar-Dec 2018 2,000 $ 57.43
Summary of Pre-tax Realized and Unrealized Gains and Losses Recognized Related to Natural Gas Derivative Instruments	The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015: For the Year Ended December 31, Commodity Derivatives: 2017 2016 2015 Realized gain on commodity derivatives-natural gas (1) $ 11,446 $ — $ 146,801 Unrealized gain (loss) on commodity derivatives (1) 16,966 — (104,190 ) Total gain on commodity derivatives $ 28,412 $ — $ 42,611 (1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Assets Measured at Fair Value	Level 1 Level 2 Level 3 Total Assets: Current derivative asset $ — $ 16,865 $ — $ 16,865
Carrying Values and Estimated Fair Values of Financial Instruments	December 31, 2017 December 31, 2016 (1) Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Term Loan, secured due 2024 $ 975,000 $ 975,000 $ — $ — 6.875% Senior, unsecured Notes, due 2022 700,000 701,750 — — 7.125% Senior, unsecured Notes, due 2025 500,000 505,000 — — Credit Agreement, secured — — — — 7.31% Notes due March 2016, issued 2009 — — 62,000 64,266 4.98% Notes due January 2017, issued 2010 — — 116,000 123,967 5.92% Notes due March 2018, issued 2008 — — 200,000 224,025 5.75% Notes due December 2018, issued 2013 — — 450,000 465,630 7.77% Notes due March 2019, issued 2009 — — 173,000 204,854 5.50% Notes due January 2020, issued 2010 — — 207,000 233,932 4.51% Notes due October 2020, issued 2010 — — 315,000 337,528 5.60% Notes due January 2022, issued 2010 — — 87,000 99,983 4.66% Notes due October 2022, issued 2010 — — 35,000 38,225 6.125% Notes due October 2024, issued 2014 — — 850,000 893,325 5.85% Notes due January 2025, issued 2010 — — 90,000 106,299 4.91% Notes due October 2025, issued 2010 — — 175,000 193,665 Credit Facility due October 2016 — — 999,000 999,000 $ 2,175,000 $ 2,181,750 $ 3,759,000 $ 3,984,699 (1) At December 31, 2016, the debt included in the table above is a component of liabilities subject to compromise in our Consolidated Balance Sheets. See Note 1.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Summary of Income (Loss) Before Income Tax Benefit	Income (loss) before income tax benefit is as follows: Year Ended December 31, 2017 2016 2015 United States $ (197,136 ) $ 134,959 $ (3,249,590 ) Foreign 360,982 (79,462 ) 37,966 Total $ 163,846 $ 55,497 $ (3,211,624 )
Summary of Consolidated Income Tax (Benefit) Provision	The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2017 2016 2015 Current tax: U.S. federal, state and local $ (13,296 ) $ (72 ) $ — Foreign 2 (583 ) (3,414 ) Total current tax (benefit) (13,294 ) (655 ) (3,414 ) Deferred tax: Foreign — 1 (990 ) Total deferred tax (benefit) expense — 1 (990 ) Total income tax (benefit) $ (13,294 ) $ (654 ) $ (4,404 )
Summary of Income Tax Provision (Benefit) from Continuing Operations	The income tax provision (benefit) from continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following: Year Ended December 31, 2017 2016 2015 Income tax provision (benefit) computed at the U.S. statutory rate $ 57,346 $ 19,424 $ (1,124,069 ) State income tax (benefit) provision net of federal effect (25,519 ) (2,335 ) (12,998 ) Valuation allowance (562,491 ) (31,083 ) 1,147,619 Tax effect of rate change 463,113 — 12,898 Sale of Pennsylvania assets 130,552 — 0 Foreign rate differential (3,150 ) 17,388 (26,740 ) Reorganization items (78,549 ) — — Other, net 5,404 (4,048 ) (1,114 ) Total income tax (benefit) $ (13,294 ) $ (654 ) $ (4,404 )
Summary of Deferred Tax Assets and Liabilities	The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows: December 31, 2017 2016 Deferred tax assets: Property and equipment 181,524 603,045 Deferred gain 22,256 40,867 U.S. federal tax credit carryforwards 987 15,967 U.S. net operating loss carryforwards 450,623 428,212 U.S. state net operating loss carryforwards 4,038 71,323 Non-U.S. net operating loss carryforwards 6,556 30,211 Asset retirement obligations 36,624 55,700 Liabilities subject to compromise-contract settlement — 59,166 Incentive compensation/other, net 8,308 16,088 710,916 1,320,579 Valuation allowance (707,348 ) (1,270,935 ) Net deferred tax assets $ 3,568 $ 49,644 Deferred tax liabilities: Derivative instruments, net 3,568 — Liabilities subject to compromise-interest — 35,498 Liabilities subject to compromise-interest (non-U.S.) — 14,146 Other — non-US — — Net tax liabilities $ 3,568 $ 49,644 Net tax asset $ — $ —

Summarized Quarterly Financia38

Summarized Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summary of Quarterly Financial Information	2017 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 220,958 $ 212,657 $ 217,631 $ 240,627 $ 891,873 Gain (loss) on commodity derivatives (13,218 ) 20,717 4,650 16,263 28,412 Operating expenses 104,227 134,393 122,394 132,574 493,588 Other income (expense), net: Interest expense (85,447 ) (29,425 ) (210,107 ) (36,388 ) (361,367 ) Contract settlement (52,707 ) — — — (52,707 ) Other income (expense), net 2,491 2,665 2,730 2,430 10,316 Total other (expense) income, net (135,663 ) (26,760 ) (207,377 ) (33,958 ) (403,758 ) Reorganization items, net (57,546 ) 426,816 (227,123 ) (1,240 ) 140,907 Income (loss) before income tax provision (benefit) (89,696 ) 499,037 (334,613 ) 89,118 163,846 Income tax provision (benefit) 2 — (6,886 ) (6,410 ) (13,294 ) Net (loss) income $ (89,698 ) $ 499,037 $ (327,727 ) $ 95,528 $ 177,140 Net income (loss) per common share — basic $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 Net income (loss) per common share — fully diluted $ (1.12 ) $ 2.76 $ (1.67 ) $ 0.49 $ 1.08 2016 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 159,386 $ 146,591 $ 199,253 $ 215,861 $ 721,091 Operating expenses 126,868 94,746 99,788 99,313 420,715 Other income (expense), net: Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016) (49,903 ) (16,662 ) — — (66,565 ) Restructuring expenses (5,579 ) (1,569 ) (28 ) — (7,176 ) Contract settlement — — — (131,106 ) (131,106 ) Other income (expense), net 943 2,411 2,124 1,993 7,471 Total other (expense) income, net (54,539 ) (15,820 ) 2,096 (129,113 ) (197,376 ) Reorganization items, net — (22,183 ) (3,109 ) (22,211 ) (47,503 ) Income (loss) before income tax (benefit) provision (22,021 ) 13,842 98,452 (34,776 ) 55,497 Income tax (benefit) provision (190 ) (160 ) 45 (349 ) (654 ) Net (loss) income $ (21,831 ) $ 14,002 $ 98,407 $ (34,427 ) $ 56,151 Net income (loss) per common share — basic $ (0.27 ) $ 0.18 $ 1.23 $ (0.43 ) $ 0.70 Net income (loss) per common share — fully diluted $ (0.27 ) $ 0.17 $ 1.22 $ (0.43 ) $ 0.70

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Analyses of Changes in Proven Reserves	United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Reserves, December 31, 2014 67,766 4,831,194 21,993 Extensions, discoveries and additions 166 17,415 3 Sales — — — Acquisitions — — — Production (3,533 ) (268,954 ) — Revisions (42,224 ) (2,243,375 ) (12,156 ) Reserves, December 31, 2015 22,175 2,336,280 9,840 Extensions, discoveries and additions 3,519 251,634 530 Sales — — — Acquisitions — — — Production (2,912 ) (264,278 ) — Revisions (1,307 ) (2,023 ) (467 ) Reserves, December 31, 2016 21,475 2,321,613 9,903 Extensions, discoveries and additions 1,117 50,312 — Sales — (89,315 ) — Acquisitions 153 22,400 — Production (2,775 ) (260,009 ) — Revisions 7,148 910,991 (9,832 ) Reserves, December 31, 2017 27,118 2,955,992 71 United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Proved: Developed 28,481 2,245,004 9,118 Undeveloped 39,285 2,586,190 12,875 Total Proved — 2014 67,766 4,831,194 21,993 Developed 22,175 2,336,280 9,840 Undeveloped — — — Total Proved — 2015 22,175 2,336,280 9,840 Developed 21,475 2,321,613 9,903 Undeveloped — — — Total Proved — 2016 21,475 2,321,613 9,903 Developed 21,652 2,261,289 71 Undeveloped 5,466 694,703 — Total Proved — 2017 27,118 2,955,992 71
Standardized Measure	As of December 31, 2017 2016 2015 Future cash inflows $ 8,965,949 $ 5,812,234 $ 6,312,095 Future production costs (3,587,581 ) (2,665,082 ) (3,006,265 ) Future development costs (1,001,024 ) (355,923 ) (358,848 ) Future income taxes — — — Future net cash flows 4,377,344 2,791,229 2,946,982 Discount at 10% (1,993,016 ) (1,100,283 ) (1,081,333 ) Standardized measure of discounted future net cash flows $ 2,384,328 $ 1,690,946 $ 1,865,649
Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows	December 31, 2017 2016 2015 Standardized measure, beginning $ 1,690,946 $ 1,865,649 $ 5,233,483 Net revisions of previous quantity estimates 840,505 (9,623 ) (2,126,998 ) Extensions, discoveries and other changes 53,549 209,603 15,254 Sales of reserves in place (83,887 ) — — Acquisition of reserves 21,903 — — Changes in future development costs (329,635 ) 11,556 1,618,068 Sales of oil and gas, net of production costs (589,621 ) (454,725 ) (550,879 ) Net change in prices and production costs 572,224 (72,939 ) (6,996,416 ) Development costs incurred during the period that reduce future development costs 8,007 22,523 548,112 Accretion of discount 169,095 186,565 709,736 Net changes in production rates and other 31,242 (67,663 ) 1,551,413 Net change in income taxes — — 1,863,876 Aggregate changes 693,382 (174,703 ) (3,367,834 ) Standardized measure, ending $ 2,384,328 $ 1,690,946 $ 1,865,649
Costs Incurred in Oil and Gas Exploration and Development Activities	Years Ended December 31, 2017 2016 2015 United States Property Acquisitions: Unproved $ 1,399 $ 983 $ 13,845 Proved 9,147 — — Exploration* 510,710 224,277 18,164 Development 35,934 44,300 461,458 Total $ 557,190 $ 269,560 $ 493,467 * Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.
Results of operations for oil and gas producing activities	F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES: Years Ended December 31, 2017 2016 2015 United States Oil and gas revenue $ 891,873 $ 721,091 $ 839,111 Production expenses (292,095 ) (266,366 ) (288,231 ) Depletion and depreciation (161,945 ) (125,121 ) (401,200 ) Ceiling test and other impairments — — (3,144,899 ) Income tax benefit (expense) (168,355 ) 83,112 (9,841 ) Total $ 269,478 $ 412,716 $ (3,005,060 )
Capitalized Costs Relating to Oil and Gas Producing Activities	G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2017 2016 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 11,215,563 $ 10,752,642 Less: accumulated depletion, depreciation and amortization (9,890,495 ) (9,742,176 ) $ 1,325,068 $ 1,010,466

Supplemental Financial Statem40

Supplemental Financial Statement Information (Tables)	12 Months Ended
	Dec. 31, 2017
Parent Company Financial Statements [Abstract]
Supplemental Statement Of Operations Disclosures Parent Company	CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2017 2016 2015 General and administrative expense $ 428 $ 650 $ 308 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) (71,876 ) (26,590 ) (81,069 ) Income (loss) from unconsolidated affiliates (183,840 ) 157,450 (3,152,078 ) Guarantee fee income — 6,073 23,029 Other expense 90 (64,888 ) (1,684 ) Reorganization items, net 433,196 (15,827 ) — Income (loss) before income taxes 177,142 55,568 (3,212,110 ) Income tax provision (benefit) 2 (583 ) (4,890 ) Net income (loss) $ 177,140 $ 56,151 $ (3,207,220 )
Supplemental Balance Sheet Disclosures Parent Company	CONDENSED BALANCE SHEET December 31, 2017 December 31, 2016 ASSETS Current Assets: Cash and cash equivalents $ 803 $ 3,009 Accounts receivable from related companies 29,940 29,939 Other current assets — 2,100 Total current assets 30,743 35,048 Other non-current assets — — Total assets $ 30,743 $ 35,048 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accrued and other current liabilities $ 21 $ 47 Total current liabilities 21 47 Advances from unconsolidated affiliates 1,185,359 1,623,414 Total liabilities not subject to compromise 1,185,380 1,623,461 Liabilities subject to compromise — 1,339,739 Total shareholders’ deficit (1,154,637 ) (2,928,152 ) Total liabilities and shareholders’ equity $ 30,743 $ 35,048
Supplemental Cash Flow Statement Disclosures Parent Company	CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2017 2016 2015 Net cash (used in) operating activities $ (2,206 ) $ (21,309 ) $ (101,277 ) Investing Activities: Investment in subsidiaries (588,677 ) — — Dividends received — 24,089 96,297 Net cash (used in) provided by investing activities (588,677 ) 24,089 96,297 Financing activities: Deferred financing costs — — 6 Shares issued 573,774 — — Repurchased shares/net share settlements 14,903 43 — Shares re-issued from treasury — (337 ) 4,725 Net cash provided by (used in) financing activities 588,677 (294 ) 4,731 (Decrease) increase in cash during the period (2,206 ) 2,486 (249 ) Cash and cash equivalents, beginning of period 3,009 523 772 Cash and cash equivalents, end of period $ 803 $ 3,009 $ 523

Chapter 11 Proceedings - Additi

Chapter 11 Proceedings - Additional Information (Details) - USD ($)	Apr. 12, 2017	Dec. 31, 2017	Feb. 08, 2017	Dec. 31, 2016
Bankruptcy Proceedings [Line Items]
Percentage of principal amount of debt held by plan support parties		66.67%
Claims settled		$ 399,000,000
Revolving Credit Facility
Bankruptcy Proceedings [Line Items]
Liens and security interests percentage		85.00%
BCA
Bankruptcy Proceedings [Line Items]
Aggregate committed amount of stock to be purchased upon plan reorganization		$ 580,000,000
Percentage of implied plan value discount		20.00%
Rights offering commitment premium		6.00%
BCA | Hold Co Noteholder
Bankruptcy Proceedings [Line Items]
Aggregate committed amount of stock to be purchased upon plan reorganization	$ 435,000,000
BCA | HoldCo Equityholder Rights Offering
Bankruptcy Proceedings [Line Items]
Aggregate committed amount of stock to be purchased upon plan reorganization	145,000,000
Exit Financing Commitment Letter | Prepetition Credit Agreement
Bankruptcy Proceedings [Line Items]
Claims settled	999,000,000
Exit Financing Commitment Letter | Prepetition Senior Notes
Bankruptcy Proceedings [Line Items]
Claims settled	1,460,000,000
Exit Financing Commitment Letter | Senior Unsecured Notes Due 2018
Bankruptcy Proceedings [Line Items]
Claims settled	450,000,000
Exit Financing Commitment Letter | Senior Unsecured Notes Due 2024
Bankruptcy Proceedings [Line Items]
Claims settled	850,000,000
Exit Financing Commitment Letter | Barclays Bank PLC
Bankruptcy Proceedings [Line Items]
Secured and unsecured financing provided by Barclays			$ 2,400,000,000
5.75% Senior Notes Due 2018
Bankruptcy Proceedings [Line Items]
Stated interest rate				5.75%
6.125% Senior Notes Due 2024
Bankruptcy Proceedings [Line Items]
Stated interest rate				6.125%
RBL Credit Agreement | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Credit facility, current borrowing capacity	400,000,000	$ 425,000,000
RBL Credit Agreement | Exit Financing Commitment Letter | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Credit facility, current borrowing capacity	400,000,000
RBL Term Loan Secured Due 2024 | Barclays Bank PLC | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
RBL Credit Agreement, initial term loan	800,000,000
RBL Term Loan Secured Due 2024 | Exit Financing Commitment Letter | Barclays Bank PLC | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
RBL Credit Agreement, initial term loan	$ 800,000,000
6.875% Senior, Unsecured Notes Due 2022
Bankruptcy Proceedings [Line Items]
Stated interest rate		6.875%
6.875% Senior, Unsecured Notes Due 2022 | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Stated interest rate	6.875%
Debt instrument, face amount	$ 700,000,000
6.875% Senior, Unsecured Notes Due 2022 | Exit Financing Commitment Letter | Wilmington Trust | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Stated interest rate	6.875%
Debt instrument, face amount	$ 700,000,000
Debt instrument face amount percentage	100.00%
7.125% Senior, Unsecured Notes Due 2025
Bankruptcy Proceedings [Line Items]
Stated interest rate		7.125%
7.125% Senior, Unsecured Notes Due 2025 | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Stated interest rate	7.125%
Debt instrument, face amount	$ 500,000,000
7.125% Senior, Unsecured Notes Due 2025 | Exit Financing Commitment Letter | Wilmington Trust | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Stated interest rate	7.125%
Debt instrument, face amount	$ 500,000,000
Debt instrument face amount percentage	98.507%
2022 and 2025 Notes | Exit Financing Commitment Letter | Wilmington Trust | Ultra Resources, Inc.
Bankruptcy Proceedings [Line Items]
Net proceeds from Notes sold	$ 1,185,000,000

Chapter 11 Proceedings - Compon

Chapter 11 Proceedings - Components of Liabilities Subject to Compromise (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Liabilities Subject To Compromise [Abstract]
Liabilities subject to compromise at December 31, 2016	$ 4,038,041
Debt extinguishment-cash	(2,521,493)
Debt extinguishment-non-cash	(1,339,740)
Contract settlement	(169,600)
Reclassified to accrued liabilities	(7,208)
Liabilities subject to compromise at December 31, 2017	$ 0

Chapter 11 Proceedings - Costs

Chapter 11 Proceedings - Costs of Reorganization (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reorganization Items [Abstract]
Professional fees								$ (66,529)	$ (11,781)	$ 0
Gains (losses)								431,107	0	0
Deferred financing costs								0	(18,742)	0
Contract settlements								0	(17,350)	0
Make-whole fees								(223,838)	0	0
Other								167	370	0
Total Reorganization items, net	$ (1,240)	$ (227,123)	$ 426,816	$ (57,546)	$ (22,211)	$ (3,109)	$ (22,183)	$ 140,907	$ (47,503)	$ 0

Chapter 11 Proceedings - Cost44

Chapter 11 Proceedings - Costs of Reorganization (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Reorganization Items [Abstract]
Accrued and unpaid professional fees	$ 1.1

Significant Accounting Polici45

Significant Accounting Policies - Additional Information (Details)	Apr. 12, 2017	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Significant Accounting Policies [Line Items]
Discount rate future net revenues		10.00%
Ceiling test limitation		$ 0	$ 0	$ 3,100,000,000
Inventory		$ 13,450,000	$ 4,906,000
Conversion ratio	0.521562
Contingently issuable shares | shares		3.9	0	0
Increase decrease in cash flows from operating activities		$ (1,900,000)	$ 3,500,000	$ (200,000)
Extinguishment of long-term debt		223,838,000
Pipe and Production Equipment [Member]
Significant Accounting Policies [Line Items]
Inventory		12,300,000
Crude Oil Inventory [Member]
Significant Accounting Policies [Line Items]
Inventory		$ 1,100,000

Significant Accounting Polici46

Significant Accounting Policies - Reconciliation of Components of Basic and Diluted Net Income Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share Reconciliation [Abstract]
Net income (loss)	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	$ 177,140	$ 56,151	$ (3,207,220)
Weighted average common shares outstanding during the period									163,824	79,996	79,899
Effect of dilutive instruments									152	367
Weighted average common shares outstanding during the period including the effects of dilutive instruments									163,976	80,363	79,899
Net income (loss) per common share — basic	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ (0.43)	$ 1.23	$ 0.18	$ (0.27)	$ 1.08	$ 0.70	$ (40.14)
Net income (loss) per common share — fully diluted	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ (0.43)	$ 1.22	$ 0.17	$ (0.27)	$ 1.08	$ 0.70	$ (40.14)
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares										749

Significant Accounting Polici47

Significant Accounting Policies - Reconciliation of Components of Basic and Diluted Net Income Per Common Share (Parenthetical) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share	749
Options and Restricted Stock Units
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from computation of earnings per share		1,700

Significant Accounting Polici48

Significant Accounting Policies - Reconciliation of Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash And Cash Equivalents And Restricted Cash At Carrying Value [Abstract]
Cash and cash equivalents	$ 16,631	$ 401,478	$ 4,143
Restricted Cash	1,638	3,571	115
Total cash, cash equivalents, and restricted cash	$ 18,269	$ 405,049	$ 4,258	$ 9,036

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$ 157,173	$ 146,210
Accretion expense	11,689	10,252
Liabilities incurred	8,174	1,317
Liabilities divested	(4,812)
Liabilities acquired	1,456
Liabilities settled	(598)	(170)
Revisions of estimated liabilities	18	(436)
Asset retirement obligations at end of period	173,100	157,173
Less: current asset retirement obligations	(263)	(239)
Long-term asset retirement obligations	$ 172,837	$ 156,934

Asset Retirement Obligation - (

Asset Retirement Obligation - (Parenthetical) (Details) $ in Millions	3 Months Ended
	Dec. 31, 2017USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Net cash proceeds subject to post-close adjustments	$ 115

Oil and Gas Properties - Schedu

Oil and Gas Properties - Schedule of Oil and Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,215,563	$ 10,752,642
Less: Accumulated depletion, depreciation and amortization	(9,890,495)	(9,742,176)
Proven	$ 1,325,068	$ 1,010,466

Oil and Gas Properties - Additi

Oil and Gas Properties - Additional Information (Details) - $ / Mcfe	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Property [Abstract]
DD&A per Mcfe	0.59	0.44	1.38

Property, Plant & Equipment (De

Property, Plant & Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Cost	$ 24,223
Accumulated Depreciation	(14,654)
Property, plant and equipment	9,569	$ 7,695
Computer Equipment
Property Plant And Equipment [Line Items]
Cost	3,018
Accumulated Depreciation	(2,464)
Property, plant and equipment	554	603
Office Equipment
Property Plant And Equipment [Line Items]
Cost	309
Accumulated Depreciation	(214)
Property, plant and equipment	95	138
Leasehold Improvements
Property Plant And Equipment [Line Items]
Cost	486
Accumulated Depreciation	(366)
Property, plant and equipment	120	185
Land
Property Plant And Equipment [Line Items]
Cost	4,637
Property, plant and equipment	4,637	4,637
Other
Property Plant And Equipment [Line Items]
Cost	15,773
Accumulated Depreciation	(11,610)
Property, plant and equipment	$ 4,163	$ 2,132

Debt and Other Long-Term Liab54

Debt and Other Long-Term Liabilities - Summary of Outstanding Debt and Other Long Term Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Total Debt:
Total long-term debt	$ 2,175,000	$ 3,759,000
Less: Deferred financing costs	(58,789)
Less: Liabilities subject to compromise		(3,759,000)
Total long-term debt not subject to compromise	2,116,211
Other long-term obligations:
Other long-term obligations	197,728	177,088
Senior Notes | Ultra Resources, Inc.
Total Debt:
Total long-term debt		1,460,000
Term Loan Secured Due 2024
Total Debt:
Total long-term debt	975,000
6.125% Senior Notes Due 2024
Total Debt:
Total long-term debt		850,000
6.875% Senior, Unsecured Notes Due 2022
Total Debt:
Total long-term debt	700,000
5.75% Senior Notes Due 2018
Total Debt:
Total long-term debt		450,000
7.125% Senior, Unsecured Notes Due 2025
Total Debt:
Total long-term debt	500,000
Credit Agreement | Ultra Resources, Inc.
Total Debt:
Total long-term debt	$ 0
Credit Facility Due October 2016
Total Debt:
Total long-term debt		$ 999,000

Debt and Other Long-Term Liab55

Debt and Other Long-Term Liabilities - Summary of Outstanding Debt and Other Long Term Obligations (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Term Loan Secured Due 2024
Debt Instrument [Line Items]
Maturity date	Apr. 12, 2024
6.875% Senior, Unsecured Notes Due 2022
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2022
Stated interest rate	6.875%
7.125% Senior, Unsecured Notes Due 2025
Debt Instrument [Line Items]
Maturity date	Apr. 15, 2025
Stated interest rate	7.125%
6.125% Senior Notes Due 2024
Debt Instrument [Line Items]
Maturity date		Oct. 1, 2024
Stated interest rate		6.125%
5.75% Senior Notes Due 2018
Debt Instrument [Line Items]
Maturity date		Dec. 15, 2018
Stated interest rate		5.75%

Debt and Other Long-Term Liab56

Debt and Other Long-Term Liabilities - Summary of Aggregate Maturities of Debt (Details) $ in Thousands	Dec. 31, 2017USD ($)
Long Term Liabilities [Abstract]
2,019	$ 7,313
2,020	9,750
2,021	9,750
2,022	709,750
Beyond 5 years	1,438,437
Total	$ 2,175,000

Debt and Other Long-Term Liab57

Debt and Other Long-Term Liabilities - Ultra Resources, Inc. - Credit Agreement - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Apr. 12, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt, gross	$ 2,175,000	$ 2,175,000		$ 3,759,000
Ultra Resources, Inc. | RBL Credit Agreement
Debt Instrument [Line Items]
Credit facility, current borrowing capacity	425,000	425,000	$ 400,000
Long-term debt, gross	0	0
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal
Debt Instrument [Line Items]
Borrowing Base	1,400,000	1,400,000	$ 1,200,000
Ultra Resources, Inc. | RBL 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	$ 50,000
Amount of commitments utilized	$ 34,500
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal | Revolving Credit Facility
Debt Instrument [Line Items]
Minimum required interest coverage ratio, as percentage		250.00%
Minimum required current ratio, as percentage		100.00%
Minimum required consolidated net leverage ratio, as percentage on or before December 31, 2017		425.00%
Minimum required consolidated net leverage ratio, as percentage after December 31, 2017		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 RBL Credit Agreement
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Minimum
Debt Instrument [Line Items]
Variable rate		2.50%
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal | Revolving Credit Facility | LIBOR | Maximum
Debt Instrument [Line Items]
Variable rate		3.50%
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Minimum
Debt Instrument [Line Items]
Variable rate		1.50%
Ultra Resources, Inc. | RBL Credit Agreement | Bank Of Montreal | Revolving Credit Facility | Base Rate | Maximum
Debt Instrument [Line Items]
Variable rate		2.50%

Debt and Other Long-Term Liab58

Debt and Other Long-Term Liabilities - Ultra Resources, Inc. - Term Loan - Additional Information (Details) - USD ($) $ in Thousands	Apr. 12, 2017	Dec. 31, 2017	Sep. 29, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt, gross		$ 2,175,000		$ 3,759,000
Ultra Resources, Inc. | Barclays Bank PLC | RBL Term Loan Secured Due 2024
Debt Instrument [Line Items]
RBL Credit Agreement, initial term loan	$ 800,000
RBL Credit Agreement, initial term loan upon emergence from chapter 11	600,000
RBL Credit Agreement, incremental term loan	$ 200,000		$ 175,000
Long-term debt, gross		$ 975,000
Debt, original issue discount as percentage on principal	1.00%
Amortization of term loan, quarterly basis		0.25%
Debt instrument, maturity term		7 years
Mandatory prepayment trigger, on asset coverage ratio		200.00%
Debt instrument, covenant compliance		At December 31, 2017, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Facility.
Ultra Resources, Inc. | Barclays Bank PLC | RBL Term Loan Secured Due 2024 | LIBOR
Debt Instrument [Line Items]
Variable rate		3.00%
Ultra Resources, Inc. | Barclays Bank PLC | RBL Term Loan Secured Due 2024 | Base Rate
Debt Instrument [Line Items]
Variable rate		2.00%

Debt and Other Long-Term Liab59

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

Share Based Compensation - Addi

Share Based Compensation - Additional Information (Details) - USD ($)	Apr. 12, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans		$ 39,977,000	$ 5,562,000	$ 4,128,000
Stock issued to employees		$ 26,673,000
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance period		3 years
Performance Shares | Stock Incentive Plan 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percent of equity reserved for directors, officers and other employees	7.50%
Performance Shares | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of reserve granted	40.00%
Vesting description		Also on the Effective Date, 40% of the Reserve, (“Initial MIP Grants”) was granted to members of the board of directors, officers, and other employees of the reorganized 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 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, 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%
Stock-Based Compensation Cost
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Payment or other distribution on account of the LTIPs	$ 0
Total cost of share based payment plans		$ 40,000,000	5,600,000	4,100,000
Stock-Based Compensation Cost | Management Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans		38,500,000
Stock issued to employees		$ 26,100,000
Numbers of shares issued to employees		1,238,665
Stock-Based Compensation Cost | Management Incentive Plan | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds $6.0 Billion
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total enterprise value		$ 6,000,000,000
Expected share-based compensation expense		21,300,000
Stock-Based Compensation Cost | Management Incentive Plan | Vest One-third Upon Reaching a Total Enterprise Value Equals or Exceeds 110% of $6.0 Billion or $6.6 Billion
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total enterprise value		6,600,000,000
Expected share-based compensation expense		$ 20,100,000
Stock-Based Compensation Cost | Long Term Incentive Plan 2014 and 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans			$ 4,700,000
Stock-Based Compensation Cost | Long Term Incentive Plan 2015, 2014 and 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total cost of share based payment plans				$ 2,900,000

Share Based Compensation - Sche

Share Based Compensation - Schedule of Valuation and Expense Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Allocation And Classification In Financial Statements [Abstract]
Total cost of share-based payment plans	$ 53,952	$ 8,013	$ 6,137
Amounts capitalized in oil and gas properties and equipment	13,975	2,451	2,009
Amounts charged against income, before income tax benefit	39,977	5,562	4,128
Amount of related income tax benefit recognized in income before valuation allowances	$ 15,927	$ 2,216	$ 1,645

Share Based Compensation - Secu

Share Based Compensation - Securities Authorized for Issuance Under Equity Compensation Plans (Details)	Dec. 31, 2017shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans	14,457,000
Equity Compensation Plans Approved by Security Holders
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans	14,457,000

Derivative Financial Instrume63

Derivative Financial Instruments - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017
Maximum
Derivative [Line Items]
Commodity derivatives board authorization	50.00%

Derivative Financial Instrume64

Derivative Financial Instruments - Summary of Open Commodity Derivative Contracts (Details) $ in Thousands	2 Months Ended	12 Months Ended
	Feb. 15, 2018MMBTU$ / MMBTU	Dec. 31, 2017USD ($)MMBTU$ / MMBTU
Derivative [Line Items]
Assets, Fair Value | $		$ 16,865
Derivative Contract, Assets | Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type		Fixed price swaps
Derivative Contract, Assets | Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NYMEX-Henry Hub
Remaining Contract Period		April-Oct 2018
Volume/ MMBTU/day | MMBTU		380,000
Average Price/MMBTU		2.97
Assets, Fair Value | $		$ 15,419
Derivative Contract, Assets | Commodity Derivative Contract Collars | Natural Gas
Derivative [Line Items]
Type		Collars
Derivative Contract, Assets | Commodity Derivative Contract Collars One | Natural Gas
Derivative [Line Items]
Commodity Reference Price		NYMEX-Henry Hub
Remaining Contract Period		Jan-Mar 2018
Volume/ MMBTU/day | MMBTU		40,000
Floor Price ($/MMBTU)		3.23
Ceiling Price ($/MMBTU)		3.54
Assets, Fair Value | $		$ 1,446
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps | Natural Gas
Derivative [Line Items]
Type	Fixed price swaps
Commodity Reference Price	NYMEX-Henry Hub
Remaining Contract Period	April-Oct 2018
Volume/ MMBTU/day | MMBTU	390,000
Average Price/MMBTU	2.79
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps One | Natural Gas
Derivative [Line Items]
Commodity Reference Price	NYMEX-Henry Hub
Remaining Contract Period	Nov-Dec 2018
Volume/ MMBTU/day | MMBTU	400,000
Average Price/MMBTU	2.88
Subsequent Event | Commodity Derivative Contract Fixed Price Swaps Two | Natural Gas
Derivative [Line Items]
Commodity Reference Price	NYMEX-Henry Hub
Remaining Contract Period	Jan-Mar 2019
Volume/ MMBTU/day | MMBTU	200,000
Average Price/MMBTU	2.91
Subsequent Event | Commodity Derivative Basis Swap Contracts | Natural Gas
Derivative [Line Items]
Type	Basis Swap Contracts
Subsequent Event | Commodity Derivative Basis Swap Contracts One | Natural Gas
Derivative [Line Items]
Commodity Reference Price	NW Rockies Basis Swap
Remaining Contract Period	Mar-Dec 2018
Volume/ MMBTU/day | MMBTU	30,000
Average Differential/MMBTU	(0.58)
Subsequent Event | Commodity Derivative Basis Swap Contracts Two | Natural Gas
Derivative [Line Items]
Commodity Reference Price	NW Rockies Basis Swap
Remaining Contract Period	April-Oct 2018
Volume/ MMBTU/day | MMBTU	140,000
Average Differential/MMBTU	(0.62)
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps
Derivative [Line Items]
Type	Fixed price swaps
Commodity Reference Price	NYMEX-WTI
Remaining Contract Period	Feb-Dec 2018
Volume/ MMBTU/day | MMBTU	2,000
Average Price/MMBTU	62.17
Subsequent Event | Crude Oil | Commodity Derivative Contract Fixed Price Swaps One
Derivative [Line Items]
Commodity Reference Price	NYMEX-WTI
Remaining Contract Period	Mar-Dec 2018
Volume/ MMBTU/day | MMBTU	2,000
Average Price/MMBTU	57.43

Derivative Financial Instrume65

Derivative Financial Instruments - Summary of Pre-tax Realized and Unrealized Gains and Losses Recognized Related to Natural Gas Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2015
Derivative [Line Items]
Total gain on commodity derivatives	$ 16,263	$ 4,650	$ 20,717	$ (13,218)	$ 28,412	$ 42,611
Commodity Derivative Contract
Derivative [Line Items]
Unrealized gain (loss) on commodity derivatives					16,966	(104,190)
Total gain on commodity derivatives					28,412	42,611
Commodity Derivative Contract | Natural Gas
Derivative [Line Items]
Realized gain on commodity derivatives-natural gas					$ 11,446	$ 146,801

Fair Value Measurements - Asset

Fair Value Measurements - Assets Measured at Fair Value (Details) $ in Thousands	Dec. 31, 2017USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset	$ 16,865
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Current derivative asset	$ 16,865

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Details) - Level 2 - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	$ 2,175,000	$ 3,759,000
Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Total debt	2,181,750	3,984,699
Term Loan Secured Due 2024 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	975,000
Term Loan Secured Due 2024 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Term loan	975,000
6.875% Senior, Unsecured Notes, Due 2022 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	700,000
6.875% Senior, Unsecured Notes, Due 2022 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	701,750
7.125% Senior, Unsecured Notes, Due 2025 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	500,000
7.125% Senior, Unsecured Notes, Due 2025 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable	$ 505,000
7.31% Notes Due March 2016, Issued 2009 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		62,000
7.31% Notes Due March 2016, Issued 2009 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		64,266
4.98% Notes Due January 2017, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		116,000
4.98% Notes Due January 2017, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		123,967
5.92% Notes Due March 2018, Issued 2008 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		200,000
5.92% Notes Due March 2018, Issued 2008 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		224,025
5.75% Notes Due December 2018, Issued 2013 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		450,000
5.75% Notes Due December 2018, Issued 2013 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		465,630
7.77% Notes Due March 2019, Issued 2009 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		173,000
7.77% Notes Due March 2019, Issued 2009 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		204,854
5.50% Notes Due January 2020, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		207,000
5.50% Notes Due January 2020, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		233,932
4.51% Notes Due October 2020, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		315,000
4.51% Notes Due October 2020, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		337,528
5.60% Notes Due January 2022, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		87,000
5.60% Notes Due January 2022, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		99,983
4.66% Notes Due October 2022, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		35,000
4.66% Notes Due October 2022, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		38,225
6.125% Notes Due October 2024, Issued 2014 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		850,000
6.125% Notes Due October 2024, Issued 2014 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		893,325
5.85% Notes Due January 2025, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		90,000
5.85% Notes Due January 2025, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		106,299
4.91% Notes Due October 2025, Issued 2010 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		175,000
4.91% Notes Due October 2025, Issued 2010 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Notes payable		193,665
Credit Facility Due October 2016 | Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility		999,000
Credit Facility Due October 2016 | Estimated Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Credit facility		$ 999,000

Fair Value Measurements - Car68

Fair Value Measurements - Carrying Values and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Term Loan Secured Due 2024
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,024
6.875% Senior, Unsecured Notes, Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,022
Stated interest rate	6.875%
7.125% Senior, Unsecured Notes, Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity year	2,025
Stated interest rate	7.125%
7.31% Notes Due March 2016, Issued 2009
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		7.31%
Debt instruments maturity month and year		2016-03
Debt instrument issuance year		2,009
4.98% Notes Due January 2017, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		4.98%
Debt instruments maturity month and year		2017-01
Debt instrument issuance year		2,010
5.92% Notes Due March 2018, Issued 2008
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		5.92%
Debt instruments maturity month and year		2018-03
Debt instrument issuance year		2,008
5.75% Notes Due December 2018, Issued 2013
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		5.75%
Debt instruments maturity month and year		2018-12
Debt instrument issuance year		2,013
7.77% Notes Due March 2019, Issued 2009
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		7.77%
Debt instruments maturity month and year		2019-03
Debt instrument issuance year		2,009
5.50% Notes Due January 2020, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		5.50%
Debt instruments maturity month and year		2020-01
Debt instrument issuance year		2,010
4.51% Notes Due October 2020, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		4.51%
Debt instruments maturity month and year		2020-10
Debt instrument issuance year		2,010
5.60% Notes Due January 2022, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		5.60%
Debt instruments maturity month and year		2022-01
Debt instrument issuance year		2,010
4.66% Notes Due October 2022, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		4.66%
Debt instruments maturity month and year		2022-10
Debt instrument issuance year		2,010
6.125% Notes Due October 2024, Issued 2014
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		6.125%
Debt instruments maturity month and year		2024-10
Debt instrument issuance year		2,014
5.85% Notes Due January 2025, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		5.85%
Debt instruments maturity month and year		2025-01
Debt instrument issuance year		2,010
4.91% Notes Due October 2025, Issued 2010
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Stated interest rate		4.91%
Debt instruments maturity month and year		2025-10
Debt instrument issuance year		2,010
Credit Facility Due October 2016
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Debt instruments maturity month and year		2016-10

Income Taxes - Summary of Incom

Income Taxes - Summary of Income (Loss) Before Income Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Loss From Continuing Operations Before Income Taxes Minority Interest And Income Loss From Equity Method Investments [Abstract]
United States	$ (197,136)	$ 134,959	$ (3,249,590)
Foreign	360,982	(79,462)	37,966
Income (loss) before income tax benefit	$ 163,846	$ 55,497	$ (3,211,624)

Income Taxes - Summary of Conso

Income Taxes - Summary of Consolidated Income Tax (Benefit) Provision (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current tax:
U.S. federal, state and local - current								$ (13,296)	$ (72)
Foreign - current								2	(583)	$ (3,414)
Total current tax (benefit)								(13,294)	(655)	(3,414)
Deferred tax:
Foreign - deferred									1	(990)
Total deferred tax (benefit) expense									1	(990)
Total income tax (benefit)	$ (6,410)	$ (6,886)	$ 2	$ (349)	$ 45	$ (160)	$ (190)	$ (13,294)	$ (654)	$ (4,404)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Statutory tax rate		35.00%
Deferred tax assets, valuation allowance		$ 700	$ 1,300
Scenario, Forecast
Income Taxes [Line Items]
Statutory tax rate	21.00%
Canada | 2015
Income Taxes [Line Items]
Tax years		2,015
Canada | 2016
Income Taxes [Line Items]
Tax years		2,016
Federal
Income Taxes [Line Items]
Net operating loss carryforward		$ 2,100
State | Utah
Income Taxes [Line Items]
Net operating loss carryforward		$ 102.2

Income Taxes - Summary of Inc72

Income Taxes - Summary of Income Tax Provision (Benefit) from Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Abstract]
Income tax provision (benefit) computed at the U.S. statutory rate								$ 57,346	$ 19,424	$ (1,124,069)
State income tax (benefit) provision net of federal effect								(25,519)	(2,335)	(12,998)
Valuation allowance								(562,491)	(31,083)	1,147,619
Tax effect of rate change								463,113		12,898
Sale of Pennsylvania assets								130,552		0
Foreign rate differential								(3,150)	17,388	(26,740)
Reorganization items								(78,549)
Other, net								5,404	(4,048)	(1,114)
Total income tax (benefit)	$ (6,410)	$ (6,886)	$ 2	$ (349)	$ 45	$ (160)	$ (190)	$ (13,294)	$ (654)	$ (4,404)

Income Taxes - Summary of Defer

Income Taxes - Summary of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Property and equipment	$ 181,524	$ 603,045
Deferred gain	22,256	40,867
U.S. federal tax credit carryforwards	987	15,967
U.S. net operating loss carryforwards	450,623	428,212
U.S. state net operating loss carryforwards	4,038	71,323
Non-U.S. net operating loss carryforwards	6,556	30,211
Asset retirement obligations	36,624	55,700
Liabilities subject to compromise-contract settlement		59,166
Incentive compensation/other, net	8,308	16,088
Deferred tax assets noncurrent before valuation allowances	710,916	1,320,579
Valuation allowance	(707,348)	(1,270,935)
Net deferred tax assets	3,568	49,644
Deferred tax liabilities:
Derivative instruments, net	3,568
Liabilities subject to compromise-interest		35,498
Liabilities subject to compromise-interest (non-U.S.)		14,146
Net tax liabilities	$ 3,568	$ 49,644

Employee Benefits - Additional

Employee Benefits - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Tax Deferred Savings Plan [Abstract]
Employee deferral percent for 401(k)	100.00%
Company matching percent for 401(k)	5.00%
Company discretionary contribution for 401(k)	8.00%
Pension and Other Postretirement Benefit Contributions [Abstract]
Other postretirement benefits payments	$ 2.4	$ 2.3	$ 2.3

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) $ in Thousands	Aug. 31, 2016USD ($)	Apr. 29, 2016USD ($)	Apr. 19, 2016USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 09, 2018MMBTUMMBbls	Oct. 06, 2017USD ($)	Apr. 14, 2017USD ($)
Loss Contingencies [Line Items]
Claims settled					$ 399,000
Bankruptcy claims, undistributed amount returned									$ 1,300
Make-whole fees included in reorganization items					223,838	$ 0	$ 0
Bankruptcy claims, amount of claims settled included in interest expense					175,200
Projected total lease payments					5,700
Commitments for office leases in 2018					1,400
Commitments for office leases in 2019					1,300
Commitments for office leases in 2020					1,300
Commitments for office leases in 2021					1,100
Commitments for office leases in 2021					600
Office leases expense recognized					$ 1,600	$ 1,500	$ 1,300
Oil and gas delivery commitments details					With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2018, the Company has long-term natural gas delivery commitments of 12.6 MMMBtu in 2019 under existing agreements. As of February 9, 2018, the Company has long-term crude oil delivery commitments of 1.7 MMBbls in 2018 and 0.3 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments.
Subsequent Event
Loss Contingencies [Line Items]
Long term natural gas delivery commitments in 2019 | MMBTU								12.6
Long term crude oil delivery commitments in 2018 | MMBbls								1.7
Long term crude oil delivery commitments in 2019 | MMBbls								0.3
Pinedale Lease Agreement
Loss Contingencies [Line Items]
Initial term liquids gathering system lease				15 years
Renewal term liquids gathering system lease				5 years
Renewal term liquids gathering system lease useful life				75.00%
Initial annual rent				$ 20,000
Projected total lease payments				$ 213,200
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

Concentration of Credit Risk -

Concentration of Credit Risk - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017
Customer Concentration Risk | Revenue | Minimum
Percentage of revenue	10.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Separation Agreement - Subsequent Event - USD ($) $ in Millions	Feb. 28, 2018	Feb. 23, 2018
Subsequent Event [Line Items]
Separation agreement date		Feb. 23, 2018
Cash severance payment		$ 3,762,950
Vesting and delivery of shares of common stock		1,226,102
Maximum
Subsequent Event [Line Items]
Post-retirement welfare benefit period	24 months

Summarized Quarterly Financia78

Summarized Quarterly Financial Information (Unaudited) - Summary of Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Operating revenues	$ 240,627	$ 217,631	$ 212,657	$ 220,958	$ 215,861	$ 199,253	$ 146,591	$ 159,386	$ 891,873	$ 721,091	$ 839,111
Gain (loss) on commodity derivatives	16,263	4,650	20,717	(13,218)					28,412		42,611
Operating expenses	132,574	122,394	134,393	104,227	99,313	99,788	94,746	126,868	493,588	420,715	3,925,520
Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016)	(36,388)	(210,107)	(29,425)	(85,447)			(16,662)	(49,903)	(361,367)	(66,565)	(171,918)
Restructuring expenses						(28)	(1,569)	(5,579)		(7,176)
Contract settlement				(52,707)	(131,106)				(52,707)	(131,106)
Other income (expense), net	2,430	2,730	2,665	2,491	1,993	2,124	2,411	943	10,316	7,471
Total other (expense) income, net	(33,958)	(207,377)	(26,760)	(135,663)	(129,113)	2,096	(15,820)	(54,539)	(403,758)	(197,376)
Reorganization items, net	(1,240)	(227,123)	426,816	(57,546)	(22,211)	(3,109)	(22,183)		140,907	(47,503)	0
Income (loss) before income tax (benefit) provision	89,118	(334,613)	499,037	(89,696)	(34,776)	98,452	13,842	(22,021)	163,846	55,497
Income tax benefit	(6,410)	(6,886)		2	(349)	45	(160)	(190)	(13,294)	(654)	(4,404)
Net income (loss)	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	$ 177,140	$ 56,151	$ (3,207,220)
Net income (loss) per common share — basic	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ (0.43)	$ 1.23	$ 0.18	$ (0.27)	$ 1.08	$ 0.70	$ (40.14)
Net income (loss) per common share — fully diluted	$ 0.49	$ (1.67)	$ 2.76	$ (1.12)	$ (0.43)	$ 1.22	$ 0.17	$ (0.27)	$ 1.08	$ 0.70	$ (40.14)

Summarized Quarterly Financia79

Summarized Quarterly Financial Information (Unaudited) - Summary of Quarterly Financial Information (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Quarterly Financial Data [Abstract]
Contractual interest expense on prepetition liabilities not recognized in statement of operations	$ 141.5

Disclosure About Oil and Gas 80

Disclosure About Oil and Gas Producing Activities (Unaudited) - Additional Information (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Internal engineer experience	15 years
Expert qualifications	The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over 7 years of prior industry experience. He graduated from graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Significant changes in reserves	Changes in proved undeveloped reserves: As of December 31, 2016 and 2015, the Company did not include PUD reserves in its total proved reserve estimates due to uncertainty regarding its ability to continue as a going concern and the availability of capital that would be required to develop the PUD reserves. Upon emergence from chapter 11 proceedings the Company began recognizing PUDs as the substantial doubt regarding the Company’s ability to continue as a going concern had been alleviated. The changes to the Company’s proved undeveloped reserves (PUDs) during 2017 include the addition of PUDs associated with the current development plan. As there were no PUDs recognized at December 31, 2016, there are no additions, transfers or conversions to record. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years.
Weighted average sales price for proved reserves natural gas	$ 2.59	$ 2.07	$ 2.21
Weighted average sales price for proved reserves condensate	$ 48.05	37.90	42.36
Weighted average sales price for proved reserves natural gas liquids		$ 19.17	$ 20.61

Disclosure About Oil and Gas 81

Disclosure About Oil and Gas Producing Activities (Unaudited) - Analyses of Changes in Proven Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf
Oil Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	21,475	22,175	67,766
Extensions, discoveries and additions	1,117	3,519	166
Acquisitions	153
Production	(2,775)	(2,912)	(3,533)
Revisions	7,148	(1,307)	(42,224)
Reserves, Ending Balance	27,118	21,475	22,175
Natural Gas Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance | Mcf	2,321,613	2,336,280	4,831,194
Extensions, discoveries and additions | Mcf	50,312	251,634	17,415
Sales | Mcf	(89,315)
Acquisitions | Mcf	22,400
Production | Mcf	(260,009)	(264,278)	(268,954)
Revisions | Mcf	910,991	(2,023)	(2,243,375)
Reserves, Ending Balance | Mcf	2,955,992	2,321,613	2,336,280
Natural Gas Liquid Reserves
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	9,903	9,840	21,993
Extensions, discoveries and additions		530	3
Revisions	(9,832)	(467)	(12,156)
Reserves, Ending Balance	71	9,903	9,840

Disclosure About Oil and Gas 82

Disclosure About Oil and Gas Producing Activities (Unaudited) - Summary of Developed and Undeveloped Proven Reserves (Details) bbl in Thousands, Mcf in Thousands	Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf
Oil Reserves
Reserve Quantities [Line Items]
Developed	21,652	21,475	22,175	28,481
Undeveloped	5,466			39,285
Total Proved	27,118	21,475	22,175	67,766
Natural Gas Reserves
Reserve Quantities [Line Items]
Developed | Mcf	2,261,289	2,321,613	2,336,280	2,245,004
Undeveloped | Mcf	694,703			2,586,190
Total Proved | Mcf	2,955,992	2,321,613	2,336,280	4,831,194
Natural Gas Liquid Reserves
Reserve Quantities [Line Items]
Developed	71	9,903	9,840	9,118
Undeveloped				12,875
Total Proved	71	9,903	9,840	21,993

Disclosure About Oil and Gas 83

Disclosure About Oil and Gas Producing Activities (Unaudited) - Standardized Measure (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future cash inflows	$ 8,965,949	$ 5,812,234	$ 6,312,095
Future production costs	(3,587,581)	(2,665,082)	(3,006,265)
Future development costs	(1,001,024)	(355,923)	(358,848)
Future net cash flows	4,377,344	2,791,229	2,946,982
Discount at 10%	(1,993,016)	(1,100,283)	(1,081,333)
Standardized measure of discounted future net cash flows	$ 2,384,328	$ 1,690,946	$ 1,865,649	$ 5,233,483

Disclosure About Oil and Gas 84

Disclosure About Oil and Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning	$ 1,690,946	$ 1,865,649	$ 5,233,483
Net revisions of previous quantity estimates	840,505	(9,623)	(2,126,998)
Extensions, discoveries and other changes	53,549	209,603	15,254
Sales of reserves in place	(83,887)
Acquisition of reserves	21,903
Changes in future development costs	(329,635)	11,556	1,618,068
Sales of oil and gas, net of production costs	(589,621)	(454,725)	(550,879)
Net change in prices and production costs	572,224	(72,939)	(6,996,416)
Development costs incurred during the period that reduce future development costs	8,007	22,523	548,112
Accretion of discount	169,095	186,565	709,736
Net changes in production rates and other	31,242	(67,663)	1,551,413
Net change in income taxes			1,863,876
Aggregate changes	693,382	(174,703)	(3,367,834)
Standardized measure, ending	$ 2,384,328	$ 1,690,946	$ 1,865,649

Disclosure About Oil and Gas 85

Disclosure About Oil and Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Gas Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$ 1,399	$ 983	$ 13,845
Acquisition costs - proved properties	9,147
Exploration	510,710	224,277	18,164
Development	35,934	44,300	461,458
Total	$ 557,190	$ 269,560	$ 493,467

Disclosure About Oil and Gas 86

Disclosure About Oil and Gas Producing Activities (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$ 891,873	$ 721,091	$ 839,111
Production expenses	(292,095)	(266,366)	(288,231)
Depletion and depreciation	(161,945)	(125,121)	(401,200)
Ceiling test and other impairments			(3,144,899)
Income tax benefit (expense)	(168,355)	83,112	(9,841)
Total	$ 269,478	$ 412,716	$ (3,005,060)

Disclosure About Oil and Gas 87

Disclosure About Oil and Gas Producing Activities (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 11,215,563	$ 10,752,642
Less: accumulated depletion, depreciation and amortization	(9,890,495)	(9,742,176)
Proved	$ 1,325,068	$ 1,010,466

Supplemental Financial Statem88

Supplemental Financial Statement Information - Supplemental Statement Of Operations Disclosures Parent Company (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General and administrative expense									$ 39,548	$ 9,179	$ 7,387
Other income (expense):
Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016)	$ (36,388)	$ (210,107)	$ (29,425)	$ (85,447)			$ (16,662)	$ (49,903)	(361,367)	(66,565)	(171,918)
Other expense									(237)	(3,082)	(2,060)
Reorganization items, net	(1,240)	(227,123)	426,816	(57,546)	$ (22,211)	$ (3,109)	(22,183)		140,907	(47,503)	0
Income (loss) before income taxes	89,118	(334,613)	499,037	(89,696)	(34,776)	98,452	13,842	(22,021)	163,846	55,497
Income tax provision (benefit)	(6,410)	(6,886)		2	(349)	45	(160)	(190)	(13,294)	(654)	(4,404)
Net income (loss)	$ 95,528	$ (327,727)	$ 499,037	$ (89,698)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	177,140	56,151	(3,207,220)
Parent
General and administrative expense									428	650	308
Other income (expense):
Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016)									(71,876)	(26,590)	(81,069)
Income (loss) from unconsolidated affiliates									(183,840)	157,450	(3,152,078)
Guarantee fee income										6,073	23,029
Other expense									90	(64,888)	(1,684)
Reorganization items, net									433,196	(15,827)
Income (loss) before income taxes									177,142	55,568	(3,212,110)
Income tax provision (benefit)									2	(583)	(4,890)
Net income (loss)									$ 177,140	$ 56,151	$ (3,207,220)

Supplemental Financial Statem89

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

Supplemental Financial Statem90

Supplemental Financial Statement Information - Supplemental Balance Sheet Disclosures Parent Company (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets:
Cash and cash equivalents	$ 16,631	$ 401,478	$ 4,143
Other current assets	5,647	6,020
Total current assets	167,425	521,393
Other non-current assets	10,920	1,374
Total assets	1,512,982	1,540,928
Current liabilities:
Accrued and other current liabilities	80,268	53,348
Total current liabilities	248,490	138,208
Total liabilities not subject to compromise	2,667,618	431,038
Liabilities subject to compromise	0	4,038,041
Total shareholders’ deficit	(1,154,636)	(2,928,151)	(2,991,937)	$ 211,660
Total liabilities and shareholders’ equity	1,512,982	1,540,928
Parent
Current Assets:
Cash and cash equivalents	803	3,009	$ 523	$ 772
Accounts receivable from related companies	29,940	29,939
Other current assets		2,100
Total current assets	30,743	35,048
Total assets	30,743	35,048
Current liabilities:
Accrued and other current liabilities	21	47
Total current liabilities	21	47
Advances from unconsolidated affiliates	1,185,359	1,623,414
Total liabilities not subject to compromise	1,185,380	1,623,461
Liabilities subject to compromise		1,339,739
Total shareholders’ deficit	(1,154,637)	(2,928,152)
Total liabilities and shareholders’ equity	$ 30,743	$ 35,048

Supplemental Financial Statem91

Supplemental Financial Statement Information - Supplemental Cash Flow Statement Disclosures Parent Company (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net cash (used in) operating activities	$ 65,268	$ 311,070	$ 515,536
Investing Activities:
Net cash used in investing activities	(435,311)	(278,900)	(512,757)
Financing activities:
Deferred financing costs	(73,092)		6
Shares issued	573,774
Repurchased shares/net share settlements	(9,581)	(379)	(2,514)
Net cash (used in) provided by financing activities	(16,737)	368,621	(7,557)
(Decrease)/Increase in cash during the period	(386,780)	400,791	(4,778)
Cash and cash equivalents, beginning of period	401,478	4,143
Cash and cash equivalents, end of period	16,631	401,478	4,143
Parent
Net cash (used in) operating activities	(2,206)	(21,309)	(101,277)
Investing Activities:
Investment in subsidiaries	(588,677)
Dividends received		24,089	96,297
Net cash used in investing activities	(588,677)	24,089	96,297
Financing activities:
Deferred financing costs			6
Shares issued	573,774
Repurchased shares/net share settlements	14,903	43
Shares re-issued from treasury		(337)	4,725
Net cash (used in) provided by financing activities	588,677	(294)	4,731
(Decrease)/Increase in cash during the period	(2,206)	2,486	(249)
Cash and cash equivalents, beginning of period	3,009	523	772
Cash and cash equivalents, end of period	$ 803	$ 3,009	$ 523