Ultra Petroleum 8-K 16 Nov 17 Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Document And Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Trading Symbol	UPL
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	1,022,646

Consolidated Statement of Opera

Consolidated Statement of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Natural gas sales	$ 609,756	$ 696,730	$ 969,850
Oil sales	111,335	142,381	260,170
Total operating revenues	721,091	839,111	1,230,020
Expenses:
Lease operating expenses	89,134	106,906	96,496
Liquids gathering system operating lease expense	20,686	20,647	20,306
Production taxes	69,737	72,774	103,898
Gathering fees	86,809	87,904	59,931
Transportation charges	20,049	83,803	77,780
Depletion, depreciation and amortization	125,121	401,200	292,951
Ceiling test and other impairments	0	3,144,899	0
General and administrative	9,179	7,387	19,069
Total operating expenses	420,715	3,925,520	670,431
Operating income (loss)	300,376	(3,086,409)	559,589
Other income (expense), net:
Interest expense (excludes contractual interest expense of $141.5 million for the year ended December 31, 2016)	(66,565)	(171,918)	(126,157)
Gain on commodity derivatives	0	42,611	82,402
Deferred gain on sale of liquids gathering system	10,553	10,553	10,553
Litigation expense	0	(4,401)	0
Restructuring expenses	(7,176)	0	0
Contract settlement	(131,106)	0	0
Gain on sale of property	0	0	8,022
Other (expense) income, net	(3,082)	(2,060)	2,618
Total other (expense) income, net	(197,376)	(125,215)	(22,562)
Reorganization items, net	(47,503)	0	0
Income (loss) before income tax benefit	55,497	(3,211,624)	537,027
Income tax benefit	(654)	(4,404)	(5,824)
Net income (loss)	$ 56,151	$ (3,207,220)	$ 542,851
Basic Earnings (Loss) per Share:
Net income (loss) per common share — basic	$ 0.37	$ (20.94)	$ 3.54
Fully Diluted Earnings (Loss) per Share:
Net income (loss) per common share — fully diluted	$ 0.36	$ (20.94)	$ 3.51
Weighted average common shares outstanding — basic	153,378	153,192	153,136
Weighted average common shares outstanding — fully diluted	154,081	153,192	154,694

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 ($)	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 401,478,000	$ 4,143,000
Restricted cash	3,571,000	115,000
Oil and gas revenue receivable	79,179,000	61,881,000
Joint interest billing and other receivables	10,781,000	11,356,000
Income tax receivable	2,099,000	5,150,000
Inventory	4,906,000	4,269,000
Deposits and retainers	13,359,000	0
Other current assets	6,020,000	4,300,000
Total current assets	521,393,000	91,214,000
Oil and gas properties, net, using the full cost method of accounting:
Proven	1,010,466,000	851,145,000
Property, plant and equipment	7,695,000	8,844,000
Deferred income taxes	0	1,000
Other	1,374,000	835,000
Total assets	1,540,928,000	952,039,000
Current liabilities:
Accounts payable	28,171,000	93,415,000
Accrued liabilities	53,348,000	72,428,000
Production taxes payable	44,329,000	52,273,000
Current portion of long-term debt	0	3,370,553,000
Interest payable	0	42,657,000
Capital cost accrual	12,360,000	20,571,000
Total current liabilities	138,208,000	3,651,897,000
Deferred gain on sale of liquids gathering system	115,742,000	126,295,000
Other long-term obligations	177,088,000	165,784,000
Total liabilities not subject to compromise	431,038,000	3,943,976,000
Liabilities subject to compromise	4,038,041,000	0
Commitments and contingencies (Note 11)
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding shares — 153,418,041 and 153,255,989, at December 31, 2016 and 2015, respectively	510,063,000	502,050,000
Treasury stock	(49,000)	(176,000)
Retained loss	(3,438,165,000)	(3,493,811,000)
Total shareholders’ deficit	(2,928,151,000)	(2,991,937,000)
Total liabilities and shareholders’ equity	$ 1,540,928,000	$ 952,039,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Statement Of Financial Position [Abstract]
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	unlimited	unlimited
Common stock, shares issued	153,418,041	153,255,989
Common stock, shares outstanding	153,418,041	153,255,989

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Beginning Balance at Dec. 31, 2013	$ (331,490)	$ 487,273	$ (816,802)	$ (1,961)
Beginning Balance, Shares at Dec. 31, 2013		152,991,000
Stock options exercised	770	$ 770
Stock options exercised, Shares		43,000
Employee stock plan grants	700	$ 700		0
Employee stock plan grants, Shares		298,000
Shares re-issued from treasury		$ (770)	(1,450)	2,220
Shares repurchased	(6,472)			(6,472)
Shares repurchased, Shares		(332,000)
Net share settlements	(2,639)		(2,639)
Net share settlements, Shares		(104,000)
Fair value of employee stock plan grants	7,940	$ 7,940
Comprehensive earnings:
Net income (loss)	542,851		542,851
Ending Balance at Dec. 31, 2014	211,660	$ 495,913	(278,040)	(6,213)
Ending Balance, Shares at Dec. 31, 2014		152,896,000
Employee stock plan grants	700	$ 700
Employee stock plan grants, Shares		526,000
Shares re-issued from treasury		$ 0	(6,037)	6,037
Net share settlements	(2,514)		(2,514)
Net share settlements, Shares		(166,000)
Fair value of employee stock plan grants	5,437	$ 5,437
Comprehensive earnings:
Net income (loss)	(3,207,220)		(3,207,220)
Ending Balance at Dec. 31, 2015	(2,991,937)	$ 502,050	(3,493,811)	(176)
Ending Balance, Shares at Dec. 31, 2015		153,256,000
Employee stock plan grants	0	$ 0
Employee stock plan grants, Shares		279,000
Shares re-issued from treasury		$ 0	(127)	127
Net share settlements	(379)		(379)
Net share settlements, Shares		(117,000)
Fair value of employee stock plan grants	8,014	$ 8,014
Comprehensive earnings:
Net income (loss)	56,151		56,151
Ending Balance at Dec. 31, 2016	$ (2,928,151)	$ 510,064	$ (3,438,166)	$ (49)
Ending Balance, Shares at Dec. 31, 2016		153,418,000

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net income (loss) for the period	$ 56,151	$ (3,207,220)	$ 542,851
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion, depreciation and amortization	125,121	401,200	292,951
Ceiling test and other impairments	0	3,144,899	0
Deferred and current non-cash income taxes	1	(990)	995
Unrealized (gain) loss on commodity derivatives	0	104,190	(130,066)
Deferred gain on sale of liquids gathering system	(10,553)	(10,553)	(10,553)
Gain on sale of property	0	0	(8,022)
Stock compensation	5,562	4,128	5,467
Non-cash reorganization items, net	42,523	0	0
Other	6,870	9,217	4,569
Net changes in operating assets and liabilities:
Restricted cash	(3,456)	2	2
Accounts receivable	(19,635)	65,132	(43,116)
Other current assets	(15,647)	(20,106)	(1,920)
Other non-current assets	(539)	21,112	284
Accounts payable	(63,924)	13,815	28,696
Accrued liabilities	133,144	1,655	(5,938)
Production taxes payable	(7,944)	(3,312)	15,115
Interest payable	57,117	(3,441)	14,233
Other long-term obligations	276	(5,770)	6,427
Current taxes payable/receivable	2,547	1,580	609
Net cash provided by operating activities	307,614	515,538	712,584
Investing Activities:
Acquisition of oil and gas properties	0	3,964	(891,075)
Oil and gas property expenditures	(269,314)	(494,025)	(599,913)
Gathering system expenditures	0	0	(6,842)
Proceeds from sale of property	0	0	27,944
Change in capital cost accrual	(8,134)	(25,380)	(125,577)
Inventory	(1,123)	3,235	175
Purchase of property, plant and equipment	(329)	(551)	(5,455)
Net cash used in investing activities	(278,900)	(512,757)	(1,600,743)
Financing activities:
Borrowings on long-term debt	369,000	1,165,000	1,095,000
Payments on long-term debt	0	(1,153,000)	(1,037,000)
Proceeds from issuance of Senior Notes	0	0	850,000
Deferred financing costs	0	6	(13,245)
Repurchased shares/net share settlements	(379)	(2,514)	(9,111)
Payment of contingent consideration	0	(17,049)	0
Proceeds from exercise of options	0	0	770
Net cash provided by (used in) financing activities	368,621	(7,557)	886,414
Increase/(Decrease) in cash during the period	397,335	(4,776)	(1,745)
Cash and cash equivalents, beginning of period	4,143	8,919	10,664
Cash and cash equivalents, end of period	401,478	4,143	8,919
Cash paid for:
Interest	4,793	169,867	108,889
Income taxes	94	0	1,752
Non-cash investing activities — oil and gas properties	$ 0	$ 0	$ 20,000

Description of the Business

Description of the Business	12 Months Ended
	Dec. 31, 2016
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, its oil reserves in the Uinta Basin in Utah and its natural gas reserves in the Appalachian Basin of Pennsylvania.

Chapter 11 Proceedings, Ability

Chapter 11 Proceedings, Ability to Continue as a Going Concern	12 Months Ended
	Dec. 31, 2016
Liquidity And Going Concern Disclosure [Abstract]
Chapter 11 Proceedings, Ability to Continue as a Going Concern	Chapter 11 Proceedings, Ability to Continue as a Going Concern Chapter 11 Proceedings On April 29, 2016 (the “Petition Date”), to restructure their respective obligations and capital structures, the Company and each of its direct and indirect wholly owned subsidiaries (collectively, the “Ultra Entities” or “Debtors”) filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors’ chapter 11 cases are being jointly administered for procedural purposes under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.). Information about our chapter 11 cases is available at our website (www.ultrapetroleum.com) and also at a website maintained by our claims agent, Epiq Systems (http://dm.epiq11.com/UPT/Docket). We are currently operating our business as a debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. After we filed our chapter 11 petitions, the Bankruptcy Court granted certain relief we requested enabling us to conduct our business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing us to pay employee wages and benefits, pay taxes and certain governmental fees and charges, continue to operate our cash management system in the ordinary course, remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and pay the prepetition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms. Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the date on which our chapter 11 cases were filed were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our prepetition liabilities and obligations should be settled or compromised under the Bankruptcy Code as part of our chapter 11 proceedings. Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors”. In addition, our assets, liabilities, including our capital structure, shareholders, officers and/or directors could change materially because of our chapter 11 cases. In addition, the description of our operations, properties and capital plans included in this Annual Report on Form 10-K may not accurately reflect our operations, properties and capital plans after we emerge from chapter 11. Creditors’ Committees – Appointment & Formation On May 5, 2016, the United States Trustee for the Southern District of Texas appointed an official committee for unsecured creditors of all of the Debtors (the “UCC”). On September 26, 2016, the United States Trustee for the Southern District of Texas filed a Notice of Reconstitution of the UCC. In addition, certain other stakeholders have organized for purposes of participating in the Debtors’ chapter 11 cases: (i) on June 8, 2016, an informal ad hoc committee of unsecured creditors of our subsidiary, Ultra Resources, Inc. (“Ultra Resources”), notified the Bankruptcy Court it had formed and identified its members, most of which are distressed debt investors and/or hedge funds; (ii) on June 13, 2016, an informal ad hoc committee of the holders of senior notes issued by the Company notified the Bankruptcy Court it had formed and identified its members; (iii) on July 20, 2016, an informal ad hoc committee of shareholders of the Company notified the Bankruptcy Court it had formed and identified its members; and (iv) on January 6, 2017, an informal ad hoc committee of unsecured creditors of our subsidiary, Ultra Resources, notified the Bankruptcy Court it had formed and identified its members, most of which are insurance companies. We expect each of the committees to be involved in our chapter 11 cases, and any disagreements with any of the committees may extend our chapter 11 cases, increase the cost of our chapter 11 cases, and/or delay our emergence from chapter 11. Exclusivity The Bankruptcy Code provides chapter 11 debtors-in-possession with the exclusive right to file a plan of reorganization under chapter 11 through a period of time specified in the Bankruptcy Code, which period may be extended by the Bankruptcy Court. On July 27, 2016, we filed a motion seeking an extension of the exclusive chapter 11 plan filing period. At a hearing conducted on August 25, 2016, the Bankruptcy Court extended our exclusive right to file a plan of reorganization under chapter 11 through and including March 1, 2017, and to solicit acceptances of such plan through and including May 1, 2017, subject to our producing and delivering a long-term business plan prior to December 1, 2016. The long-term business plan was provided prior to December 1, 2016, and, pursuant to a Stipulation Regarding Order Extending Exclusivity signed by the Bankruptcy Court, we satisfied the condition (with the effect that our exclusive right to file a reorganization plan now continues until and including March 1, 2017, and our exclusive right to solicit acceptances of such a plan continues until and including May 1, 2017). On February 1, 2017, we filed a motion seeking an extension of the exclusive chapter 11 plan filing period through June 29, 2017 and the exclusive right to solicit acceptances of a chapter 11 plan through August 29, 2017. On February 17, 2017, we filed a revised proposed form of order to the motion seeking an extension of the exclusive chapter 11 plan filing period through April 15, 2017 and the exclusive right to solicit acceptances of a chapter 11 plan through June 15, 2017. Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing Commitment Letter 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 sets forth the terms and conditions pursuant to which the Ultra Entities and the Commitment Parties have agreed to seek and support a joint plan of reorganization at an aggregate plan value of $6.25 billion, $6.0 billion, or $5.5 billion, depending on commodity prices, for the Ultra Entities which will successfully complete the Reorganization Proceedings (collectively, the “Plan”). Under the Plan, the total enterprise value of the Ultra Entities will be $6.0 billion (the “Plan Value”); provided, that if the average closing price of the 12-month forward Henry Hub natural gas strip price during the seven (7) trading days preceding the commencement of the Rights Offering solicitation is: (i) greater than $3.65/MMBtu, the Plan Value will be $6.25 billion; or (ii) less than $3.25/MMBtu, the Plan Value will be $5.5 billion. Among other matters, the Plan provides for a comprehensive restructuring of all allowable claims against and interests in the Ultra Entities, including the conversion of the outstanding unsecured senior notes issued by the Company (“HoldCo Notes” and, the holders thereof, “HoldCo Noteholders”) to newly-issued shares of common stock in the Company, the exchange of the outstanding unsecured senior notes issued by UPL’s subsidiary Ultra Resources for a combination of new unsecured notes issued by Ultra Resources and cash, the payment in full of all other allowed claims against the Ultra Debtors in cash, and the distribution to each owner of common stock in the Company as of the Plan’s record date (“HoldCo Equityholders”) of such owner’s pro rata share of the new UPL common stock and the right to participate in the Rights Offering (as described below). The PSA provides certain milestones for the restructuring, which the Company is required to use commercially reasonable efforts to satisfy. Failure of the Company to satisfy certain milestones, including (i) entry of an order approving the Debtors’ entry into the BCA by January 20, 2017 and (ii) consummation of the Plan by April 15, 2017 would provide the Plan Support Parties a termination right under the PSA. On February 9, 2017, the Company entered into the First Amendment to the Plan Support Agreement (the “PSA Amendment”) with the Plan Support Parties party thereto. Pursuant to the PSA Amendment, the Required Consenting Parties agreed that the Plan Term Sheet, as modified to accord with the treatment of OpCo Funded Debt Claims and General Unsecured Claims under the Second Amended Plan, is reasonably satisfactory to such parties (as such terms are defined in the Plan Support Agreement). On February 13, 2017, the Court signed an order approving our Disclosure Statement. On February 21, 2017, the Court signed an amended order approving our Disclosure Statement. The amended order: (1) approves the adequacy of our Disclosure Statement, (2) approves the solicitation and notice procedures related to confirmation of our plan of reorganization, (3) approves the forms of ballots and notices related thereto, (4) approves the rights offering procedures and matters related thereto, (5) schedules certain dates related to our plan confirmation process and Rights Offering, and (6) grants related relief. With respect to the Rights Offering, the amended order defines the “Subscription Commencement Date” as February 21, 2017. Accordingly, as will be reflected in the materials to be distributed in connection with the Rights Offering, the Plan Value under the PSA is $6.0 billion. 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 will offer 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 will consist of the following offerings: • HoldCo Noteholders shall be 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, will reflect an aggregate purchase price of $435.0 million. • HoldCo Equityholders shall be 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, will reflect an aggregate purchase price of $145.0 million. Backstop Commitment Agreement : Under the BCA, the Commitment Parties have agreed to purchase the HoldCo Noteholder Rights Offering Shares and the HoldCo Equityholder Rights Offering Shares, as applicable, that are 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”). The Company will pay the Commitment Parties upon the closing of the Rights Offering a Commitment Premium equal to 6.0% of the $580.0 million committed amount (the “Commitment Premium”). The Commitment Premium was fully earned as of January 19, 2017, the date the Backstop Approval Order was entered by the Bankruptcy Court. The Commitment Premium will be paid either in the form of new common stock at the Rights Offering Price, if the Plan is consummated as contemplated in the Plan Support Agreement, or in cash in the amount of 4.0% of the $580.0 million committed amount, if the Backstop Agreement is terminated other than as a result of a material breach by the Commitment Parties. Exit Financing Commitment Letter : On February 8, 2017, the Debtors obtained a commitment letter (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 has agreed to provide secured and unsecured financing in an aggregate amount of up to $2.4 billion, consisting of: • A seven-year senior secured first lien term loan credit facility (the “Term Loan Facility”) in an aggregate amount of $600.0 million; • A five-year senior secured first lien revolving credit facility (the “Revolving Facility”) in an aggregate amount of $400.0 million with an initial borrowing base (the “Borrowing Base”) (which limits the aggregate amount of first lien debt under the Revolving Facility and the Term Loan Facility) of $1.0 billion with scheduled semi-annual redeterminations starting on October 1, 2017; and • Senior unsecured bridge loans under senior unsecured bridge facilities (together with the Revolving Facility and the Term Loan Facility, the “Credit Facilities”) in an aggregate amount of $1.4 billion, consisting of (i) a five-year bridge facility in an aggregate principal amount of $700.0 million, less the aggregate principal amount of privately placed five-year senior unsecured notes of the Company, if any, issued on or prior to the closing date of the Credit Facilities (the “Closing Date”) and (ii) an eight-year bridge facility in an aggregate principal amount of $700.0 million, less the aggregate principal amount of privately placed eight-year senior unsecured notes of the Company, if any, issued on or prior to the Closing Date. The Revolving Facility is anticipated to, among other things: • have capacity for the Debtors to increase the commitments subject to certain conditions; • have $100.0 million of the commitments available for the issuance of letters of credit; and • require the Company to maintain (A) a maximum total net debt to EBITDAX ratio of (i) 4.25 to 1.0 as of the end of the first full fiscal quarter after the closing date and each subsequent fiscal quarter of 2017 and (ii) 4.0 to 1.0 as of the end of each fiscal quarter thereafter, (B) a minimum current ratio of 1.0 to 1.0 and (C) a minimum interest coverage ratio of 2.5 to 1.0. The Term Loan Facility is anticipated to, among other things, have capacity for the Debtors to increase the commitments, with such increase in commitments subject to certain conditions. The Revolving Facility and Term Loan Facility will include customary affirmative and negative covenants, including, among other things, as to compliance with laws, delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of properties (including oil and gas properties), maintenance of a lien on, and delivery of title information with respect to, 85% of the Debtors’ proved oil and gas reserves, restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. The Revolving Facility and Term Loan Facility will include events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to material indebtedness; bankruptcy; material judgments; and certain ERISA events. Many events of default are subject to customary notice and cure periods. The commitments of Barclays to provide the Credit Facilities are subject to certain conditions set forth in the Commitment Letter, including but not limited to the Plan Support Parties’ reasonable satisfaction with the approval by the Bankruptcy Court of all actions to be taken, undertakings to be made and obligations to be incurred by the Debtors in connection with the Credit Facilities. The Commitment Letter will terminate upon the occurrence of certain events described therein and the outside termination date for the Commitment Letter is May 9, 2017. Based on the indicative pricing levels provided to the Company, the blended interest rate of the Credit Facilities on the effective date of the Plan (the “Blended Rate”) is expected to be approximately 5.10% per annum. The actual Blended Rate on the effective date of the Plan will depend on factors including, without limitation, the size of each tranche of the Credit Facilities and the results of the syndication process of such Credit Facilities, and may therefore be higher or lower than 5.10% per annum. As previously disclosed on a Current Report on Form 8-K filed with the SEC on February 9, 2017, on February 8, 2017, the Debtors filed a motion with the Bankruptcy Court seeking authorization to enter into and perform under the Commitment Letter and the other commitment papers. The motion was heard and approved during the Company’s disclosure statement hearing on February 13, 2017. Plan of Reorganization (Disclosure Statement) We plan to emerge from our chapter 11 cases after we obtain approval from the Bankruptcy Court for a chapter 11 plan of reorganization. Among other things, a chapter 11 plan of reorganization will determine the rights and satisfy the claims of our prepetition creditors and security holders. The terms and conditions of a chapter 11 plan of reorganization will be determined through negotiations with our stakeholders and, possibly, decisions by the Bankruptcy Court. On December 6, 2016, we filed an initial plan of reorganization and disclosure statement therefore. On January 17, 2017, we filed a revised plan of reorganization and disclosure statement therefore. On February 8, 2017, we filed a further revised plan of reorganization and disclosure statement therefore. On February 13, 2017, we filed amendments and further revisions to the plan of reorganization we filed on February 8, 2017 (the “Plan”) and to the disclosure statement therefore (the “Disclosure Statement”). The Court approved our Disclosure Statement on February 13, 2017 and scheduled a hearing to consider confirmation of the Plan for March 14, 2017. Under the absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of our existing common stock can receive any distribution or retain any property under a chapter 11 plan of reorganization. The ultimate recovery to creditors and/or shareholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors or shareholders. Our plan of reorganization could result in any of the holders of our liabilities and/or securities, including our common stock, receiving no distribution on account of their interests and cancellation of their holdings. Moreover, a plan of reorganization can be confirmed, under the Bankruptcy Code, even if the holders of our common stock vote against the plan and even if the plan provides that the holders of our common stock receive no distribution on account of their equity interests. Liabilities Subject to Compromise We have applied Accounting Standards Codification (“ASC”) 852, Reorganizations, in preparing the Consolidated Financial Statements included in this Annual Report on Form 10-K. In addition, the consolidated financial statements presented here include amounts classified as “liabilities subject to compromise.” This amount represents estimates of known or potential prepetition claims expected to be resolved in connection with our chapter 11 proceedings. Additional amounts may be included in liabilities subject to compromise in future periods if we elect to reject executory contracts and unexpired leases as part of our chapter 11 cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Annual Report on Form 10-K and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the chapter 11 process, and we plan to make adjustments in future periods as necessary and appropriate. Such adjustments may be material. Under the Bankruptcy Code, we may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. If we reject a contract or lease, such rejection generally (1) is treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieves the Debtors of performing their future obligations under such contract or lease, and (3) entitles the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. If we assume an executory contract or unexpired lease, we are generally required to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty. Accordingly, any description of an executory contract or unexpired lease in this Annual Report on Form 10-K, including any quantification of our obligations under any such contract or lease, is wholly qualified by the rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto. The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of December 31, 2016: December 31, 2016 Accounts payable $ 1,322 Accrued liabilities 6,303 Accrued interest payable 99,774 Debt 3,759,000 Accrued contract settlements 171,642 Liabilities subject to compromise $ 4,038,041 Schedules and Statements – Magnitude of Potential Claims & Claims Resolution Process On June 8, 2016, each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. On October 14, 2016, Ultra Wyoming LGS, LLC (“UWLGS”), one of the Debtors and our indirect, wholly owned subsidiary, filed an amendment to its Schedules and Statements. The Schedules and Statements are subject to further amendment or modification. Certain holders of prepetition claims were required to file proofs of claim by the deadline for filing certain proofs of claims in the Debtors’ chapter 11 cases, which deadline was September 1, 2016, for prepetition general unsecured claims and October 26, 2016, for governmental claims. Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and will likely continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained. To the best of our knowledge, we have notified all of our known current or potential creditors that the Debtors have filed chapter 11 cases. The Schedules and Statements set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors is a party, and are subject to the qualifications and assumptions included therein and amendment or modification as our chapter 11 cases proceed. Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. In addition, there are differences between the amounts for certain claims listed in the Schedules and Statements and the amounts claimed by our creditors. Such differences, as well as other disputes and contingencies will be investigated and resolved as part of our claims resolution process in our chapter 11 cases. Please refer to Note 11 for additional information about contingent matters and commitments related to certain claims filed in our chapter 11 cases. Pursuant to the Federal Rules of Bankruptcy Procedure, some creditors who wished to assert prepetition claims against us and whose claims (i) were not listed in the Schedules and Statements or (ii) were listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to the bar date set by the court. The bar date for non-governmental creditors was September 1, 2016, and the bar date for governmental creditors was October 26, 2016. The claims filed against the Debtors to date are voluminous. Further, it is possible that claimants will file amended or modified claims in the future, including modifications or amendments to assign values to claims originally filed with no designated value. The amended or modified claims may be material. We plan to investigate and evaluate all filed claims in connection with our plan of reorganization. As a part of the claims resolution process, we anticipate working to resolve differences in amounts we listed in our Schedules and Statements and amounts of claims filed by our creditors. We have already identified, for example, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have previously filed, and we will continue to file and prosecute objections with the Bankruptcy Court as necessary for claims we believe should be disallowed. Tax Attributes; Net Operating Loss Carryforwards We have substantial tax net operating loss carryforwards and other tax attributes. Under the U.S. Internal Revenue Code, our ability to use these net operating losses and other tax attributes may be limited if we experience a change of control, as determined under U.S. Internal Revenue Code. Accordingly, we obtained an order from the Bankruptcy Court that is intended to protect our ability to use our tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s common stock. In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock. Such persons are required to notify us and the Bankruptcy Court before effecting a transaction that might result in us losing the ability to use our tax attributes, and we have the right to seek an injunction to prevent the transaction if it might adversely affect our ability to use our tax attributes. Any purchase, sale or other transfer of our equity securities in violation of the restrictions of the order is null and would be treated as invalid from the outset as an act in violation of a Bankruptcy Court order and would therefore confer no rights on a proposed transferee. Costs of Reorganization We have incurred and will continue to incur 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. In addition, a non-cash charge to write-off the unamortized debt issuance costs related to our funded indebtedness is included in “Reorganization items, net” as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. 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 three and year months ended December 31, 2016: For the Twelve Months Ended December 31, 2016 2015 2014 Professional fees(1) $ 11,781 $ — $ — Deferred financing costs(2) 18,742 — — Contract settlements(3) 17,350 — — Other(4) (370 ) — — Total Reorganization items, net $ 47,503 $ — $ — (1) The year ended December 31, 2016 includes $6.4 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings. (2) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. (3) Includes accrued, unpaid amounts subject to Bankruptcy Court approval related to a settlement reached with Big West Oil, LLC in the amount of $17.35 million. (4) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital. Ability to Continue as a Going Concern The Consolidated Financial Statements included in this Annual Report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. As a result of our financial condition at the time the financial statements were originally issued, including the defaults under our debt agreements, and the risks and uncertainties surrounding our chapter 11 proceedings, we concluded that substantial doubt existed that we would be able to continue as a going concern. On March 14, 2017, the Bankruptcy Court confirmed the Company’s Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization .

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	1. SIGNIFICANT ACCOUNTING POLICIES: Our accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements. (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 2016 or 2014. 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: (j) Income Taxes: (k) Earnings (loss) Per Share: The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2016 2015 2014 Net income $ 56,151 $ (3,207,220 ) $ 542,851 Weighted average common shares outstanding during the period 153,378 153,192 153,136 Effect of dilutive instruments 703 — 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net income per common share — basic $ 0.37 $ (20.94 ) $ 3.54 Net income per common share — fully diluted $ 0.36 $ (20.94 ) $ 3.51 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 1,437 — 1,377 (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. (l) Use of Estimates: (m) Accounting for Share-Based Compensation: (n) Fair Value Accounting: (o) Asset Retirement Obligation: (p) 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, 2016 and December 31, 2015 were immaterial. (q) Capitalized Interest: (r) Capital Cost Accrual: (s) Reclassifications: (t) Deposits and Retainers: (u) Recent Accounting Pronouncements: Statement of Cash Flows (Topic 230): Restricted Cash In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting In February 2016, the FASB issued ASU 2016-02, Leases In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory In April 2015, the FASB issued ASU 2015-03, Interest — Imputation of Interest (Subtopic 835-30) —Simplifying the Presentation of Debt Issuance Costs. Interest —Imputation of Interest (Subtopic 835-30) — Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements 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 We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation, completed training of the new ASU’s revenue recognition model, and begun contract review and documentation. The primary impacts to the Company of adopting ASU 2014-09 relate to principal versus agent considerations and the use of the entitlements method for oil and natural gas sales, both of which are continuing to be evaluated by the Company. 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 cumulative catch-up transition method). The Company is currently evaluating the available adoption methods. In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligations 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, 2016 2015 Asset retirement obligations at beginning of period $ 146,210 $ 127,240 Accretion expense 10,252 9,122 Liabilities incurred 1,317 7,352 Liabilities settled (170 ) (1,861 ) Revisions of estimated liabilities (436 ) 4,357 Asset retirement obligations at end of period 157,173 146,210 Less: current asset retirement obligations (239 ) (305 ) Long-term asset retirement obligations $ 156,934 $ 145,905

Oil and Gas Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2016
Oil And Gas Properties And Equipment Tables [Abstract]
OIL AND GAS PROPERTIES	3. December 31, 2016 December 31, 2015 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,752,642 $ 10,480,165 Less: Accumulated depletion, depreciation and amortization(1) (9,742,176 ) (9,629,020 ) 1,010,466 851,145 On a unit basis, DD&A was $0.44, $1.38 and $1.18 per Mcfe for the years ended December 31, 2016, 2015 and 2014, respectively. (1) 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.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment Disclosure Abstract
PROPERTY, PLANT AND EQUIPMENT	4. PROPERTY, PLANT AND EQUIPMENT: December 31, 2016 2015 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,840 (2,237 ) 603 794 Office equipment 309 (171 ) 138 196 Leasehold improvements 486 (301 ) 185 267 Land 4,637 — 4,637 4,637 Other 12,460 (10,328 ) 2,132 2,950 Property, plant and equipment, net $ 20,732 $ (13,037 ) $ 7,695 $ 8,844

Debt and Other Long-Term Liabil

Debt and Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2016
Long Term Liabilities Tables [Abstract]
DEBT AND OTHER LONG-TERM LIABILITIES	5. DEBT AND OTHER LONG-TERM LIABILITIES: December 31, 2016 December 31, 2015 Total Debt: 6.125% Senior Notes due 2024 $ 850,000 $ 850,000 5.75% Senior Notes due 2018 450,000 450,000 Senior Notes issued by Ultra Resources, Inc. 1,460,000 1,460,000 Credit Agreement 999,000 630,000 Total current portion of long-term debt 3,759,000 3,390,000 Less: Deferred financing costs(1) — (19,447 ) Less: Liabilities subject to compromise(2) (See Note 1) (3,759,000 ) — Total current portion of long-term debt not subject to compromise — $ 3,370,553 December 31, 2016 December 31, 2015 Other long-term obligations: Other long-term obligations $ 177,088 $ 165,784 Aggregate maturities of debt at December 31, 2016:(2) 2017 2018 2019 2020 2021 Beyond 5 years Total $ 3,759,000 $ — $ — $ — $ — $ — $ 3,759,000 (1) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, the unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net in the Consolidated Statements of Operations as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. (2) We have significant indebtedness, all of which is included with liabilities subject to compromise at December 31, 2016 in the Consolidated Balance Sheets. Our level of indebtedness has adversely impacted and is continuing to adversely impact our financial condition. As a result of our financial condition, the defaults under our debt agreements and the risks and uncertainties surrounding our chapter 11 proceedings, substantial doubt exists that we will be able to continue as a going concern. As a result, we have classified all of our total outstanding debt as short-term. Ultra Resources, Inc. Bank indebtedness. Ultra Resources, Inc. (“Ultra Resources”), a wholly owned subsidiary of the Company, is a party to the Credit Agreement. Ultra Resources’ obligations under the Credit Agreement are guaranteed by the Company and UP Energy Corporation, a wholly owned subsidiary of the Company. Ultra Resources’ filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated its obligations under the Credit Agreement. Other events of default are also present with respect to the Credit Agreement, including a failure to make interest payments and, as described below, a failure to deliver annual audited consolidated financial statements without a going concern qualification, a failure to meet the minimum PV-9 ratio covenant and a failure to comply with the consolidated leverage covenant in the Credit Agreement at the end of the first quarter of 2016. The Credit Agreement provides that upon the acceleration of Ultra Resources’ obligations under the Credit Agreement, the outstanding balance of loans extended under the Credit Agreement comes due, unpaid interest accrued as of the time of the acceleration comes due, and any fees or other obligations of the borrower come due. Under the Bankruptcy Code, the creditors under the Credit Agreement are stayed from taking any action against Ultra Resources or any of the other Debtors as a result of the default. Prior to April 29, 2016, loans under the Credit Agreement bore interest, at the borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus a margin based on a grid of the borrower’s consolidated leverage ratio, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the borrower’s consolidated leverage ratio. The Credit Agreement requires us to deliver annual audited, consolidated financial statements for the Company without a “going concern” or like qualification or explanation. On March 15, 2016, we delivered an audit report with respect to the financial statements in our 2015 Annual Report on Form 10-K that included an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” The Credit Agreement contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31, 2016 (the ratio was 4.6 times at March 31, 2016). The Credit Agreement contains a PV-9 covenant, pursuant to which Ultra Resources is required to maintain a minimum ratio of the discounted net present value of its oil and gas properties to its total funded consolidated debt of 1.5 times. We were required to report whether we were in compliance with this covenant on April 1, 2016. Based on the PV-9 of its oil and gas properties at December 31, 2015, Ultra Resources failed to comply with the PV-9 ratio covenant under the Credit Agreement (the ratio was 0.9 times at December 31, 2015). Senior Notes . Ultra Resources has outstanding $1.46 billion of senior notes (“Senior Notes”) which were issued pursuant to a certain Master Note Purchase Agreement dated as of March 6, 2008 (as amended, supplemented or otherwise modified, the “MNPA”). The Senior Notes rank pari passu with the Credit Agreement. Payment of the Senior Notes is guaranteed by the Company and by UP Energy Corporation. The Senior Notes are subject to representations, warranties, covenants and events of default similar to those in the Credit Agreement. Ultra Resources’ filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated its obligations under the MNPA and the Senior Notes. Other events of default are also present with respect to the MNPA, including a failure to comply with the consolidated leverage covenant at the end of the first quarter of 2016 and a failure to make principal and interest payments due under the Ultra Resources’ Senior Notes. The MNPA provides that upon the acceleration of Ultra Resources’ obligations under the MNPA and the Senior Notes, among other matters, the Senior Notes are deemed to have matured, the unpaid principal balance of the Senior Notes comes due, unpaid interest accrued as of the time of the acceleration comes due, and any applicable make-whole amount (as determined pursuant to the MNPA) comes due. Under the Bankruptcy Code, the creditors under the Senior Notes are stayed from taking any action against Ultra Resources or any of the other the Debtors as a result of the default. The MNPA contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31, 2016 (the ratio was 4.6 times at March 31, 2016). On March 1, 2016, we failed to make an interest payment of approximately $40.0 million and a principal payment of $62.0 million, each of which was due March 1, 2016 under the terms of the Senior Notes. We entered into a forbearance agreement related to the failure to make these payments with the holders of the Senior Notes, and we filed the chapter 11 petitions without making the payments before the forbearance period expired. Interest Expense . No interest expense has been recognized with respect to the Credit Agreement or the Senior Notes subsequent to the Petition Date. Ultra Petroleum Corp. Senior Notes The Company’s filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated the Company’s obligations under the 2024 Notes and the 2018 Notes. Additionally, other events of default, including cross-defaults, are present due to the failure to make interest payments and other matters. Under the indentures pursuant to which the 2024 Notes and the 2018 Notes, respectively, were issued, upon the acceleration of the Company’s obligations under the 2024 Notes and the 2018 Notes, among other matters, the 2024 Notes and the 2018 Notes, respectively, are deemed to have matured, the unpaid principal balance of the 2024 Notes and the 2018 Notes, respectively, comes due, unpaid interest accrued as of the time of the acceleration comes due, and any applicable premiums (as determined pursuant to the indentures) comes due. Under the Bankruptcy Code, the creditors under the 2024 Notes and the 2018 Notes are stayed from taking any action against the Debtors as a result of the default. Senior Notes due 2024 : On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and, as a result, are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. Interest due under the 2024 Notes is payable each April 1 and October 1. On April 1, 2016, we elected to defer making an interest payment on the 2024 Notes of approximately $26.0 million due April 1, 2016. The indenture governing the 2024 Notes provides a 30-day grace period for us to make this interest payment. We did not make this interest payment before the end of the grace period, which resulted in an event of default under the indenture governing the 2024 Notes. Senior Notes due 2018 : On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and, as a result, are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. Interest due under the 2018 Notes is payable each June 15 and December 15. The Company’s filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated the Company’s obligations under the 2024 Notes and the 2018 Notes. Additionally, other events of default, including cross-defaults resulting from the acceleration of indebtedness outstanding under the Credit Agreement and the Ultra Resources’ Senior Notes, are present due to the failure to make interest payments and other matters. Under the Bankruptcy Code, the creditors under the 2024 Notes and the 2018 Notes are stayed from taking any action against the Debtors as a result of the Company’s bankruptcy filings. Interest Expense . No interest expense has been recognized with respect to the 2024 Notes or the 2018 Notes subsequent to the Petition Date. 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, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
SHARE BASED COMPENSATION	6. SHARE BASED COMPENSATION: The Company sponsors a share based compensation plan: the 2015 Stock Incentive Plan (“2015 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 purpose of the 2015 Plan is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the Plan permits the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions and estimates forfeitures that may occur. The Committee may grant awards under the 2015 Plan until December 31, 2024. Valuation and Expense Information Year Ended December 31, 2016 2015 2014 Total cost of share-based payment plans $ 8,013 $ 6,137 $ 8,640 Amounts capitalized in oil and gas properties and equipment $ 2,451 $ 2,009 $ 3,173 Amounts charged against income, before income tax benefit $ 5,562 $ 4,128 $ 5,467 Amount of related income tax benefit recognized in income before valuation allowances $ 2,216 $ 1,645 $ 2,285 Securities Authorized for Issuance Under Equity Compensation Plans As of December 31, 2016, 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 to be Issued Upon Exercise of Outstanding Options Weighted Average Exercise Price of Outstanding Options Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in the First Column) (000’s) (000’s) Equity compensation plans approved by security holders 346 $ 60.64 4,339 Equity compensation plans not approved by security holders n/a n/a n/a Total 346 $ 60.64 4,339 Changes in Stock Options and Stock Options Outstanding The following table summarizes the changes in stock options for the three year period ended December 31, 2016: Number of Options Weighted Average Exercise Price (US$) (000’s) Balance, December 31, 2013 1,246 $ 16.97 to $ 98.87 Forfeited (513 ) $ 33.57 to $ 75.18 Exercised (43 ) $ 16.97 to $ 25.68 Balance, December 31, 2014 690 $ 25.68 to $ 98.87 Forfeited (171 ) $ 25.68 to $ 75.18 Balance, December 31, 2015 519 $ 49.05 to $ 98.87 Forfeited (173 ) $ 50.15 to $ 75.18 Balance, December 31, 2016 346 $ 49.05 to $ 98.87 The following table summarizes information about the stock options outstanding and exercisable at December 31, 2016: Options Outstanding and Exercisable Range of Exercise Price Number Outstanding Weighted Average Remaining Contractual Life Weighted Average Exercise Price Aggregate Intrinsic Value (000’s) (Years) $49.05 — $62.23 210 0.31 $ 54.12 $ — $51.60 — $98.87 136 1.45 $ 70.64 $ — The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $7.23 per share on December 31, 2016, which would have been received by the option holders had all option holders exercised their options as of that date. There were no in-the-money options exercisable as of December 31, 2016. The following table summarizes information about the weighted-average grant-date fair value of share options: 2016 2015 2014 Options forfeited during the year $ 25.17 $ 28.00 $ 24.40 As of December 31, 2011, all options were fully vested; therefore, no options vested during the years ended December 31, 2016, 2015 or 2014. There were no stock options exercised during the years ended December 31, 2016, 2015 and 2014. At December 31, 2016, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011. PERFORMANCE SHARE PLANS: Long Term Incentive Plans. During 2015 and 2014, the Company offered 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. Each LTIP covers a performance period of three years. Under each LTIP, the Committee establishes a percentage of base salary for each participant that is multiplied by the participant’s base salary at the beginning of the performance period and individual performance level to derive a Long Term Incentive Value as a “target” value. This “target” value corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the participant is employed by the Company through the date the award vests and if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event the Company’s actual performance is below or above target levels. Time-Based Measure and Performance-Based Measures: For each LTIP, the Compensation Committee established time-based and performance-based measures at the beginning of each three-year performance period. For the LTIP awards in 2015 and 2014, the Compensation Committee established the following performance-based measures: return on capital employed, debt level, and reserve replacement ratio. At the time the LTIP awards are awarded, the fair value of the time-based and performance-based component of the LTIP award is based on the average high and low market price of the Company’s common stock on the date of the award. Market-Based Measure (Total Shareholder Return): LTIP awards granted to officers during 2016 and 2015, included an additional performance metric, Total Shareholder Return. The grant-date fair value related to the market-based condition was calculated using a Monte Carlo simulation. Valuation Assumptions The Company estimates the fair value of the market condition related to the LTIP awards on the date of grant using a Monte Carlo simulation with the following assumptions: 2015 LTIP 2014 LTIP Volatility of common stock 40.1 % 39.0 % Average volatility of peer companies 46.5 % n/a Average correlation coefficient of peer companies 0.454 n/a Risk-free interest rate 1.02 % 0.66 % Stock-Based Compensation Cost: For the year ended December 31, 2016, the Company recognized $4.7 million in pre-tax compensation expense related to the 2015 and 2014 LTIP awards. For the year ended December 31, 2015, the Company recognized $2.9 million in pre-tax compensation expense related to the 2015, 2014 and 2013 LTIP awards. For the year ended December 31, 2014, the Company recognized $6.3 million in pre-tax compensation expense related to the 2014, 2013 and 2012 LTIP awards. The amounts recognized during the year ended December 31, 2016 assumes that performance objectives between less than threshold and up to maximum are attained for the 2015 LTIP and 2014 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2016, for each of the three-year performance periods is expected to be approximately $10.3 million and $9.5 million related to the 2015 and 2014 LTIP awards of restricted stock units, respectively. Based on the Company’s achievement relative to the 2013 LTIP’s performance-based measures, and based on the continued employment with the Company by those participants who received a payment in connection with the 2013 LTIP relative to the 2013 LTIP’s time-based measures, during the first quarter of 2016, the Compensation Committee approved payment of the 2013 LTIP. This was the first payment of an LTIP since our LTIPs were modified in 2013 to include time-based and performance-based measures. As such, the Compensation Committee elected to pay the time-based portion of the LTIP awards in cash at the award value and the performance-based portion of the LTIP awards in shares of our common stock. The payout of the 2013 LTIP was during the first quarter of 2016 and totaled $3.8 million (resulting in delivery of 132,843 net shares of our common stock to eligible participants in the 2013 LTIP).

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Financial Instruments Disclosure [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS	7. DERIVATIVE FINANCIAL INSTRUMENTS: Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise. 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. The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production 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, 2016, the Company had no open commodity derivative contracts to manage price risk on a portion of its production. 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, 2016, 2015 and 2014: For the Year Ended December 31, Commodity Derivatives: 2016 2015 2014 Realized gain (loss) on commodity derivatives-natural gas(1) $ — $ 146,801 $ (48,170 ) Realized gain on commodity derivatives-crude oil(1) — — 506 Unrealized (loss) gain on commodity derivatives(1) — (104,190 ) 130,066 Total gain on commodity derivatives $ — $ 42,611 $ 82,402 (1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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). 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, 2016(1) December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value 7.31% Notes due March 2016, issued 2009 62,000 64,266 62,000 63,604 4.98% Notes due January 2017, issued 2010 116,000 123,967 116,000 113,420 5.92% Notes due March 2018, issued 2008 200,000 224,025 200,000 191,985 5.75% Notes due December 2018, issued 2013 450,000 465,630 450,000 111,451 7.77% Notes due March 2019, issued 2009 173,000 204,854 173,000 174,488 5.50% Notes due January 2020, issued 2010 207,000 233,932 207,000 185,052 4.51% Notes due October 2020, issued 2010 315,000 337,528 315,000 258,520 5.60% Notes due January 2022, issued 2010 87,000 99,983 87,000 73,034 4.66% Notes due October 2022, issued 2010 35,000 38,225 35,000 25,558 6.125% Notes due October 2024, issued 2014 850,000 893,325 850,000 206,321 5.85% Notes due January 2025, issued 2010 90,000 106,299 90,000 70,756 4.91% Notes due October 2025, issued 2010 175,000 193,665 175,000 115,911 Credit Facility due October 2016 999,000 999,000 630,000 630,000 $ 3,759,000 $ 3,984,699 $ 3,390,000 $ 2,220,100 (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, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	9. INCOME TAXES: Income (loss) before income tax benefit is as follows: Year Ended December 31, 2016 2015 2014 United States $ 134,959 $ (3,249,590 ) $ 505,689 Foreign (79,462 ) 37,966 31,338 Total $ 55,497 $ (3,211,624 ) $ 537,027 The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2016 2015 2014 Current tax: U.S. federal, state and local $ (72 ) $ — $ (110 ) Foreign (583 ) (3,414 ) (6,709 ) Total current tax (benefit) (655 ) (3,414 ) (6,819 ) Deferred tax: Foreign 1 (990 ) 995 Total deferred tax (benefit) expense 1 (990 ) 995 Total income tax (benefit) $ (654 ) $ (4,404 ) $ (5,824 ) 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, 2016 2015 2014 Income tax provision (benefit) computed at the U.S. statutory rate $ 19,424 $ (1,124,069 ) $ 187,959 State income tax (benefit) provision net of federal effect (2,335 ) (12,998 ) 8,023 Valuation allowance (31,083 ) 1,147,619 (199,038 ) Tax effect of rate change — 12,898 15,457 Foreign rate differential 17,388 (26,740 ) (16,314 ) Other, net (4,048 ) (1,114 ) (1,911 ) Total income tax (benefit) $ (654 ) $ (4,404 ) $ (5,824 ) 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, 2016 2015 Deferred tax assets : Property and equipment 603,045 776,504 Deferred gain 40,867 44,593 U.S. federal tax credit carryforwards 15,967 16,144 U.S. net operating loss carryforwards 428,212 319,673 U.S. state net operating loss carryforwards 71,323 61,919 Non-U.S. net operating loss carryforwards 30,211 9,142 Asset retirement obligations 55,700 51,815 Liabilities subject to compromise-contract settlement 59,166 — Incentive compensation/other, net 16,088 28,711 1,320,579 1,308,501 Valuation allowance (1,270,935 ) (1,307,076 ) Net deferred tax assets $ 49,644 $ 1,425 Deferred tax liabilities : Liabilities subject to compromise-interest 35,498 — Liabilities subject to compromise-interest (non-U.S.) 14,146 — Other — non-US — 1,424 Net tax liabilities $ 49,644 $ 1,424 Net tax asset $ — $ 1 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, 2016 and 2015, the Company recorded a valuation allowance against certain deferred tax assets of $1.3 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’s valuation allowance decreased by $36.1 million from December 31, 2015 to December 31, 2016. Of this amount, $31.1 million reduced the Company’s current year deferred tax benefit, and $5.1 million was reflected through shareholders’ equity. As of December 31, 2016, the Company had approximately $13.7 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. The Company has $0.5 million of general business credits available to offset U.S. federal income taxes. These general business credits expire in 2032. In addition, the Company has $1.6 million of foreign tax credit carryforwards, which will expire in 2017. The Company has a U.S. federal tax net operating loss carryforward of $1.2 billion which will be carried forward to offset taxable income generated in future years, and if unutilized, will expire between 2033 and 2036. The Company has Pennsylvania state tax net operating loss carry forwards of $1.1 billion which will expire between 2031 and 2036. The Company has Utah state tax net operating loss carry forwards of $80.8 million which will expire between 2033 and 2036. The Company has immaterial state tax net operating loss carry forwards in other jurisdictions, none of which expire prior to 2020. Without regard to the recorded valuation allowance, if the Company experiences an 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 has a Canada Federal and Provincial tax loss carryforward remaining after carryback of $111.9 million that will be carried forward to offset taxable income generated in future years and will expire in 2036. 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, 2016. 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 2013 through 2016 remain open to examination by the major taxing jurisdictions in which the Company has business activity. The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon.

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2016
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 $2.3 million, $2.3 million and $2.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2016
Commitements And Contingencies Disclosures [Abstract]
COMMITMENTS AND CONTINGENCIES	11. COMMITMENTS AND CONTINGENCIES: The commencement of the chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates, and the Company has obtained from the Bankruptcy Court authority to pay certain prepetition claims in the ordinary course of business notwithstanding the commencement of the chapter 11 proceedings. A future plan of reorganization in the chapter 11 proceedings, when confirmed, will provide for the treatment of claims against the Company’s bankruptcy estates, including prepetition liabilities that have not otherwise been satisfied or addressed during the chapter 11 proceedings. Indebtedness Claims The chapter 11 filings by the Company and its various subsidiaries, including Ultra Resources, constituted events of default under the Company’s debt agreements. See Note 5 of this Annual Report on Form 10-K for more information about the debt agreements. On or around September 1, 2016, many of the holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid interest that had accrued by the petition dates, interest that has accrued since the petition dates (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations under the debt agreements. On December 29, 2016, holders of certain Senior Notes (as defined below) filed a complaint initiating an adversary proceeding against us in our chapter 11 cases. In the complaint, among other matters, the noteholders allege that there is a make-whole amount due under the Senior Notes as a result of our filing the chapter 11 cases, which they assert is “no less than $200,725,869, exclusive of any interest thereon.” On January 13, 2017, holders of certain other Senior Notes intervened to join the adversary proceeding as plaintiffs. On January 30, 2017, we filed a motion to dismiss the complaint. On February 10, 2017, both noteholder groups objected to our motion to dismiss. On February 13, 2017, the Court set a briefing schedule and a hearing date for April 20, 2017 for resolution of the make-whole and interest claims. At this time, we are not able to determine the likelihood or range of amounts attributable to claims for postpetition interest, make-whole amounts, or other fees and obligations under the debt agreements. We anticipate these claims will be resolved during our chapter 11 proceedings, although it is possible resolution of some of these matters could occur after we emerge from chapter 11. Rockies Express Pipeline On February 26, 2016, we received a letter from Sempra Rockies Marketing, LLC (“Sempra”) alleging that we were in breach of our Capacity Release Agreement, dated March 5, 2009 (the “Capacity Agreement”), resulting from nonpayment of fees for transportation service and notifying us that Sempra was authorized to recall the capacity released to us under the Capacity Agreement and to pursue any claims for damages or other remedies to which Sempra was entitled. On March 8, 2016, we received a letter from Sempra notifying us that Sempra was exercising its alleged right to permanently recall the 50,000 MMBtu/day of capacity on the Rockies Express Pipeline pursuant to the Capacity Agreement and that the recall would be effective as of March 9, 2016. On August 25, 2016, Sempra filed a proof of claim with the Bankruptcy Court for approximately $63.8 million. On October 28, 2016, we filed an objection to Sempra’s proof of claim. On December 20, 2016, Sempra filed a response to the Company’s objection. On November 28, 2016, the Bankruptcy Court entered a scheduling order establishing March 2, 2017 as the trial date for the claim objection. On January 23, 2017, the Bankruptcy Court entered an updated scheduling order establishing April 18, 2017 as the trial date for the claim objection. Our estimate of the potential exposure in connection with the Capacity Agreement and Sempra’s claim filed in our chapter 11 proceedings ranges from $4.2 million, which represents amounts Sempra paid to Rockies Express attributable to the capacity released to us under the Capacity Agreement prior to Sempra’s recalling such capacity, to $63.8 million. We anticipate Sempra’s claims will be resolved through our chapter 11 proceedings. On April 4, 2016, we received a demand for payment and notice of enforcement from Rockies Express Pipeline LLC (“REX”) in connection with the transportation agreement related to the Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016. On April 14, 2016, REX filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages related to the alleged breach. On August 26, 2016, REX filed a proof of claim with the Bankruptcy Court for $303.3 million. The Company objected to REX’s proof of claim. On January 12, 2017, REX and the Company entered into a settlement agreement resolving REX’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to REX of $150.0 million six months after the Company emerges from chapter 11, but no later than October 30, 2017, and to provide REX an allowed general unsecured claim under our Plan in that amount. Additionally, in connection with the settlement, we agreed to enter into, with REX, a new seven-year agreement, commencing December 1, 2019, for firm transportation service on the Rockies Express Pipeline, west-to-east, of 200,000 dekatherms per day at a rate of approximately $0.37 per dekatherm, or approximately $26.8 million annually. The settlement with REX has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization. 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. During the second quarter of 2016, the Company responded to the preliminary determination asserting the reasonableness of its allocation methodology of such costs, noting several matters we believed should have been considered in the preliminary determination notice. The ONRR unbundling review could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods. On October 27, 2016, ONRR filed a proof of claim with the Bankruptcy Court asserting approximately $35.1 million in claims attributable to the Company’s royalty calculations. 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. We dispute SPMT’s positions in the letter and its proof of claim. 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 its breach of the contract during the prepetition period. On January 18, 2017, SPMT filed a reply to our objection SPMT’s proof of claim and an answer to our complaint in the adversary proceeding. At this time, we are not able to determine the likelihood or range of damages owed to SPMT, if any, related to this matter, or, if and when such amounts are assessed, whether such amounts would be material. SPMT is a member of our official committee of unsecured creditors. We anticipate SPMT’s claims will be resolved through our chapter 11 proceedings. The Company is a party, with Big West Oil, LLC (“Big West”), to several prepetition contracts (the “Crude Contracts”) for the purchase and sale of crude oil. On April 26, 2016, Big West Oil LLC (“Big West”) and the Company entered into a Temporary Suspension of Contracts and Interim Crude Oil Purchase and Sale Agreement (“Suspension Agreement”), pursuant to which the parties suspended performance under the prepetition contracts. On August 30, 2016, Big West filed a proof of claim with the Bankruptcy Court for $32.6 million. The Company objected to Big West’s proof of claim. On January 20, 2017, Big West and the Company reached an agreement settling and resolving Big West’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to Big West, within six months of our emergence from chapter 11, of $17.35 million to provide Big West with an allowed general unsecured claim against all of the Ultra Entities in that amount and that all of our prepetition contracts with Big West, including the Suspension Agreement, would be rejected (with no additional damages other than the $17.35 million payment) in connection with our plan of reorganization. Additionally, in connection with the settlement, we and Big West agreed to enter into two new, Operating Lease During December 2012, the Company sold its 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 $229.9 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 $6.6 million at December 31, 2016; ($1.3 million in 2017; $1.2 million in 2018; $1.2 million in 2019; $1.2 million in 2020; and $1.1 million in 2021 with the remainder due beyond five years). During the years ended December 31, 2016, 2015 and 2014, the Company recognized expense associated with its office leases in the amount of $1.5 million, $1.3 million, and $1.0 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, 2017, the Company has long-term natural gas delivery commitments of 2.8 MMMBtu in 2018 under existing agreements. As of February 9, 2017, the Company has long-term crude oil delivery commitments of 1.6 MMBbls in 2017, 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 a lawsuit related 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 intend to defend this case 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, 2016
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. 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, 2016. A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2016, the Company had one single customer that represented approximately 10% of its total revenues.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	13. SUBSEQUENT EVENTS: The Company has evaluated the period subsequent to December 31, 2016 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below: • On January 17, 2017, we filed a revised plan of reorganization and disclosure statement therefore. On February 8, 2017, we filed a further revised plan of reorganization and disclosure statement therefore. On February 13, 2017, we filed amendments and further revisions to the plan of reorganization we filed on February 8, 2017 and to the disclosure statement therefore. The Court approved our Disclosure Statement on February 13, 2017 and scheduled a hearing to consider confirmation of the Plan for March 14, 2017. On February 21, 2017, the Court signed an amended order approving our Disclosure Statement. The amended order: (1) approves the adequacy of our Disclosure Statement, (2) approves the solicitation and notice procedures related to confirmation of our plan of reorganization, (3) approves the forms of ballots and notices related thereto, (4) approves the rights offering procedures and matters related thereto, (5) schedules certain dates related to our plan confirmation process and Rights Offering, and (6) grants related relief. With respect to the Rights Offering, the amended order defines the “Subscription Commencement Date” as February 21, 2017. Accordingly, as will be reflected in the materials to be distributed in connection with the Rights Offering, the Plan Value under the PSA is $6.0 billion. • On February 8, 2017, the Debtors obtained a commitment letter from Barclays, pursuant to which, in connection with the consummation of the Plan, Barclays has agreed to provide secured and unsecured financing in an aggregate amount of up to $2.4 billion, consisting of (i) a seven-year senior secured first lien term loan credit facility in an aggregate amount of $600.0 million, (ii) a five-year senior secured first lien revolving credit facility in an aggregate amount of $400.0 million and (iii) senior unsecured bridge loans under senior unsecured bridge facilities in an aggregate amount of up to $1.4 billion. • As of January 19, 2017, the Backstop Approval Order was entered by the Bankruptcy Court and the Commitment Premium was fully earned by the Commitment Parties; the order being entered on January 19, 2017 satisfied one of the milestones in the Backstop Agreement. The Commitment Premium will be paid either in the form of new common stock at the Rights Offering Price, if the Plan is consummated as contemplated in the Plan Support Agreement, or in cash if the Backstop Agreement is terminated other than as a result of a material breach by the Commitment Parties. See Note 1 for further details. • On April 4, 2016, we received a demand for payment and notice of enforcement from REX in connection with the transportation agreement related to the Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016. On April 14, 2016, REX filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages related to the alleged breach. On August 26, 2016, REX filed a proof of claim with the Bankruptcy Court for $303.3 million. The Company objected to REX’s proof of claim. On January 12, 2017, REX and the Company entered into a settlement agreement resolving REX’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to REX of $150.0 million six months after the Company emerges from chapter 11, but no later than October 30, 2017, and to provide REX an allowed general unsecured claim under our Plan in that amount. Additionally, in connection with the settlement, we agreed to enter into, with REX, a new seven-year agreement, commencing December 1, 2019, for firm transportation service on the Rockies Express Pipeline, west-to-east, of 200,000 dekatherms per day at a rate of approximately $0.37 per dekatherm, or approximately $26.8 million annually. The settlement with REX has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization. • The Company is a party, with Big West Oil, LLC (“Big West”), to several prepetition contracts (the “Crude Contracts”) for the purchase and sale of crude oil. On April 26, 2016, Big West Oil LLC (“Big West”) and the Company entered into a Temporary Suspension of Contracts and Interim Crude Oil Purchase and Sale Agreement (“Suspension Agreement”), pursuant to which the parties suspended performance under the prepetition contracts. On August 30, 2016, Big West filed a proof of claim with the Bankruptcy Court for $32.6 million. The Company objected to Big West’s proof of claim. On January 20, 2017, Big West and the Company reached an agreement settling and resolving Big West’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to Big West, within six months of our emergence from chapter 11, of $17.35 million, to provide Big West with an allowed general unsecured claim against all of the Ultra Entities in that amount and that all of our prepetition contracts with Big West, including the Suspension Agreement, would be rejected (with no additional damages other than the $17.35 million payment) in connection with our plan of reorganization. Additionally, in connection with the settlement, we and Big West agreed to enter into two new, two-year, contracts for the purchase and sale of crude oil we produce in Wyoming and Utah. The settlement with Big West has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization.

Summarized Quarterly Financial

Summarized Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 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 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 $ (0.14 ) $ 0.09 $ 0.64 $ (0.22 ) $ 0.37 Net income (loss) per common share — fully diluted $ (0.14 ) $ 0.09 $ 0.64 $ (0.22 ) $ 0.36 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 219,309 $ 207,998 $ 222,503 $ 189,301 $ 839,111 Gain (loss) on commodity derivatives 36,865 (3,646 ) 9,390 2 42,611 Operating expenses 189,347 188,483 195,339 207,452 780,621 Ceiling test and other impairments — — — 3,144,899 3,144,899 Interest expense (42,668 ) (42,619 ) (43,137 ) (43,494 ) (171,918 ) Other income (expense), net (992 ) 1,827 2,354 903 4,092 Income before income tax provision 23,167 (24,923 ) (4,229 ) (3,205,639 ) (3,211,624 ) Income tax provision (2,022 ) (250 ) (1,133 ) (999 ) (4,404 ) Net income $ 25,189 $ (24,673 ) $ (3,096 ) $ (3,204,640 ) $ (3,207,220 ) Net income per common share — basic $ 0.16 $ (0.16 ) $ (0.02 ) $ (20.91 ) $ (20.94 ) Net income per common share — fully diluted $ 0.16 $ (0.16 ) $ (0.02 ) $ (20.91 ) $ (20.94 )

Disclosure About Oil and Gas Pr

Disclosure About Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2016
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 Vice President — Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, a Masters of Business Administration 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, 2016, 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, 2016, 2015 and 2014 in this annual report. For the year ended December 31, 2013, the Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets in Wyoming and Pennsylvania in this annual report. Due to the timing of the closing of the acquisition in Utah in December 2013 relative to the timing of preparing annual corporate reserves, the Company’s Reservoir Engineering Department prepared the proved reserve estimates for its Utah assets for the year ended December 31, 2013, which were prepared in accordance with the Company’s internal controls and SEC regulations and represented less than 2% of estimated proved reserves as of December 31, 2013. 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, 2016, 2015 and 2014 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2016, 2015 and 2014. All such reserves are located in the Green River Basin in Wyoming, the Uinta Basin in Utah and the Appalachian Basin of Pennsylvania. B. ANALYSES OF CHANGES IN PROVEN RESERVES: United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Reserves, December 31, 2013 34,119 3,409,742 — Extensions, discoveries and additions 34,275 866,513 210 Sales — (239,290 ) — Acquisitions 9,381 1,345,964 21,740 Production (3,409 ) (228,517 ) — Revisions (6,600 ) (323,218 ) 43 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 United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Proved: Developed 20,566 1,777,267 — Undeveloped 13,553 1,632,475 — Total Proved — 2013 34,119 3,409,742 — 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 Changes in proved developed reserves : During 2016, substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2016. 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. NGLs : During 2014, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017. These contracts provide for an annual election to process NGLs, and the Company elected not to process NGLs in 2017. 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. In addition, as a part of our internal controls for determining a plan to develop our proved reserves each year, we consider whether we have the financial capability to develop proved undeveloped reserves. This year, because substantial doubt exists about our ability to continue as a going concern, we lack the required degree of certainty that we have the ability to fund a development plan. Therefore, as of December 31, 2016, we did not book any PUD reserves. As of February 22, 2017, the Company has 5 rigs running in the Pinedale field (4 operated, 1 non-operated) and, subject to available capital, intends to continue drilling and completing wells. We expect to report PUD reserves in future filings if we determine that we have the financial capability to execute a development plan. 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, 2016, 2015 and 2014 was $2.07, $2.21 and $4.32 per Mcf, respectively, for natural gas, and $37.90, $42.36 and $80.62 per barrel, respectively, for oil and condensate. During 2014, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017. These contracts provide for an annual election to process NGLs, and the Company elected not to process NGLs in 2017. 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, 2016 2015 2014 Future cash inflows $ 5,812,234 $ 6,312,095 $ 27,331,391 Future production costs (2,665,082 ) (3,006,265 ) (8,627,657 ) Future development costs (355,923 ) (358,848 ) (3,859,385 ) Future income taxes — — (3,898,355 ) Future net cash flows 2,791,229 2,946,982 10,945,994 Discount at 10% (1,100,283 ) (1,081,333 ) (5,712,511 ) Standardized measure of discounted future net cash flows $ 1,690,946 $ 1,865,649 $ 5,233,483 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, 2016 2015 2014 Standardized measure, beginning $ 1,865,649 $ 5,233,483 $ 3,187,969 Net revisions of previous quantity estimates (9,623 ) (2,126,998 ) (603,795 ) Extensions, discoveries and other changes 209,603 15,254 1,787,643 Sales of reserves in place — — (398,506 ) Acquisition of reserves — — 2,552,491 Changes in future development costs 11,556 1,618,068 (1,013,652 ) Sales of oil and gas, net of production costs (454,725 ) (550,879 ) (949,389 ) Net change in prices and production costs (72,939 ) (6,996,416 ) 1,010,052 Development costs incurred during the period that reduce future development costs 22,523 548,112 342,987 Accretion of discount 186,565 709,736 413,177 Net changes in production rates and other (67,663 ) 1,551,413 (175,419 ) Net change in income taxes — 1,863,876 (920,075 ) Aggregate changes (174,703 ) (3,367,834 ) 2,045,514 Standardized measure, ending $ 1,690,946 $ 1,865,649 $ 5,233,483 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, 2016 2015 2014 United States Property Acquisitions: Unproved $ 983 $ 13,845 $ 26,106 Proved — — 895,179 Exploration* 224,277 18,164 197,664 Development 44,300 461,458 382,984 Total $ 269,560 $ 493,467 $ 1,501,933 * 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, 2016 2015 2014 United States Oil and gas revenue $ 721,091 $ 839,111 $ 1,230,020 Production expenses (266,366 ) (288,231 ) (280,631 ) Depletion and depreciation (125,121 ) (401,200 ) (292,951 ) Ceiling test and other impairments — (3,144,899 ) — Income tax benefit (expense) 83,112 (9,841 ) 3,736 Total $ 412,716 $ (3,005,060 ) $ 660,174 G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2016 2015 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,752,642 $ 10,480,165 Less: accumulated depletion, depreciation and amortization (9,742,176 ) (9,629,020 ) 1,010,466 851,145 Unproven Properties: $ 1,010,466 $ 851,145

Supplemental Financial Statemen

Supplemental Financial Statement Information	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 General and administrative expense $ 650 $ 308 $ 261 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) (26,590 ) (81,069 ) (42,996 ) Income (loss) from unconsolidated affiliates 157,450 (3,152,078 ) 558,634 Guarantee fee income 6,073 23,029 23,045 Other expense (64,888 ) (1,684 ) (1,324 ) Reorganization items, net (15,827 ) — — Income (loss) before income taxes 55,568 (3,212,110 ) 537,098 Income tax benefit (583 ) (4,890 ) (5,753 ) Net income (loss) $ 56,151 $ (3,207,220 ) $ 542,851 CONDENSED BALANCE SHEET December 31, 2016 December 31, 2015 ASSETS Current Assets: Cash and cash equivalents $ 3,009 $ 523 Accounts receivable from related companies 29,939 64,542 Other current assets 2,100 5,150 Total current assets 35,048 70,215 Other non-current assets — 24,197 Total assets $ 35,048 $ 94,412 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Current portion of long-term debt $ — $ 1,283,232 Interest payable — 14,166 Accrued and other current liabilities 47 — Total current liabilities 47 1,297,398 Advances from unconsolidated affiliates 1,623,414 1,788,951 Total liabilities not subject to compromise 1,623,461 3,086,349 Liabilities subject to compromise 1,339,739 — Total shareholders’ deficit (2,928,152 ) (2,991,937 ) Total liabilities and shareholders’ equity $ 35,048 $ 94,412 CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2016 2015 2014 Net cash (used in) operating activities $ (21,309 ) $ (101,277 ) $ (35,818 ) Investing Activities: Investment in subsidiaries — — (850,000 ) Dividends received 24,089 96,297 52,741 Net cash provided by (used in) investing activities 24,089 96,297 (797,259 ) Financing activities: Proceeds from issuance of Senior Notes — — 850,000 Deferred financing costs — 6 (13,245 ) Repurchased shares/net share settlements 43 — (6,471 ) Shares re-issued from treasury (337 ) 4,725 2,936 Net cash (used in) provided by financing activities (294 ) 4,731 833,220 Increase (decrease) in cash during the period 2,486 (249 ) 143 Cash and cash equivalents, beginning of period 523 772 629 Cash and cash equivalents, end of period $ 3,009 $ 523 $ 772

Significant Accounting Polici26

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 2016 or 2014. 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:
Income taxes	(j) Income Taxes:
Earnings (loss) per share	(k) Earnings (loss) Per Share: The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2016 2015 2014 Net income $ 56,151 $ (3,207,220 ) $ 542,851 Weighted average common shares outstanding during the period 153,378 153,192 153,136 Effect of dilutive instruments 703 — 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net income per common share — basic $ 0.37 $ (20.94 ) $ 3.54 Net income per common share — fully diluted $ 0.36 $ (20.94 ) $ 3.51 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 1,437 — 1,377 (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	(l) Use of Estimates:
Accounting for share-based compensation	(m) Accounting for Share-Based Compensation:
Fair value accounting	(n) Fair Value Accounting:
Asset retirement obligation	(o) Asset Retirement Obligation:
Revenue recognition	(p) Revenue Recognition: 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, 2016 and December 31, 2015 were immaterial.
Capitalized interest	(q) Capitalized Interest:
Capital cost accrual	(r) Capital Cost Accrual:
Reclassifications	(s) Reclassifications:
Deposits and retainers	(t) Deposits and Retainers:
Recent accounting pronouncements	(u) Recent Accounting Pronouncements: Statement of Cash Flows (Topic 230): Restricted Cash In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting In February 2016, the FASB issued ASU 2016-02, Leases In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory In April 2015, the FASB issued ASU 2015-03, Interest — Imputation of Interest (Subtopic 835-30) —Simplifying the Presentation of Debt Issuance Costs. Interest —Imputation of Interest (Subtopic 835-30) — Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements 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 We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation, completed training of the new ASU’s revenue recognition model, and begun contract review and documentation. The primary impacts to the Company of adopting ASU 2014-09 relate to principal versus agent considerations and the use of the entitlements method for oil and natural gas sales, both of which are continuing to be evaluated by the Company. 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 cumulative catch-up transition method). The Company is currently evaluating the available adoption methods. In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

Chapter 11 Proceedings, Abili27

Chapter 11 Proceedings, Ability to Continue as a Going Concern (Tables)	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Schedule Of Liabilities Subject To Compromise	December 31, 2016 Accounts payable $ 1,322 Accrued liabilities 6,303 Accrued interest payable 99,774 Debt 3,759,000 Accrued contract settlements 171,642 Liabilities subject to compromise $ 4,038,041
Schedule Of Reorganization Items Table	For the Twelve Months Ended December 31, 2016 2015 2014 Professional fees(1) $ 11,781 $ — $ — Deferred financing costs(2) 18,742 — — Contract settlements(3) 17,350 — — Other(4) (370 ) — — Total Reorganization items, net $ 47,503 $ — $ — (1) The year ended December 31, 2016 includes $6.4 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings. (2) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. (3) Includes accrued, unpaid amounts subject to Bankruptcy Court approval related to a settlement reached with Big West Oil, LLC in the amount of $17.35 million. (4) Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Significant Accounting Polici28

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Significant Accounting Tables Policies [Abstract]
Schedule Of Earnings Per Share	The following table provides a reconciliation of components of basic and diluted net income per common share: December 31, 2016 2015 2014 Net income $ 56,151 $ (3,207,220 ) $ 542,851 Weighted average common shares outstanding during the period 153,378 153,192 153,136 Effect of dilutive instruments 703 — 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net income per common share — basic $ 0.37 $ (20.94 ) $ 3.54 Net income per common share — fully diluted $ 0.36 $ (20.94 ) $ 3.51 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 1,437 — 1,377 (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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Asset retirement obligations at beginning of period $ 146,210 $ 127,240 Accretion expense 10,252 9,122 Liabilities incurred 1,317 7,352 Liabilities settled (170 ) (1,861 ) Revisions of estimated liabilities (436 ) 4,357 Asset retirement obligations at end of period 157,173 146,210 Less: current asset retirement obligations (239 ) (305 ) Long-term asset retirement obligations $ 156,934 $ 145,905

Oil and Gas Properties (Tables)

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2016
Oil And Gas Properties And Equipment Tables [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities	December 31, 2016 December 31, 2015 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,752,642 $ 10,480,165 Less: Accumulated depletion, depreciation and amortization(1) (9,742,176 ) (9,629,020 ) 1,010,466 851,145 (1) 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.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Schedule of Property, Plant and Equipment	December 31, 2016 2015 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,840 (2,237 ) 603 794 Office equipment 309 (171 ) 138 196 Leasehold improvements 486 (301 ) 185 267 Land 4,637 — 4,637 4,637 Other 12,460 (10,328 ) 2,132 2,950 Property, plant and equipment, net $ 20,732 $ (13,037 ) $ 7,695 $ 8,844

Debt and Other Long-Term Liab32

Debt and Other Long-Term Liabilities (Table)	12 Months Ended
	Dec. 31, 2016
Long Term Liabilities Tables [Abstract]
Schedule of Long-term Liabilities	December 31, 2016 December 31, 2015 Total Debt: 6.125% Senior Notes due 2024 $ 850,000 $ 850,000 5.75% Senior Notes due 2018 450,000 450,000 Senior Notes issued by Ultra Resources, Inc. 1,460,000 1,460,000 Credit Agreement 999,000 630,000 Total current portion of long-term debt 3,759,000 3,390,000 Less: Deferred financing costs(1) — (19,447 ) Less: Liabilities subject to compromise(2) (See Note 1) (3,759,000 ) — Total current portion of long-term debt not subject to compromise — $ 3,370,553 December 31, 2016 December 31, 2015 Other long-term obligations: Other long-term obligations $ 177,088 $ 165,784
Maturity Schedule	Aggregate maturities of debt at December 31, 2016:(2) 2017 2018 2019 2020 2021 Beyond 5 years Total $ 3,759,000 $ — $ — $ — $ — $ — $ 3,759,000 (1) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, the unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net in the Consolidated Statements of Operations as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. (2) We have significant indebtedness, all of which is included with liabilities subject to compromise at December 31, 2016 in the Consolidated Balance Sheets. Our level of indebtedness has adversely impacted and is continuing to adversely impact our financial condition. As a result of our financial condition, the defaults under our debt agreements and the risks and uncertainties surrounding our chapter 11 proceedings, substantial doubt exists that we will be able to continue as a going concern. As a result, we have classified all of our total outstanding debt as short-term.

Share Based Compensation (Table

Share Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Share Based Compensation Tables [Abstract]
Valuation and Expense Information	Valuation and Expense Information Year Ended December 31, 2016 2015 2014 Total cost of share-based payment plans $ 8,013 $ 6,137 $ 8,640 Amounts capitalized in oil and gas properties and equipment $ 2,451 $ 2,009 $ 3,173 Amounts charged against income, before income tax benefit $ 5,562 $ 4,128 $ 5,467 Amount of related income tax benefit recognized in income before valuation allowances $ 2,216 $ 1,645 $ 2,285
Securities Authorized for Issuance Under Equity Compensation Plans	Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options Weighted Average Exercise Price of Outstanding Options Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in the First Column) (000’s) (000’s) Equity compensation plans approved by security holders 346 $ 60.64 4,339 Equity compensation plans not approved by security holders n/a n/a n/a Total 346 $ 60.64 4,339
Changes in Stock Options Outstanding	The following table summarizes the changes in stock options for the three year period ended December 31, 2016: Number of Options Weighted Average Exercise Price (US$) (000’s) Balance, December 31, 2013 1,246 $ 16.97 to $ 98.87 Forfeited (513 ) $ 33.57 to $ 75.18 Exercised (43 ) $ 16.97 to $ 25.68 Balance, December 31, 2014 690 $ 25.68 to $ 98.87 Forfeited (171 ) $ 25.68 to $ 75.18 Balance, December 31, 2015 519 $ 49.05 to $ 98.87 Forfeited (173 ) $ 50.15 to $ 75.18 Balance, December 31, 2016 346 $ 49.05 to $ 98.87
Share Based Compensation by Exercise Price Table	The following table summarizes information about the stock options outstanding and exercisable at December 31, 2016: Options Outstanding and Exercisable Range of Exercise Price Number Outstanding Weighted Average Remaining Contractual Life Weighted Average Exercise Price Aggregate Intrinsic Value (000’s) (Years) $49.05 — $62.23 210 0.31 $ 54.12 $ — $51.60 — $98.87 136 1.45 $ 70.64 $ —
Weighted Average Grant Date Fair Value of Stock Options	The following table summarizes information about the weighted-average grant-date fair value of share options: 2016 2015 2014 Options forfeited during the year $ 25.17 $ 28.00 $ 24.40
Valuation Assumptions	Valuation Assumptions The Company estimates the fair value of the market condition related to the LTIP awards on the date of grant using a Monte Carlo simulation with the following assumptions: 2015 LTIP 2014 LTIP Volatility of common stock 40.1 % 39.0 % Average volatility of peer companies 46.5 % n/a Average correlation coefficient of peer companies 0.454 n/a Risk-free interest rate 1.02 % 0.66 %

Derivative Financial Instrume34

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Financial Instruments Tables [Abstract]
Detail Schedule of Realized and Unrealized Gains and Losses	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, 2016, 2015 and 2014: For the Year Ended December 31, Commodity Derivatives: 2016 2015 2014 Realized gain (loss) on commodity derivatives-natural gas(1) $ — $ 146,801 $ (48,170 ) Realized gain on commodity derivatives-crude oil(1) — — 506 Unrealized (loss) gain on commodity derivatives(1) — (104,190 ) 130,066 Total gain on commodity derivatives $ — $ 42,611 $ 82,402 (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, 2016
Fair Value Measurements Tables [Abstract]
Fair Value of Long-Term Debt	December 31, 2016(1) December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value 7.31% Notes due March 2016, issued 2009 62,000 64,266 62,000 63,604 4.98% Notes due January 2017, issued 2010 116,000 123,967 116,000 113,420 5.92% Notes due March 2018, issued 2008 200,000 224,025 200,000 191,985 5.75% Notes due December 2018, issued 2013 450,000 465,630 450,000 111,451 7.77% Notes due March 2019, issued 2009 173,000 204,854 173,000 174,488 5.50% Notes due January 2020, issued 2010 207,000 233,932 207,000 185,052 4.51% Notes due October 2020, issued 2010 315,000 337,528 315,000 258,520 5.60% Notes due January 2022, issued 2010 87,000 99,983 87,000 73,034 4.66% Notes due October 2022, issued 2010 35,000 38,225 35,000 25,558 6.125% Notes due October 2024, issued 2014 850,000 893,325 850,000 206,321 5.85% Notes due January 2025, issued 2010 90,000 106,299 90,000 70,756 4.91% Notes due October 2025, issued 2010 175,000 193,665 175,000 115,911 Credit Facility due October 2016 999,000 999,000 630,000 630,000 $ 3,759,000 $ 3,984,699 $ 3,390,000 $ 2,220,100 (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, 2016
Income Tax Disclosure [Abstract]
Consolidated income tax provision table	Income (loss) before income tax benefit is as follows: Year Ended December 31, 2016 2015 2014 United States $ 134,959 $ (3,249,590 ) $ 505,689 Foreign (79,462 ) 37,966 31,338 Total $ 55,497 $ (3,211,624 ) $ 537,027 The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2016 2015 2014 Current tax: U.S. federal, state and local $ (72 ) $ — $ (110 ) Foreign (583 ) (3,414 ) (6,709 ) Total current tax (benefit) (655 ) (3,414 ) (6,819 ) Deferred tax: Foreign 1 (990 ) 995 Total deferred tax (benefit) expense 1 (990 ) 995 Total income tax (benefit) $ (654 ) $ (4,404 ) $ (5,824 )
Income tax expense reconciliation table	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, 2016 2015 2014 Income tax provision (benefit) computed at the U.S. statutory rate $ 19,424 $ (1,124,069 ) $ 187,959 State income tax (benefit) provision net of federal effect (2,335 ) (12,998 ) 8,023 Valuation allowance (31,083 ) 1,147,619 (199,038 ) Tax effect of rate change — 12,898 15,457 Foreign rate differential 17,388 (26,740 ) (16,314 ) Other, net (4,048 ) (1,114 ) (1,911 ) Total income tax (benefit) $ (654 ) $ (4,404 ) $ (5,824 )
Consolidated 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, 2016 2015 Deferred tax assets : Property and equipment 603,045 776,504 Deferred gain 40,867 44,593 U.S. federal tax credit carryforwards 15,967 16,144 U.S. net operating loss carryforwards 428,212 319,673 U.S. state net operating loss carryforwards 71,323 61,919 Non-U.S. net operating loss carryforwards 30,211 9,142 Asset retirement obligations 55,700 51,815 Liabilities subject to compromise-contract settlement 59,166 — Incentive compensation/other, net 16,088 28,711 1,320,579 1,308,501 Valuation allowance (1,270,935 ) (1,307,076 ) Net deferred tax assets $ 49,644 $ 1,425 Deferred tax liabilities : Liabilities subject to compromise-interest 35,498 — Liabilities subject to compromise-interest (non-U.S.) 14,146 — Other — non-US — 1,424 Net tax liabilities $ 49,644 $ 1,424 Net tax asset $ — $ 1

Summarized Quarterly Financia37

Summarized Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information Table Text Block	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 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 $ (0.14 ) $ 0.09 $ 0.64 $ (0.22 ) $ 0.37 Net income (loss) per common share — fully diluted $ (0.14 ) $ 0.09 $ 0.64 $ (0.22 ) $ 0.36 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Operating revenues $ 219,309 $ 207,998 $ 222,503 $ 189,301 $ 839,111 Gain (loss) on commodity derivatives 36,865 (3,646 ) 9,390 2 42,611 Operating expenses 189,347 188,483 195,339 207,452 780,621 Ceiling test and other impairments — — — 3,144,899 3,144,899 Interest expense (42,668 ) (42,619 ) (43,137 ) (43,494 ) (171,918 ) Other income (expense), net (992 ) 1,827 2,354 903 4,092 Income before income tax provision 23,167 (24,923 ) (4,229 ) (3,205,639 ) (3,211,624 ) Income tax provision (2,022 ) (250 ) (1,133 ) (999 ) (4,404 ) Net income $ 25,189 $ (24,673 ) $ (3,096 ) $ (3,204,640 ) $ (3,207,220 ) Net income per common share — basic $ 0.16 $ (0.16 ) $ (0.02 ) $ (20.91 ) $ (20.94 ) Net income per common share — fully diluted $ 0.16 $ (0.16 ) $ (0.02 ) $ (20.91 ) $ (20.94 )

Disclosures About Oil and Gas P

Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2013 34,119 3,409,742 — Extensions, discoveries and additions 34,275 866,513 210 Sales — (239,290 ) — Acquisitions 9,381 1,345,964 21,740 Production (3,409 ) (228,517 ) — Revisions (6,600 ) (323,218 ) 43 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 United States Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Proved: Developed 20,566 1,777,267 — Undeveloped 13,553 1,632,475 — Total Proved — 2013 34,119 3,409,742 — 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
Standardized measure	As of December 31, 2016 2015 2014 Future cash inflows $ 5,812,234 $ 6,312,095 $ 27,331,391 Future production costs (2,665,082 ) (3,006,265 ) (8,627,657 ) Future development costs (355,923 ) (358,848 ) (3,859,385 ) Future income taxes — — (3,898,355 ) Future net cash flows 2,791,229 2,946,982 10,945,994 Discount at 10% (1,100,283 ) (1,081,333 ) (5,712,511 ) Standardized measure of discounted future net cash flows $ 1,690,946 $ 1,865,649 $ 5,233,483
Summary of changes in the standardized measure of discounted future net cash flows	December 31, 2016 2015 2014 Standardized measure, beginning $ 1,865,649 $ 5,233,483 $ 3,187,969 Net revisions of previous quantity estimates (9,623 ) (2,126,998 ) (603,795 ) Extensions, discoveries and other changes 209,603 15,254 1,787,643 Sales of reserves in place — — (398,506 ) Acquisition of reserves — — 2,552,491 Changes in future development costs 11,556 1,618,068 (1,013,652 ) Sales of oil and gas, net of production costs (454,725 ) (550,879 ) (949,389 ) Net change in prices and production costs (72,939 ) (6,996,416 ) 1,010,052 Development costs incurred during the period that reduce future development costs 22,523 548,112 342,987 Accretion of discount 186,565 709,736 413,177 Net changes in production rates and other (67,663 ) 1,551,413 (175,419 ) Net change in income taxes — 1,863,876 (920,075 ) Aggregate changes (174,703 ) (3,367,834 ) 2,045,514 Standardized measure, ending $ 1,690,946 $ 1,865,649 $ 5,233,483
Costs incurred in oil and gas exploration and development activities	Years Ended December 31, 2016 2015 2014 United States Property Acquisitions: Unproved $ 983 $ 13,845 $ 26,106 Proved — — 895,179 Exploration* 224,277 18,164 197,664 Development 44,300 461,458 382,984 Total $ 269,560 $ 493,467 $ 1,501,933 * 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, 2016 2015 2014 United States Oil and gas revenue $ 721,091 $ 839,111 $ 1,230,020 Production expenses (266,366 ) (288,231 ) (280,631 ) Depletion and depreciation (125,121 ) (401,200 ) (292,951 ) Ceiling test and other impairments — (3,144,899 ) — Income tax benefit (expense) 83,112 (9,841 ) 3,736 Total $ 412,716 $ (3,005,060 ) $ 660,174
Capitalized Costs Relating to Oil and Gas Producing Activities	G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2016 2015 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,752,642 $ 10,480,165 Less: accumulated depletion, depreciation and amortization (9,742,176 ) (9,629,020 ) 1,010,466 851,145 Unproven Properties: $ 1,010,466 $ 851,145

Supplemental Financial Statem39

Supplemental Financial Statement Information (Parent Company) (Tables)	12 Months Ended
	Dec. 31, 2016
Parent Company Financial Statements [Abstract]
Supplemental Statement of Operations Disclosures Parent Company	CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2016 2015 2014 General and administrative expense $ 650 $ 308 $ 261 Other income (expense): Interest expense (excludes contractual interest expense of $52.4 million for the year ended December 31, 2016) (26,590 ) (81,069 ) (42,996 ) Income (loss) from unconsolidated affiliates 157,450 (3,152,078 ) 558,634 Guarantee fee income 6,073 23,029 23,045 Other expense (64,888 ) (1,684 ) (1,324 ) Reorganization items, net (15,827 ) — — Income (loss) before income taxes 55,568 (3,212,110 ) 537,098 Income tax benefit (583 ) (4,890 ) (5,753 ) Net income (loss) $ 56,151 $ (3,207,220 ) $ 542,851
Supplemental Balance Sheet Disclosures Parent Company	CONDENSED BALANCE SHEET December 31, 2016 December 31, 2015 ASSETS Current Assets: Cash and cash equivalents $ 3,009 $ 523 Accounts receivable from related companies 29,939 64,542 Other current assets 2,100 5,150 Total current assets 35,048 70,215 Other non-current assets — 24,197 Total assets $ 35,048 $ 94,412 LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Current portion of long-term debt $ — $ 1,283,232 Interest payable — 14,166 Accrued and other current liabilities 47 — Total current liabilities 47 1,297,398 Advances from unconsolidated affiliates 1,623,414 1,788,951 Total liabilities not subject to compromise 1,623,461 3,086,349 Liabilities subject to compromise 1,339,739 — Total shareholders’ deficit (2,928,152 ) (2,991,937 ) Total liabilities and shareholders’ equity $ 35,048 $ 94,412
Supplemental Cash Flow Statement Disclosures Parent Company	CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2016 2015 2014 Net cash (used in) operating activities $ (21,309 ) $ (101,277 ) $ (35,818 ) Investing Activities: Investment in subsidiaries — — (850,000 ) Dividends received 24,089 96,297 52,741 Net cash provided by (used in) investing activities 24,089 96,297 (797,259 ) Financing activities: Proceeds from issuance of Senior Notes — — 850,000 Deferred financing costs — 6 (13,245 ) Repurchased shares/net share settlements 43 — (6,471 ) Shares re-issued from treasury (337 ) 4,725 2,936 Net cash (used in) provided by financing activities (294 ) 4,731 833,220 Increase (decrease) in cash during the period 2,486 (249 ) 143 Cash and cash equivalents, beginning of period 523 772 629 Cash and cash equivalents, end of period $ 3,009 $ 523 $ 772

Chapter 11 Proceedings, Abili40

Chapter 11 Proceedings, Ability to Continue as a Going Concern Disclosure (Narratives) (Details) - USD ($)	2 Months Ended	3 Months Ended	12 Months Ended
	Feb. 13, 2017	Mar. 31, 2016	Dec. 31, 2016
Chapter11 Proceedings [Abstract]
NOL Order Beneficial Ownership Percentage			4.50%
Accrued and Unpaid Professional Fees			$ 6,400,000
Big West Settlement Agreement			$ 17,350,000
Plan Support Agreement, Rights Offering and Backstop Commitment Agreement [Abstract]
Percentage Of Principal Amount Of Debt Held By Plan Support Parties			66.67%
Senior Notes Ultra Petroleum Corp Due 2018 Interest Rate			5.75%
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate			6.125%
Plan Support Agreement [Abstract]
Reorganization Plan Value			$ 6,000,000,000
Reorganization Value High			6,250,000,000
Reorganization Value Low			$ 5,500,000,000
Reoganization Value High Strip Price			greater than $3.65/MMBtu
Reoganization Value Low Strip Price			less than $3.25/MMBtu
Exit Financing Commitment Letter [Abstract]
Aggregate Comitment Value	$ 2,400,000,000
Senior Secured Term Loan Facility	600,000,000
Senior Secured Revolving Facility	400,000,000
Initial Borrowing Base	1,000,000,000
Aggregate Bridge Loan Commitment Value	1,400,000,000
Five Year Bridge Facility	700,000,000
Eight Year Bridge Facility	700,000,000
Letters Of Credit Availability	$ 100,000,000
Revolving Facility Initial Max total net debt to EBITDAX Ratio	425.00%
Revolving Facility Max total net debt to EBITDAX Ratio	400.00%	350.00%
Revolving Facility Minimum Current Ratio	100.00%
Revolving Facility Minimum Interest Coverage Ratio	250.00%
Percentage of Proved Property Securing Debt	85.00%
Credit Facilities Blended Rate	5.10%
Rights Offering [Abstract]
Rights Offering Aggregate			$ 580,000,000
Rights Offering Subscription Value HoldCo Noteholders			435,000,000
Rights Offering Subscription Value HoldCo Equityholders			$ 145,000,000
Rights Offering Commitment Premium			6.00%
Rights Offering Terminated Commitment Premium			4.00%
Implied Plan Value Discount			20.00%

Chapter 11 Proceedings, Abili41

Chapter 11 Proceedings, Ability to Continue as a Going Concern (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Liabilities Subject To Compromise [Abstract]
Accounts payable	$ 1,322			$ 1,322
Accrued liabilities	6,303			6,303
Accrued interest payable	99,774			99,774
Debt	3,759,000			3,759,000
Accrued contract settlements	171,642			171,642
Liabilities subject to compromise	4,038,041			4,038,041	$ 0
Reorganization Items [Abstract]
Professional fees				11,781	0	$ 0
Deferred financing costs				18,742	0	0
Contract settlements				17,350
Other				(370)	0	0
Total Reorganization items, net	$ 22,211	$ 3,109	$ 22,183	$ 47,503	$ 0	$ 0

Significant Accounting Polici42

Significant Accounting Policies (Narratives) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Significant Accounting Policies Details [Abstract]
Ceiling test limitation	$ 3,100,000,000
Inventory	4,269,000	$ 4,906,000
Unamortized debt issuance costs reclassified	$ 19,400,000

Significant Accounting Polici43

Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share Reconciliation [Abstract]
Net income (loss)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	$ (3,204,640)	$ (3,096)	$ (24,673)	$ 25,189	$ 56,151	$ (3,207,220)	$ 542,851
Weighted average common shares outstanding during the period									153,378,000	153,192,000	153,136,000
Effect of dilutive instruments									703,000		1,558,000
Weighted average common shares outstanding during the period including the effects of dilutive instruments									154,081,000	153,192,000	154,694,000
Net income per common share — basic	$ (0.22)	$ 0.64	$ 0.09	$ (0.14)	$ (20.91)	$ (0.02)	$ (0.16)	$ 0.16	$ 0.37	$ (20.94)	$ 3.54
Net income per common share — fully diluted	$ (0.22)	$ 0.64	$ 0.09	$ (0.14)	$ (20.91)	$ (0.02)	$ (0.16)	$ 0.16	$ 0.36	$ (20.94)	$ 3.51
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									1,437,000	1,700,000	1,377,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$ 146,210	$ 127,240
Accretion expense	10,252	9,122
Liabilities incurred	1,317	7,352
Liabilities settled	(170)	(1,861)
Revisions of estimated liabilities	(436)	4,357
Asset retirement obligations at end of period	157,173	146,210
Less: current asset retirement obligations	(239)	(305)
Long-term asset retirement obligations	$ 156,934	$ 145,905

Oil and Gas Properties (Details

Oil and Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 10,752,642	$ 10,480,165
Less: Accumulated depletion, depreciation and amortization	(9,742,176)	(9,629,020)
Proven	$ 1,010,466	$ 851,145

Oil and Gas Properties (Narrati

Oil and Gas Properties (Narratives) (Details) $ in Billions	12 Months Ended
	Dec. 31, 2015USD ($)$ / Mcfe	Dec. 31, 2016$ / Mcfe	Dec. 31, 2014$ / Mcfe
Oil And Gas Property [Abstract]
DD&A per Mcfe | $ / Mcfe	1.38	0.44	1.18
Ceiling test limitation | $	$ 3.1

Property, Plant & Equipment (De

Property, Plant & Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Cost	$ 20,732
Accumulated Depreciation	(13,037)
Property, plant and equipment	7,695	$ 8,844
Computer equipment [Member]
Property Plant And Equipment [Line Items]
Cost	2,840
Accumulated Depreciation	(2,237)
Property, plant and equipment	603	794
Office equipment [Member]
Property Plant And Equipment [Line Items]
Cost	309
Accumulated Depreciation	(171)
Property, plant and equipment	138	196
Leasehold improvements [Member]
Property Plant And Equipment [Line Items]
Cost	486
Accumulated Depreciation	(301)
Property, plant and equipment	185	267
Land [Member]
Property Plant And Equipment [Line Items]
Cost	4,637
Accumulated Depreciation	0
Property, plant and equipment	4,637	4,637
Other [Member]
Property Plant And Equipment [Line Items]
Cost	12,460
Accumulated Depreciation	(10,328)
Property, plant and equipment	$ 2,132	$ 2,950

Debt and Other Long Term Liabil

Debt and Other Long Term Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Short Term Borrowings [Abstract]
6.125% Senior Notes due 2024	$ 850,000	$ 850,000
5.75% Senior Notes due 2018	450,000	450,000
Senior Notes issued by Ultra Resources, Inc.	1,460,000	1,460,000
Credit Agreement	999,000	630,000
Total current portion of long-term debt	3,759,000	3,390,000
Less: Deferred financing costs	0	(19,447)
Less: Liabilities subject to compromise	(3,759,000)	0
Total current portion of long-term debt not subject to compromise	0	3,370,553
Other long-term obligations [Abstract]
Other long-term obligations	$ 177,088	$ 165,784

Debt and Other Long Term Liab49

Debt and Other Long Term Liabilities (Details 1) $ in Thousands	Dec. 31, 2016USD ($)
Long Term Debt Maturities	$ 3,759,000
Maturities Of Long Term Debt One Year [Member]
Long Term Debt Maturities	3,759,000
Maturities of Long Term Debt 2017 [Member]
Long Term Debt Maturities	0
Maturities of Long Term Debt 2018 [Member]
Long Term Debt Maturities	0
Maturities of Long Term Debt 2019 [Member]
Long Term Debt Maturities	0
Maturities of Long Term Debt 2020 [Member]
Long Term Debt Maturities	0
Maturities Of Long Term Debt Beyond Five Years [Member]
Long Term Debt Maturities	$ 0

Debt and Other Long Term Liab50

Debt and Other Long Term Liabilities (Narratives) (Details) $ in Thousands	Apr. 04, 2016	Feb. 13, 2017	Mar. 31, 2016	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Apr. 01, 2016USD ($)	Mar. 01, 2016USD ($)
Senior Credit Facility Details
Credit Agreement Consolidated Leverage Ratio		400.00%	350.00%
Credit Agreement Consolidated Leverage Covenant			4.6
Debt Instrument Restrictive Covenants Present Value Ratio	1.5				0.9
Ultra Resources Inc Senior Notes
Senior Notes Ultra Resources Inc				$ 1,460,000	$ 1,460,000
Senior Notes Consolidated Leverage Ratio			350.00%
Senior Notes Consolidated Leverage Covenant			4.6
Ultra Petroleum Corp Senior Notes
Senior Notes Ultra Petroleum Corp Due 2024				$ 850,000	850,000
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate				6.125%
Senior Notes Ultra Petroleum Corp Due 2018				$ 450,000	$ 450,000
Senior Notes Ultra Petroleum Corp Due 2018 Interest Rate				5.75%
Maturities Schedule
Interest payment due Senior Notes Ultra Resources Inc							$ 40,000
Principal payment due Senior Notes Ultra Resources Inc							$ 62,000
Interest payment due Senior Notes Ultra PetroleumCorp Due 2024						$ 26,000

Share Based Compensation (Detai

Share Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation And Expense Information [Abstract]
Total cost of share-based payment plans	$ 8,013	$ 6,137	$ 8,640
Amounts capitalized in oil and gas properties and equipment	2,451	2,009	3,173
Amounts charged against income, before income tax benefit	5,562	4,128	5,467
Amount of related income tax benefit recognized in income before valuation allowances	$ 2,216	$ 1,645	$ 2,285

Share Based Compensation (Det52

Share Based Compensation (Details 1)	Dec. 31, 2016$ / sharesshares
Share Based Compensation Details [Abstract]
Number of Securities to be Issued Upon Exercise of Outstanding Options	346,000
Weighted Average Exercise Price of Outstanding Options | $ / shares	60.64
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in the First Column)	4,339,000

Share Based Compensation (Det53

Share Based Compensation (Details 2) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Options Outstanding Summary [Line Items]
Balance	346,000
Number Of Options [Member]
Stock Options Outstanding Summary [Line Items]
Balance	519,000	690,000	1,246,000
Forfeited	(173,000)	(171,000)	(513,000)
Exercised			(43,000)
Balance	346,000	519,000	690,000	1,246,000
Weighted Average Exercise Price [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 49.05	$ 49.05	$ 25.68	$ 16.97
Exercise Price, Upper Range Limit	98.87	98.87	98.87	$ 98.87
Exercise Price, Lower Range Limit Forfeited	50.15	25.68	33.57
Exercise Price, Upper Range Limit Forfeited	$ 75.18	$ 75.18	75.18
Exercise Price, Lower Range Limit Exercised			16.97
Exercise Price, Upper Range Limit Exercised			$ 25.68

Share Based Compensation (Det54

Share Based Compensation (Details 3) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Range 6 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 49.05
Exercise Price, Upper Range Limit	$ 62.23
Number Outstanding | shares	210,000
Weighted Average Remaining Contractual Life	3 months 22 days
Weighted Average Exercise Price	$ 54.12
Aggregate Intrinsic Value | $	$ 0
Range 7 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 51.60
Exercise Price, Upper Range Limit	$ 98.87
Number Outstanding | shares	136,000
Weighted Average Remaining Contractual Life	1 year 5 months 12 days
Weighted Average Exercise Price	$ 70.64
Aggregate Intrinsic Value | $	$ 0

Share Based Compensation (Narra

Share Based Compensation (Narratives) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Company's closing stock price last day of year	$ 7.23
Number of in the money options exercisable	0
Total intrinsic value of stock options excercised	$ 0	$ 0	$ 0
Long Term Incentive Program Period	4,700,000	$ 2,900,000	$ 6,300,000
Long Term Incentive Program Total 2015 Program	10,300,000
Long Term Incentive Program Total 2014 Program	9,500,000
Long Term Incentive Program Total 2013 Program	$ 3,800,000
Long Term Incentive Program Total 2013 Program Shares	132,843

Share Based Compensation (Det56

Share Based Compensation (Details 4) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Additional Disclosures [Abstract]
Options forfeited during the year	$ 25.17	$ 28	$ 24.40

Share Based Compensaton (TSR) (

Share Based Compensaton (TSR) (Details 5)	12 Months Ended
	Dec. 31, 2016
Long Term Incentive 2015 Plan [Member]
Total Shareholder Retun [Line Items]
Volatility of common stock	40.10%
Average correlation coefficient of peer companies	0.454
Risk-free interest rate	1.02%
Long Term Incentive 2015 Plan [Member] | Peer Companies [Member]
Total Shareholder Retun [Line Items]
Volatility of common stock	46.50%
Long Term Incentive 2014 Plan [Member]
Total Shareholder Retun [Line Items]
Volatility of common stock	39.00%
Risk-free interest rate	0.66%

Derivative Financial Instrume58

Derivative Financial Instruments (Narratives) (Details)	12 Months Ended
	Dec. 31, 2016
Commodity Derivatives Authorization [Abstract]
Commodity Derivatives Board Authorization	50.00%

Derivative Financial Instrume59

Derivative Financial Instruments (Details 1) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commodity Derivatives [Abstract]
Realized gain (loss) on commodity derivatives-natural gas					$ 0	$ 146,801	$ (48,170)
Realized gain on commodity derivatives-crude oil					0	0	506
Unrealized (loss) gain on commodity derivatives					0	(104,190)	130,066
Total gain on commodity derivatives	$ 2	$ 9,390	$ (3,646)	$ 36,865	$ 0	$ 42,611	$ 82,402

Fair Value Measurments (Details

Fair Value Measurments (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Carrying amount	$ 3,759,000	$ 3,390,000
Estimated Fair Value	3,984,699	2,220,100
Notes Due 2016 [Member]
Debt Instrument [Line Items]
Carrying amount	62,000	62,000
Estimated Fair Value	$ 64,266	63,604
Debt Instruments Interst Rates	7.31%
Notes Due 2017 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 116,000	116,000
Estimated Fair Value	$ 123,967	113,420
Debt Instruments Interst Rates	4.98%
Notes Due 2018 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 200,000	200,000
Estimated Fair Value	$ 224,025	191,985
Debt Instruments Interst Rates	5.92%
Notes Due December 2018 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 450,000	450,000
Estimated Fair Value	$ 465,630	111,451
Debt Instruments Interst Rates	5.75%
Notes Due 2019 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 173,000	173,000
Estimated Fair Value	$ 204,854	174,488
Debt Instruments Interst Rates	7.77%
Notes Due January 2020 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 207,000	207,000
Estimated Fair Value	$ 233,932	185,052
Debt Instruments Interst Rates	5.50%
Notes Due October 2020 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 315,000	315,000
Estimated Fair Value	$ 337,528	258,520
Debt Instruments Interst Rates	4.51%
Notes Due January 2022 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 87,000	87,000
Estimated Fair Value	$ 99,983	73,034
Debt Instruments Interst Rates	5.60%
Notes Due October 2022 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 35,000	35,000
Estimated Fair Value	$ 38,225	25,558
Debt Instruments Interst Rates	4.66%
Notes Due October 2024 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 850,000	850,000
Estimated Fair Value	$ 893,325	206,321
Debt Instruments Interst Rates	6.125%
Notes Due January 2025 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 90,000	90,000
Estimated Fair Value	$ 106,299	70,756
Debt Instruments Interst Rates	5.85%
Notes Due October 2025 [Member]
Debt Instrument [Line Items]
Carrying amount	$ 175,000	175,000
Estimated Fair Value	$ 193,665	115,911
Debt Instruments Interst Rates	4.91%
Credit Facility [Member]
Debt Instrument [Line Items]
Carrying amount	$ 999,000	630,000
Estimated Fair Value	$ 999,000	$ 630,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Loss From Continuing Operations [Abstract]
United States									$ 134,959	$ (3,249,590)	$ 505,689
Foreign									(79,462)	37,966	31,338
Income (loss) before income tax benefit	$ (34,776)	$ 98,452	$ 13,842	$ (22,021)	$ (3,205,639)	$ (4,229)	$ (24,923)	$ 23,167	$ 55,497	$ (3,211,624)	$ 537,027

Income Taxes (Details 1)

Income Taxes (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
U.S. federal, state and local - current									$ (72)	$ 0	$ (110)
Foreign - current									(583)	(3,414)	(6,709)
Total current tax (benefit)									(655)	(3,414)	(6,819)
Deferred:
Foreign - deferred									1	(990)	995
Total deferred tax (benefit) expense									1	(990)	995
Total income tax (benefit)	$ (349)	$ 45	$ (160)	$ (190)	$ (999)	$ (1,133)	$ (250)	$ (2,022)	$ (654)	$ (4,404)	$ (5,824)

Income Taxes (Narratives) (Deta

Income Taxes (Narratives) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Income Taxes Details [Abstract]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate	35.00%
Deferred Tax Assets, Valuation Allowance	$ 1,300,000	$ 1,300,000
Total change in valuation allowance	36,100
Change in valuation allowance - earnings	31,083	$ (1,147,619)	$ 199,038
Change in valuation allowance - equity	5,100
U.S. federal alternative minimum tax credits	13,700
Deferred Tax Assets Tax Credit Carryforwards General Business	500
Foreign tax credit carryforward	1,600
U.S. federal tax net operating loss carryforward	1,200,000
PA state tax net operating loss carryforwards	1,100,000
UT state tax net operating loss carryforwards	80,800
Canadian Federal and Provincial tax loss balance	$ 111,900

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Abstract]
Income tax provision (benefit) computed at the U.S. statutory rate									$ 19,424	$ (1,124,069)	$ 187,959
State income tax (benefit) provision net of federal effect									(2,335)	(12,998)	8,023
Valuation allowance									(31,083)	1,147,619	(199,038)
Tax effect of rate change									0	12,898	15,457
Foreign rate differential									17,388	(26,740)	(16,314)
Other, net									(4,048)	(1,114)	(1,911)
Total income tax (benefit)	$ (349)	$ 45	$ (160)	$ (190)	$ (999)	$ (1,133)	$ (250)	$ (2,022)	$ (654)	$ (4,404)	$ (5,824)

Income Taxes (Details 3)

Income Taxes (Details 3) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets [Abstract]
Property and equipment	$ 603,045	$ 776,504
Deferred gain	40,867	44,593
U.S. federal tax credit carryforwards	15,967	16,144
U.S. net operating loss carryforwards	428,212	319,673
U.S. state net operating loss carryforwards	71,323	61,919
Non-U.S. net operating loss carryforwards	30,211	9,142
Asset retirement obligations	55,700	51,815
Liabilities subject to compromise-contract settlement	59,166	0
Incentive compensation/other, net	16,088	28,711
Deferred tax assets noncurrent before valuation allowances	1,320,579	1,308,501
Valuation allowance	(1,270,935)	(1,307,076)
Net deferred tax assets	49,644	1,425
Deferred Tax Liabilities [Abstract]
Other — non-US	0	1,424
Liabilities subject to compromise-interest	35,498	0
Liabilities subject to compromise-interest (non-U.S.)	14,146	0
Net tax liabilities	49,644	1,424
Net tax asset	$ 0	$ 1

Employee Benefits (Details)

Employee Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 2.3	$ 2.3	$ 2

Commitments and Contingencies (

Commitments and Contingencies (Details) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)MMBTU$ / MMBTU	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments And Contingencies Disclosure [Abstract]
Ultra Resources Senior Noteholders Minimum Make-Whole Claim	$ 200,725,869
Increased commitment capacity per day of natural gas | MMBTU	50
Demand For Payment Sempra	$ 63,800,000
Contingency Lower Range Sempra	4,200,000
Contingency Upper Range Sempra	63,800,000
Demand for payment Rockies Express	303,200,000
Rockies Express Proof Of Claim	303,300,000
Rockies Express Settlement Agreement	$ 150,000,000
Commitment capacity per day of natural gas | MMBTU	200
Commitment capacity rate | $ / MMBTU	0.37
REX Transportation Services Expense	$ 26,800,000
ONRR Proof Of Claim	35,100,000
Demand for payment from Sunoco	38,600,000
Sunoco Proof Of Claim	16,900,000
Big West Proof Of Claim	32,600,000
Big West Settlement Agreement	$ 17,350,000
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%
Liquids Gathering System Operating Lease Rental Expense	$ 20,000,000
Lease And Rental Expense Total	229,900,000
Office Space Operating Lease Total Future Minimum Payments	6,600,000
Commitment to office leases, current	1,300,000
Commitment to office leases, due in two years	1,200,000
Commitment to office leases, due in three years	1,200,000
Commitment to office leases, due in four years	1,200,000
Commitment to office leases, due in five years	1,100,000
Office leases expense	$ 1,500,000	$ 1,300,000	$ 1,000,000
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, 2017, the Company has long-term natural gas delivery commitments of 2.8 MMMBtu in 2018 under existing agreements. As of February 9, 2017, the Company has long-term crude oil delivery commitments of 1.6 MMBbls in 2017, 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.

Credit Risk (Details)

Credit Risk (Details)	12 Months Ended
	Dec. 31, 2016
Schedule Of Significant Customers [Abstract]
Percentage of revenue	10.00%

Subsequent Event (Details)

Subsequent Event (Details) MMBTU in Thousands	2 Months Ended	12 Months Ended
	Feb. 13, 2017USD ($)	Dec. 31, 2016USD ($)MMBTU$ / MMBTU
Subsequent Events [Abstract]
Reorganization Plan Value		$ 6,000,000,000
Aggregate Comitment Value	$ 2,400,000,000
Term Loan Facility	600,000,000
Revolving Facility	400,000,000
Aggregate Bridge Loan Commitment Value	$ 1,400,000,000
Demand for payment Rockies Express		303,200,000
Rockies Express Proof Of Claim		303,300,000
Rockies Express Settlement Agreement		$ 150,000,000
Commitment capacity per day of natural gas | MMBTU		200
Commitment Capacity Rate | $ / MMBTU		0.37
REX Transportation Services Expense		$ 26,800,000
Big West Proof Of Claim		32,600,000
Big West Settlement Agreement		$ 17,350,000

Summarized Quarterly Financia70

Summarized Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 215,861	$ 199,253	$ 146,591	$ 159,386	$ 189,301	$ 222,503	$ 207,998	$ 219,309	$ 721,091	$ 839,111	$ 1,230,020
Gain (loss) on commodity derivatives					2	9,390	(3,646)	36,865	0	42,611	82,402
Operating expenses	99,313	99,788	94,746	126,868	207,452	195,339	188,483	189,347	420,715	780,621
Ceiling test and other impairments					3,144,899				0	3,144,899	0
Interest expense			(16,662)	(49,903)	(43,494)	(43,137)	(42,619)	(42,668)	(66,565)	(171,918)	(126,157)
Restructuring expenses		(28)	(1,569)	(5,579)					(7,176)	0	0
Contract settlement	(131,106)								(131,106)	0	0
Other income (expense), net	1,993	2,124	2,411	943	903	2,354	1,827	(992)	7,471	4,092
Total other (expense) income, net	(129,113)	2,096	(15,820)	(54,539)					(197,376)	(125,215)	(22,562)
Reorganization items, net	(22,211)	(3,109)	(22,183)						(47,503)	0	0
Income before income tax (benefit) provision	(34,776)	98,452	13,842	(22,021)	(3,205,639)	(4,229)	(24,923)	23,167	55,497	(3,211,624)	537,027
Income tax (benefit) provision	(349)	45	(160)	(190)	(999)	(1,133)	(250)	(2,022)	(654)	(4,404)	(5,824)
Net income (loss)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	$ (3,204,640)	$ (3,096)	$ (24,673)	$ 25,189	$ 56,151	$ (3,207,220)	$ 542,851
Net income (loss) per common share — basic	$ (0.22)	$ 0.64	$ 0.09	$ (0.14)	$ (20.91)	$ (0.02)	$ (0.16)	$ 0.16	$ 0.37	$ (20.94)	$ 3.54
Net income (loss) per common share — fully diluted	$ (0.22)	$ 0.64	$ 0.09	$ (0.14)	$ (20.91)	$ (0.02)	$ (0.16)	$ 0.16	$ 0.36	$ (20.94)	$ 3.51

Disclosure About Oil and Gas 71

Disclosure About Oil and Gas Producing Activities (Unaudited) (Narratives) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2014	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Internal Engineer Experience	15 years
Reserves Prepared Internally		2.00%
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.
Weighted Average Sales Price For Proved Reserves Natural Gas	$ 2.07	$ 4.32	$ 2.21
Weighted Average Sales Price For Proved Reserves Condensate	37.90	$ 80.62	42.36
Weighted Average Sales Price For Proved Reserves Natural Gas Liquids	$ 19.17		$ 20.61

Disclosure About Oil and Gas 72

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf
Oil Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	22,175	67,766	34,119
Extensions, discoveries and additions	3,519	166	34,275
Sales	0	0	0
Acquisitions	0	0	9,381
Production	(2,912)	(3,533)	(3,409)
Revisions	(1,307)	(42,224)	(6,600)
Reserves, Ending Balance	21,475	22,175	67,766
Natural Gas Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance | Mcf	2,336,280	4,831,194	3,409,742
Extensions, discoveries and additions | Mcf	251,634	17,415	866,513
Sales | Mcf	0	0	(239,290)
Acquisitions | Mcf	0	0	1,345,964
Production | Mcf	(264,278)	(268,954)	(228,517)
Revisions | Mcf	(2,023)	(2,243,375)	(323,218)
Reserves, Ending Balance | Mcf	2,321,613	2,336,280	4,831,194
Natural Gas Liquids Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	9,840	21,993	0
Extensions, discoveries and additions	530	3	210
Sales	0	0	0
Acquisitions	0	0	21,740
Production	0	0	0
Revisions	(467)	(12,156)	43
Reserves, Ending Balance	9,903	9,840	21,993

Disclosure About Oil and Gas 73

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 1) bbl in Thousands, Mcf in Thousands	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf	Dec. 31, 2013bblMcf
Oil Reserves [Member]
Reserve Quantities [Line Items]
Developed	21,475	22,175	28,481	20,566
Undeveloped	0	0	39,285	13,553
Total Proved	21,475	22,175	67,766	34,119
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Developed | Mcf	2,321,613	2,336,280	2,245,004	1,777,267
Undeveloped | Mcf	0	0	2,586,190	1,632,475
Total Proved | Mcf	2,321,613	2,336,280	4,831,194	3,409,742
Natural Gas Liquids Reserves [Member]
Reserve Quantities [Line Items]
Developed	9,903	9,840	9,118	0
Undeveloped	0	0	12,875	0
Total Proved	9,903	9,840	21,993	0

Disclosure About Oil and Gas 74

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 2) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future cash inflows	$ 5,812,234	$ 6,312,095	$ 27,331,391
Future production costs	(2,665,082)	(3,006,265)	(8,627,657)
Future development costs	(355,923)	(358,848)	(3,859,385)
Future income taxes	0	0	(3,898,355)
Future net cash flows	2,791,229	2,946,982	10,945,994
Discount at 10%	(1,100,283)	(1,081,333)	(5,712,511)
Standardized measure of discounted future net cash flows	$ 1,690,946	$ 1,865,649	$ 5,233,483	$ 3,187,969

Disclosure About Oil and Gas 75

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure, beginning	$ 1,865,649	$ 5,233,483	$ 3,187,969
Net revisions of previous quantity estimates	(9,623)	(2,126,998)	(603,795)
Extensions, discoveries and other changes	209,603	15,254	1,787,643
Sales of reserves in place	0	0	(398,506)
Acquisition of reserves	0	0	2,552,491
Changes in future development costs	11,556	1,618,068	(1,013,652)
Sales of oil and gas, net of production costs	(454,725)	(550,879)	(949,389)
Net change in prices and production costs	(72,939)	(6,996,416)	1,010,052
Development costs incurred during the period that reduce future development costs	22,523	548,112	342,987
Accretion of discount	186,565	709,736	413,177
Net changes in production rates and other	(67,663)	1,551,413	(175,419)
Net change in income taxes	0	1,863,876	(920,075)
Aggregate changes	(174,703)	(3,367,834)	2,045,514
Standardized measure, ending	$ 1,690,946	$ 1,865,649	$ 5,233,483

Disclosure About Oil and Gas 76

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$ 983	$ 13,845	$ 26,106
Acquisition costs - proved properties	0	0	895,179
Exploration	224,277	18,164	197,664
Development	44,300	461,458	382,984
Total	$ 269,560	$ 493,467	$ 1,501,933

Disclosure About Oil and Gas 77

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$ 721,091	$ 839,111	$ 1,230,020
Production expenses	(266,366)	(288,231)	(280,631)
Depletion and depreciation	(125,121)	(401,200)	(292,951)
Ceiling test and other impairments	0	(3,144,899)	0
Income tax benefit (expense)	83,112	(9,841)	3,736
Total	$ 412,716	$ (3,005,060)	$ 660,174

Disclosure About Oil and Gas 78

Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$ 10,752,642	$ 10,480,165
Less: Accumulated depletion, depreciation and amortization	(9,742,176)	(9,629,020)
Proven	1,010,466	851,145
Unproven Properties:
Net capitalized costs - oil and gas properties	$ 1,010,466	$ 851,145

Supplemental Financial Informat

Supplemental Financial Information (Parent - Statement of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
General and administrative expense									$ 9,179	$ 7,387	$ 19,069
Other income (expense), net:
Interest expense			$ (16,662)	$ (49,903)	$ (43,494)	$ (43,137)	$ (42,619)	$ (42,668)	(66,565)	(171,918)	(126,157)
Other expense									(3,082)	(2,060)	2,618
Income (loss) before income tax benefit	$ (34,776)	$ 98,452	13,842	(22,021)	(3,205,639)	(4,229)	(24,923)	23,167	55,497	(3,211,624)	537,027
Income tax benefit	(349)	45	(160)	(190)	(999)	(1,133)	(250)	(2,022)	(654)	(4,404)	(5,824)
Net income (loss)	$ (34,427)	$ 98,407	$ 14,002	$ (21,831)	$ (3,204,640)	$ (3,096)	$ (24,673)	$ 25,189	56,151	(3,207,220)	542,851
Parent [Member]
General and administrative expense									650	308	261
Other income (expense), net:
Interest expense									(26,590)	(81,069)	(42,996)
Income (loss) from unconsolidated affiliates									157,450	(3,152,078)	558,634
Guarantee fee income									6,073	23,029	23,045
Other expense									(64,888)	(1,684)	(1,324)
Reorganization items, net									(15,827)
Income (loss) before income tax benefit									55,568	(3,212,110)	537,098
Income tax benefit									(583)	(4,890)	(5,753)
Net income (loss)									$ 56,151	$ (3,207,220)	$ 542,851

Supplemental Financial Inform80

Supplemental Financial Information (Parent - Statement of Operations Contractual Interest) (Details 1) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Contractual Interest Expense On Prepetition Liabilities Not Recognized In Statement Of Operations	$ 141.5
Parent [Member]
Contractual Interest Expense On Prepetition Liabilities Not Recognized In Statement Of Operations	$ 52.4

Supplemental Financial Inform81

Supplemental Financial Information (Parent - Balance Sheet) (Details 2) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 401,478,000	$ 4,143,000	$ 8,919,000	$ 10,664,000
Other current assets	6,020,000	4,300,000
Total current assets	521,393,000	91,214,000
Other non-current assets	1,374,000	835,000
Total assets	1,540,928,000	952,039,000
Current liabilities:
Current portion of long-term debt	0	3,370,553,000
Interest payable	0	42,657,000
Accrued and other current liabilities	53,348,000	72,428,000
Total current liabilities	138,208,000	3,651,897,000
Total liabilities not subject to compromise	431,038,000	3,943,976,000
Total shareholders’ deficit	(2,928,151,000)	(2,991,937,000)	211,660,000	(331,490,000)
Total liabilities and shareholders’ equity	1,540,928,000	952,039,000
Parent [Member]
Current Assets:
Cash and cash equivalents	3,009,000	523,000	$ 772,000	$ 629,000
Accounts receivable from related companies	29,939,000	64,542,000
Other current assets	2,100,000	5,150,000
Total current assets	35,048,000	70,215,000
Other non-current assets		24,197,000
Total assets	35,048,000	94,412,000
Current liabilities:
Current portion of long-term debt		1,283,232,000
Interest payable		14,166,000
Accrued and other current liabilities	47,000
Total current liabilities	47,000	1,297,398,000
Advances from unconsolidated affiliates	1,623,414,000	1,788,951,000
Total liabilities not subject to compromise	1,623,461,000	3,086,349,000
Liabilities subject to compromise	1,339,739,000
Total shareholders’ deficit	(2,928,152,000)	(2,991,937,000)
Total liabilities and shareholders’ equity	$ 35,048,000	$ 94,412,000

Supplemental Financial Inform82

Supplemental Financial Information (Parent - Cash Flow Statement) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net cash (used in) operating activities	$ 307,614	$ 515,538	$ 712,584
Investing Activities:
Net cash used in investing activities	(278,900)	(512,757)	(1,600,743)
Financing activities:
Proceeds from issuance of Senior Notes	0	0	850,000
Deferred financing costs	0	6	(13,245)
Repurchased shares/net share settlements	(379)	(2,514)	(9,111)
Net cash provided by (used in) financing activities	368,621	(7,557)	886,414
Increase/(Decrease) in cash during the period	397,335	(4,776)	(1,745)
Cash and cash equivalents, beginning of period	4,143	8,919	10,664
Cash and cash equivalents, end of period	401,478	4,143	8,919
Parent [Member]
Net cash (used in) operating activities	(21,309)	(101,277)	(35,818)
Investing Activities:
Investment in subsidiaries			(850,000)
Dividends received	24,089	96,297	52,741
Net cash used in investing activities	24,089	96,297	(797,259)
Financing activities:
Proceeds from issuance of Senior Notes			850,000
Deferred financing costs		6	(13,245)
Repurchased shares/net share settlements	43		(6,471)
Shares re-issued from treasury	(337)	4,725	2,936
Net cash provided by (used in) financing activities	(294)	4,731	833,220
Increase/(Decrease) in cash during the period	2,486	(249)	143
Cash and cash equivalents, beginning of period	523	772	629
Cash and cash equivalents, end of period	$ 3,009	$ 523	$ 772