Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 15, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | Ultra Petroleum Corp. | ||
Entity Central Index Key | 1,022,646 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 269,948,228 | ||
Entity Common Stock, Shares Outstanding (actual number) | 153,418,041 | ||
Trading Symbol | UPLMQ |
Consolidated Statement of Opera
Consolidated Statement of Operations - USD ($) shares in Thousands, $ 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 | |
Revenues: | |||||||||||
Natural gas sales | $ 609,756 | $ 696,730 | $ 969,850 | ||||||||
Oil sales | 111,335 | 142,381 | 260,170 | ||||||||
Total 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 |
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 and depreciation | 125,121 | 401,200 | 292,951 | ||||||||
Ceiling test and other impairments | 0 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | 0 | 0 | 3,144,899 | 0 |
General and Administrative Expense | 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 Debt | 0 | 0 | (16,662) | (49,903) | 43,494 | 43,137 | 42,619 | 42,668 | (66,565) | (171,918) | (126,157) |
Gain (loss) on commodity derivatives | 0 | 0 | 0 | 0 | 2 | 9,390 | (3,646) | 36,865 | 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 | 0 | (28) | (1,569) | (5,579) | (7,176) | 0 | 0 | ||||
Contract Settlement | (131,106) | 0 | 0 | 0 | (131,106) | 0 | 0 | ||||
Gain on sale of property | 0 | 0 | 8,022 | ||||||||
Other income (expense) net | (3,082) | (2,060) | 2,618 | ||||||||
Total other income (expense), net | (129,113) | 2,096 | (15,820) | (54,539) | (197,376) | (125,215) | (22,562) | ||||
Reorganization items, net | (22,211) | (3,109) | (22,183) | 0 | (47,503) | 0 | 0 | ||||
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 |
Basic Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Basic | $ (0.22) | $ 0.64 | $ 0.09 | $ (0.14) | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 0.37 | $ (20.94) | $ 3.54 |
Fully Diluted Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Diluted | $ (0.22) | $ 0.64 | $ 0.09 | $ (0.14) | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 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 ($) | |
Consolidated Statement of Operations [Abstract] | |
Contractual Interest Expense On Prepetition Liabilities Not Recognized In Statement Of Operations | $ 52.4 |
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 Full Cost Method Of Accounting [Abstract] | ||
Proven | 1,010,466,000 | 851,145,000 |
Property, plant and equipment | 7,695,000 | 8,844,000 |
Deferred income taxes | 0 | 975 |
Deferred financing costs and other | 1,374,000 | 835,000 |
Total assets | 1,540,928,000 | 952,038,975 |
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 maturities of long term debt | 0 | 3,370,553,000 |
Interest Payable Current | 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 |
Liabilities not subject to compromise parent | 431,038,000 | 3,943,976,000 |
Liabilities subject to compromise | 4,038,041,000 | 0 |
Commitments and contingencies | ||
Shareholders' equity: | ||
Common stock - no par value; authorized - unlimited; issued and outstanding - 153,418,041 and 153,255,989, respectively | 510,063,000 | 502,050,000 |
Treasury stock | (49,000) | (176,000) |
Retained earnings | (3,438,165,000) | (3,493,811,000) |
Total shareholders' equity (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 | |
Consolidated Balance Sheets [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 |
Statement of Shareholders Equit
Statement 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 | |
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 earnings (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, Shares | 298,000 | |||
Employee stock plan grants | 700 | $ 700 | ||
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 earnings (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, Shares | 526,000 | |||
Employee stock plan grants | 0 | $ 0 | ||
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 earnings (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 | |||
Employee stock plan grants, Shares | 279,000 |
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 (Loss) Income Attributable to Parent | $ 56,151 | $ (3,207,220) | $ 542,851 |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||
Depletion and depreciation | 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 loss (gain) 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) |
Prepaid expenses and other | (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 | 2,547 | 1,580 | 609 |
Net cash provided by operating activities | 307,614 | 515,538 | 712,584 |
Investing Activities: | |||
Acquisition costs | 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 |
(Decrease)/increase 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 |
Organization Disclosure
Organization Disclosure | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block] | (All amounts in this Report on Form 10-K are expressed in thousands of U.S. dollars (except per share data), unless otherwise noted). 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 reserve s 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] | |
Liquidity and Ability to Continue as a Going Concern [Text Block] | Chapter 11 Proceedings, Ability to Continue as a Going Concern Chap ter 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 pro cedural 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 age nt, 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 p etitions, 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 w ages 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 prep etition 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 counter parties 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, propertie s 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 J une 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 identi fied 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, a nd/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, wh ich 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 fi le 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 lo ng-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 f iling period through June 29, 2017 and the exclusive right to solicit acceptances of a chapter 11 pl an 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 p lan 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 2 1, 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 w ho 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”). P lan 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 Valu e 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 conver sion 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 b y 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 su ch 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 acco rdance 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 sto ck 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, collec tively, 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 aggr egate 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 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 Offerin g 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 Commitmen t 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”) (wh ich 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 a mount 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 capaci ty 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 o f ( 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 mini mum 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, m aintenance 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 ERI SA 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 Su pport 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 termina te 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 th e 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 Facili ties 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, o n 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 Ban kruptcy 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 reorganizat ion we filed on February 8, 2017 (the “Plan”) and to the disclosure statement therefore (the “Disc losure 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 fu ll 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 liabili ties 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 commo n 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 amo unt 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 executo ry 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 liabili ties 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 cl aimed 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 prepetiti on 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 futu re 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 re jection 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 cert ain 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 credito rs 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 b ankruptcy. 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 inv estigated 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 diffe rences 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 w ho 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 c laims 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 r easons. 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 Bankruptc y 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 securi ties 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 i ncurred 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-cas h 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 t hree 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 instru ments 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 amo unt 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 includ ed 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. The Conso lidated Financial Statements do not reflect any adjustments that might result from the outcome of our chapter 11 proceedings. We have significant indebtedness, all of which we have reclassified to liabilities subject to compromise at December 31, 2016 . O ur 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 procee dings, substantial doubt exists that we will be able to continue as a going concern . |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Significant Accounting Policies Disclosures [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: The consolidated financial statements include the accounts of the Company and its w holly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation. ( b) Cash and Cash Equiv alents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. (c) Restricted Cash: Restricted cash primarily represents cash received by the Company from production sold where the final divis ion of ownership of the production is unknown or in dispute. (d) Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s acc ounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. (e) Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. (f) Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securitie s and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activit ies – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly rela ted to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recor ded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capi talized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, cost s 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 val ues 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 rese rves 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 activiti es 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 o f 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 crud e 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 exces s as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods eve n though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation in 201 6 or 201 4 . 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 calcula ted 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: At December 31, 2016 and 2015 , inventory of $4.9 million and $4.3 million, respectively, primarily includes the cost of pipe and production equipment that will be utilized during the 2017 drilling program and crude oil inv entory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general a nd administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market. (h) Deriv ative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and re cords the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7). ( i ) Deferred Financing Costs : During the year ended December 31, 2016, a non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes (as defined below) issued by Ultra Resources, Inc., the unsecured 2018 Se nior Notes (as defined below) issued by the Company and the unsecured 2024 Senior Notes (as defined below) issued by the Company is included in Reorganization items, net in the accompanying Consolidated Statements of Operations as these debt instruments ar e expected to be impacted by the pendency of the Company’s chapter 11 cases. At December 31, 2015, other current assets includes costs associated with the issuance of our revolving credit facility while costs associated with the issuance of our Senior Note s, 2018 Notes and 2024 Notes are presented as a direct deduction from the carrying amount of the related debt liability. (j) Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recog nized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and li abilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is reco gnized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recogni zes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. (k) Earnings (loss) Per Share: Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect. The weighted average shares in the table below do not consider any potential dilutive effects of the proposed plan of re organization discussed in Note 1. The following table provides a reconciliation of components of basic and diluted net net income per common share: December 31, 2016 2015 2014 Net 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) 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net net income per common share - basic $ 0.37 $ (20.94) $ 3.54 Net 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) 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: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (m) Accounting for Share-Based Compensation: The Company measures and r ecognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. (n) Fair Value Ac counting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information. (o) Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liabi lity with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an a djustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timi ng of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the acc ompanying Consolidated Balance Sheets. (p) Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitleme nts method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share is treate d as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its part ners 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 va lue of product imbalances. The Company’s imbalance obligations as of December 31, 2016 and December 31, 2015 were immaterial. (q) Capitalized Interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any. (r) Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. (s) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. (t) Deposits and Retainers: Deposits and retainers primarily consists of payments related to surety bonds. (u) Recent Accounti ng Pronouncements: In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. The ASU also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and r equires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, begin ning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows ( Topic 230) (“ASU No. 2016-15”). The guidance requires that debt prepayment or debt extinguishment costs, including third-party costs, premiums paid, and other fees paid to lenders, be classified as cash outflows for financing activities. For public compani es, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of this ASU to have a material impact on its c onsolidated financial statements. In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU No. 2016-09”) to simplify some of the provisions in stock compensation accounting. The update simplifies the accounting for a stock payment’s tax consequences and amends how excess tax benefits and a business’s payments to cover the tax bills for the shares’ recipients should be classified. T he amendments allow companies to estimate the number of stock awards expected to vest and revises the withholding requirements for classifying stock awards as equity. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-09 on its financial position and results of operations . In February 2016, the FASB issued ASU 2016 -02, Leases (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take e ffect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations . In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (“ASU No. 2015-11”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material impact on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Sub topic 835-30)—Simplifying the Presentation of Debt Issuance Costs. In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced current assets and current maturities of long-term debt by $ 19.4 million on the Company’s Consolidated Balan ce Sheet at December 31, 2015. A non-cash charge to write-off all of the unamortized debt issuance costs is included in Reorganization items, net at December 31, 2016 as the related debt instruments are expected to be impacted by the pendency of the Compan y’s chapter 11 cases . In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. We are currently e valuating 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 (“ASU No. 2014-15”) that requires management to evaluate whethe r there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management is required to provide certa in footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods ending after December 15, 2016 and for interim reporting periods thereafter. The adoption of this ASU did not have a material impact on the Company’s Consolidated Financial Statements . |
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. OIL AND GAS PROPERTIES: December 31, 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 (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 ce iling 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 diffe rentials. |
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 |
Long Term Liabilities
Long Term Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Long Term Liabilities Tables [Abstract] | |
LONG-TERM LIABILITIES | 5 . DEBT AND OTHER LONG-TERM LIABILITIES : December 31, December 31, 2016 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 $ Other long-term obligations: Other long-term obligations 177,088 $ 165,784 Aggregate maturities of debt at December 31, 2016:(2) Beyond 2017 2018 2019 2020 2021 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 indeb tedness , 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 Agr eement 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 accelerati on 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 bo rrower 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 Agreeme nt 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 consolidate d 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 stateme nts 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 expre ssing 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 tr ailing 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 ti mes . 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 Agreemen t (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, s upplemented 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. Oth er 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 Resource s’ 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 ag ainst 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 t railing 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 recogniz ed 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, am ong 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 N otes 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 indebtedn ess, 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 elect ed 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 bef ore 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 obligatio ns 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 failur e 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 in terest 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 oblig ations. |
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 importan ce 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 em ployees, 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 permit s the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based a wards, 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 estima tes 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. Number of Securities Remaining Available Number of for Future Issuance Securities to Weighted Under Equity be Issued Average Compensation Plans Upon Exercise of Exercise Price of (Excluding Securities Outstanding Outstanding Reflected in the Plan Category Options Options First Column) Equity compensation plans approved by (000's) (000's) security holders 346 $60.64 4,339 Equity compensation plans not approved by security holders n/a n/a n/a Total 346 $60.64 4,339 Changes in Stock Options and Stock Options Outstanding The following table summarizes the changes in stock options for the three year period ended December 31, 2016 : Weighted Average Number of Exercise Price Options (US$) (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 Weighted Weighted Average Average Aggregate Number Remaining Exercise Intrinsic Range of Exercise Price Outstanding Contractual Life Price 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 De cember 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 establishe d 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 g ranted 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 compensat ion 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 relat ed 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 , duri ng the first quarter of 201 6 , 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 del ivery of 132,843 net shares of our common stock to eligible par ticipants 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 recei ved 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 re ceived 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. Th e 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 a s 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 derivati ve 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 curr ent 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 Consolidat ed 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 wit hin 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-coun ter 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 i ts 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 Financia l 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, acc ounts 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 reflecti ve 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 ut ilized 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 Estimated Carrying Estimated Amount Fair Value Amount 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 Taxes 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 in come 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 futu re 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, a nd $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 av ailable to offset regular U.S. F ederal income taxes. T hese 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 Compa ny 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 b illion which will be carried forward to offset taxable income generated in future years, and if unut ilized, will expire between 2033 and 203 6 . The Company has Pennsylvania s tate tax net operating loss carry forwards of $1.1 b illion which will expire between 2031 and 203 6 . The Company has Utah state tax net operating loss carry forwards of $80.8 million which will expire between 2033 and 203 6 . 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 Co mpany 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 203 6 . 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 o f 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 1 00 % 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 a n 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 th e 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. Indebtedn ess 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 de bt 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 date s, 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 cl aims. 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 d uring 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”) a lleging 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 millio n. On October 28, 2016, w e 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 tria l 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 cap acity, 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 trans portation 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 contra ct 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 1 2 , 2017, REX and the Company entered into a settlem ent 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 gene ral 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 reasona bleness 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. T he 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 demand ed 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 suc h 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 W est’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 cha pter 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 o il 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 reorganizat ion . Operating Lease During December 2012, the Company sold its sys tem 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 th e 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 r ent 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 operatin g 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. T hese 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 Wit h 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 i n 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 pr ice. 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 a vailability 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 threaten ed litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations. |
Credit Risk
Credit Risk | 12 Months Ended |
Dec. 31, 2016 | |
Credit Risk [Abstract] | |
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 exposu re 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 guarant ee. 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 Com pany’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 reorgani zation 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 Feb ruary 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, consisti ng 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 br idge loans under senior unsecured bridge facilities in an aggregate amount of up to $1.4 billion. A s of January 19, 2017 , the Backstop Approval Order was entered by the Bankruptcy Court and t he 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 enfo rcement 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 H arris 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, 201 7, 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 transporta tion 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 approv al 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 A ugust 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 cl aim. 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 amou nt 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 i mplemented in connection with the plan of reorganization. |
Summarized Quarterly Financial
Summarized Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2016 | |
Summarized 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 e stimation. 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, hi storical 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 en gineering 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 definit ions 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 yea rs 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 Depar tment 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 d ata 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 exte rnal 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 th e 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 rese rves 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 an d 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 Natural Gas NGLs (MBbls) (MMcf) (MBbls) Reserves, December 31, 2013 34,119 3,409,742 - Extensions, discoveries and additions 34,275 866,513 210 Sales - (239,290) - Acquistions 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 - - - Acquistions - - - 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 - - - Acquistions - - - 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 Natural Gas NGLs (MBbls) (MMcf) (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 n ot 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 yea r, 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 contin ue 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 natu ral 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 Compa ny’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 ta x 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 estim ate 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 t hereof 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, December 31, 2016 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 | (a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its w holly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation. |
Cash and cash equivalents | ( b) Cash and Cash Equiv alents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. |
Restricted cash | (c) Restricted Cash: Restricted cash primarily represents cash received by the Company from production sold where the final divis ion of ownership of the production is unknown or in dispute. |
Accounts receivable | (d) Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s acc ounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. |
Property, plant and equipment | (e) Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. |
Oil and natural gas properties | (f) Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securitie s and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activit ies – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly rela ted to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recor ded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capi talized costs and proved reserves of oil and natural gas attributable to a country. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, cost s 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 val ues 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 rese rves 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 activiti es 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 o f 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 crud e 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 exces s as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods eve n though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation in 201 6 or 201 4 . 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 calcula ted 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: At December 31, 2016 and 2015 , inventory of $4.9 million and $4.3 million, respectively, primarily includes the cost of pipe and production equipment that will be utilized during the 2017 drilling program and crude oil inv entory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general a nd administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market. |
Derivative Instruments and hedging activities | (h) Deriv ative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and re cords the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7). |
Deferred financing costs | ( i ) Deferred Financing Costs : During the year ended December 31, 2016, a non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes (as defined below) issued by Ultra Resources, Inc., the unsecured 2018 Se nior Notes (as defined below) issued by the Company and the unsecured 2024 Senior Notes (as defined below) issued by the Company is included in Reorganization items, net in the accompanying Consolidated Statements of Operations as these debt instruments ar e expected to be impacted by the pendency of the Company’s chapter 11 cases. At December 31, 2015, other current assets includes costs associated with the issuance of our revolving credit facility while costs associated with the issuance of our Senior Note s, 2018 Notes and 2024 Notes are presented as a direct deduction from the carrying amount of the related debt liability. |
Income Taxes Policy | (j) Income Taxes: Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recog nized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and li abilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is reco gnized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recogni zes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. |
Earnings per share | (k) Earnings (loss) Per Share: Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect. The weighted average shares in the table below do not consider any potential dilutive effects of the proposed plan of re organization discussed in Note 1. The following table provides a reconciliation of components of basic and diluted net net income per common share: December 31, 2016 2015 2014 Net 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) 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net net income per common share - basic $ 0.37 $ (20.94) $ 3.54 Net 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) 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: Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Accounting for share based compensation | (m) Accounting for Share-Based Compensation: The Company measures and r ecognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. |
Fair value accounting | (n) Fair Value Ac counting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information. |
Asset retirement obligation | (o) Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liabi lity with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an a djustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timi ng of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the acc ompanying Consolidated Balance Sheets. |
Revenue recognition | (p) Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitleme nts method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share is treate d as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its part ners 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 va lue of product imbalances. The Company’s imbalance obligations as of December 31, 2016 and December 31, 2015 were immaterial. |
Capitalized interest | (q) Capitalized Interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any. |
Capital cost accrual | (r) Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. |
Reclassifications | (s) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. |
Deposits and retainers | (t) Deposits and Retainers: Deposits and retainers primarily consists of payments related to surety bonds. |
Recent accounting pronouncements | (u) Recent Accounti ng Pronouncements: In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 2016-18”). The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. The ASU also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and r equires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, begin ning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows ( Topic 230) (“ASU No. 2016-15”). The guidance requires that debt prepayment or debt extinguishment costs, including third-party costs, premiums paid, and other fees paid to lenders, be classified as cash outflows for financing activities. For public compani es, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of this ASU to have a material impact on its c onsolidated financial statements. In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU No. 2016-09”) to simplify some of the provisions in stock compensation accounting. The update simplifies the accounting for a stock payment’s tax consequences and amends how excess tax benefits and a business’s payments to cover the tax bills for the shares’ recipients should be classified. T he amendments allow companies to estimate the number of stock awards expected to vest and revises the withholding requirements for classifying stock awards as equity. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-09 on its financial position and results of operations . In February 2016, the FASB issued ASU 2016 -02, Leases (“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take e ffect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-02 on its financial position and results of operations . In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (“ASU No. 2015-11”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material impact on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Sub topic 835-30)—Simplifying the Presentation of Debt Issuance Costs. In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30)—Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The adoption resulted in a reclassification that reduced current assets and current maturities of long-term debt by $ 19.4 million on the Company’s Consolidated Balan ce Sheet at December 31, 2015. A non-cash charge to write-off all of the unamortized debt issuance costs is included in Reorganization items, net at December 31, 2016 as the related debt instruments are expected to be impacted by the pendency of the Compan y’s chapter 11 cases . In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) and in 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10, Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. We are currently e valuating 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 (“ASU No. 2014-15”) that requires management to evaluate whethe r there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management is required to provide certa in footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods ending after December 15, 2016 and for interim reporting periods thereafter. The adoption of this ASU did not have a material impact on the Company’s Consolidated Financial Statements |
Derivatives and Hedging Activities Policies [Abstract] | |
Derivative Instruments and hedging activities | (h) Deriv ative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and re cords the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7). |
Accounting for share based compensation | (m) Accounting for Share-Based Compensation: The Company measures and r ecognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. |
Oil and Gas Properties Policies [Abstract] | |
Capitalized interest | (q) Capitalized Interest: Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any. |
Fair Value Policies [Abstract] | |
Fair value accounting | (n) Fair Value Ac counting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information. |
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 instru ments 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 amo unt 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 net income per common share: December 31, 2016 2015 2014 Net 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) 1,558 Weighted average common shares outstanding during the period including the effects of dilutive instruments 154,081 153,192 154,694 Net net income per common share - basic $ 0.37 $ (20.94) $ 3.54 Net 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) 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 | 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, 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 (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 ce iling 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 diffe rentials. 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 |
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 |
Long Term Liabilities (Tables)
Long Term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Long Term Liabilities Tables [Abstract] | |
Schedule of Long-term Liabilities | December 31, December 31, 2016 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 $ Other long-term obligations: Other long-term obligations 177,088 $ 165,784 |
Maturity Schedule | Aggregate maturities of debt at December 31, 2016:(2) Beyond 2017 2018 2019 2020 2021 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 indeb tedness , 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 | Number of Securities Remaining Available Number of for Future Issuance Securities to Weighted Under Equity be Issued Average Compensation Plans Upon Exercise of Exercise Price of (Excluding Securities Outstanding Outstanding Reflected in the Plan Category Options Options First Column) Equity compensation plans approved by (000's) (000's) security holders 346 $60.64 4,339 Equity compensation plans not approved by security holders n/a n/a n/a Total 346 $60.64 4,339 |
Changes in Stock Options Outstanding | Weighted Average Number of Exercise Price Options (US$) (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 Weighted Weighted Average Average Aggregate Number Remaining Exercise Intrinsic Range of Exercise Price Outstanding Contractual Life Price 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 | 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 Estimated Carrying Estimated Amount Fair Value Amount 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 Taxes [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) |
Consoldiated 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 | |
Summarized 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 Natural Gas NGLs (MBbls) (MMcf) (MBbls) Reserves, December 31, 2013 34,119 3,409,742 - Extensions, discoveries and additions 34,275 866,513 210 Sales - (239,290) - Acquistions 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 - - - Acquistions - - - 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 - - - Acquistions - - - 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 Natural Gas NGLs (MBbls) (MMcf) (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 | December 31, 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 (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 ce iling 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 diffe rentials. 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, December 31, 2016 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 (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Liabilities Subject To Compromise [Abstract] | |||||||
Accounts Payable | $ 1,322,000 | $ 1,322,000 | |||||
Accrued Liabilities | 6,303,000 | 6,303,000 | |||||
Accrued interest payable | 99,774,000 | 99,774,000 | |||||
Debt | 3,759,000,000 | 3,759,000,000 | |||||
Other Terminated Contracts | 171,642,000 | 171,642,000 | |||||
Liabilities Subject To Compromise | 4,038,041,000 | 4,038,041,000 | $ 0 | ||||
Reorganization Items [Abstract] | |||||||
Professional Fees | 11,781,000 | 0 | $ 0 | ||||
Deferred Financing Costs | 18,742,000 | 0 | 0 | ||||
Contract Settlements | 17,350,000 | ||||||
Other | (370,000) | 0 | 0 | ||||
Reorganization items, net | $ 22,211,000 | $ 3,109,000 | $ 22,183,000 | $ 0 | $ 47,503,000 | $ 0 | $ 0 |
Chapter 11 Proceedings, Abili41
Chapter 11 Proceedings, Ability to Continue as a Going Concern Disclosure (Narratives) (Details) - USD ($) | 2 Months Ended | 12 Months Ended |
Feb. 13, 2017 | Dec. 31, 2016 | |
Chapter 11 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 | 4.25 to 1.0 | |
Revolving Facility Max total net debt to EBITDAX Ratio | 4.0 to 1.0 | |
Revolving Facility Minimum Current Ratio | 1.0 to 1.0 | |
Revolving Facility Minimum Interest Coverage Ratio | 2.5 to 1.0 | |
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% |
Significant Accounting Polici42
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 | |||||||||||
Net earnings (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 - basic | 153,378,000 | 153,192,000 | 153,136,000 | ||||||||
Effect of dilutive instruments | 703,000 | 0 | 1,558,000 | ||||||||
Weighted average common shares outstanding - fully diluted | 154,081,000 | 153,192,000 | 154,694,000 | ||||||||
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 |
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount | 1,437,000 | 1,700,000 | 1,377,000 |
Significant Accounting Polici43
Significant Accounting Policies (Narratives) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Significant Accounting Policies Details [Abstract] | ||
Ceiling test limitation | $ 3,144,899,000 | |
Inventory | 4,269,000 | $ 4,906,000 |
Unamortized debt issuance costs reclassified | $ 19,400,000 |
Asset Retirement Obligation (De
Asset Retirement Obligation (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) |
Asset Retirement Obligation, Revision of Estimate | (436) | 4,357 |
Asset retirement obligations at end of period | 157,173 | 146,210 |
Less: current asset requirement 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 [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $ 10,752,642 | $ 10,480,165 |
Less: Accumulated depletion, depreciation and amortization | (9,742,176) | (9,629,020) |
Proved | $ 1,010,466 | $ 851,145 |
Oil and Gas Properties (Narrati
Oil and Gas Properties (Narratives) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)$ / Mcf | Dec. 31, 2016$ / Mcf | Dec. 31, 2014$ / Mcf | |
Oil And Gas Property [Abstract] | |||
DD&A per Mcfe | $ / Mcf | 1.38 | 0.44 | 1.18 |
Ceiling test limitation | $ | $ 3,144,899 |
Property, Plant & Equipment (De
Property, Plant & Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | $ 20,732 | |
Accumulated Depreciation | (13,037) | |
Property, plant and equipment | 7,695 | $ 8,844 |
Computer equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 2,840 | |
Accumulated Depreciation | (2,237) | |
Property, plant and equipment | 603 | 794 |
Office equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 309 | |
Accumulated Depreciation | (171) | |
Property, plant and equipment | 138 | 196 |
Leasehold improvements [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 486 | |
Accumulated Depreciation | (301) | |
Property, plant and equipment | 185 | 267 |
Land [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 4,637 | |
Accumulated Depreciation | 0 | |
Property, plant and equipment | 4,637 | 4,637 |
Other [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
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 ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Short Term Borrowings [Abstract] | ||
6.125% Senior Notes due 2024 | $ 850,000,000 | $ 850,000,000 |
5.75% Senior Notes due 2018 | 450,000,000 | 450,000,000 |
Senior Notes issued by Ultra Resources Inc | 1,460,000,000 | 1,460,000,000 |
Credit Agreement | 999,000,000 | 630,000,000 |
Current portion of long term debt | 3,759,000,000 | 3,390,000,000 |
Deferred financing costs | 0 | (19,447,000) |
Liabilities Subject To Compromise Debt Only | (3,759,000,000) | 0 |
Total current portion of long term debt not subject to compromise | 0 | 3,370,553,000 |
Other long-term obligations [Abstract] | ||
Other long-term obligations | $ 177,088,000 | $ 165,784,000 |
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) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Apr. 01, 2016USD ($) | Mar. 01, 2016USD ($) | |
Senior Credit Facility Details [Abstract] | |||||
Credit Agreement Consolidated Leverage Covenant | 3.5 to 1.0 | ||||
Credit Agreement Consolidated Leverage Ratio | 4.6 | ||||
Debt Instrument Restrictive Covenants Present Value Ratio | 0.9 | ||||
Restrictive covenants present value Ultra Resources revolving credit facility | 1.5 times | ||||
Ultra Resources Inc Senior Notes | |||||
Senior Notes Ultra Resources Inc | $ 1,460,000,000 | $ 1,460,000,000 | |||
Senior Notes Consolidated Leverage Covenant | 3.5 to 1.0 | ||||
Senior Notes Consolidated Leverage Covenant Ratio | 4.6 | ||||
Ultra Petroleum Corp Senior Notes | |||||
Senior Notes Ultra Petroleum Corp Due 2024 | $ 850,000,000 | 850,000,000 | |||
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate | 6.125% | ||||
Senior Notes Ultra Petroleum Corp Due 2018 | $ 450,000,000 | $ 450,000,000 | |||
Senior Notes Ultra Petroleum Corp Due 2018 Interest Rate | 5.75% | ||||
Maturities Abstract | |||||
Interest payment due Senior Notes Ultra Resources Inc | $ 40,000,000 | ||||
Principal payment due Senior Notes Ultra Resources Inc | $ 62,000,000 | ||||
Interest payment due Senior Notes Ultra PetroleumCorp Due 2024 | $ 26,000,000 |
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 fixed costs | 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 | $ 2,216 | $ 1,645 | $ 2,285 |
Share Based Compensation (Det52
Share Based Compensation (Details 1) | Dec. 31, 2016USD ($)shares |
Share Based Compensation Details [Abstract] | |
Number of Securities to be Issued Upon Exercise of Outstanding Options | 346,000 |
Weighted Averaged Exercise Price of Outstanding Options | $ | 60.64 |
Number Of Securities Remaining Available For Future Issuance Under Equity Compenstation 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 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
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 | $ 51.6 |
Exercise Price, Upper Range Limit | $ 98.87 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
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 (Det55
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 | $ 24.4 |
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 volatility of peer companies | 46.50% |
Average correlation coefficient of peer companies | 0.454 |
Risk-free interest rate | 1.02% |
Long Term Incentive 2014 Plan [Member] | |
Total Shareholder Retun [Line Items] | |
Volatility of common stock | 39.00% |
Risk-free interest rate | 0.66% |
Share Based Compensation (Narra
Share Based Compensation (Narratives) (Details) | 12 Months Ended | ||
Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Share Based Compensation Details [Abstract] | |||
Companys Closing Stock Price Last Day Of Year | 7.23 | ||
Number Of In The Money Options Exercisable | shares | 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 2014 Program | 9,500,000 | ||
Long Term Incentive Program Total 2015 Program | 10,300,000 | ||
Long Term Incentive Program Total 2013 Program | $ 3,800,000 | ||
Long Term Incentive Program Total 2013 Program Shares | shares | 132,843 |
Derivative Financial Instrume58
Derivative Financial Instruments (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 | |
Commodity Derivatives [Abstract] | |||||||||||
Realized (loss) gain on commodity derivatives - natural gas | $ 0 | $ 146,801 | $ (48,170) | ||||||||
Realized (loss) gain on commodity derivatives - crude oil | 0 | 0 | 506 | ||||||||
Unrealized loss (gain) on commodity derivatives | 0 | (104,190) | 130,066 | ||||||||
Gain loss on commodity derivatives | $ 0 | $ 0 | $ 0 | $ 0 | $ 2 | $ 9,390 | $ (3,646) | $ 36,865 | $ 0 | $ 42,611 | $ 82,402 |
Derivative Financial Instrume59
Derivative Financial Instruments (Narratives) (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Commodity Derivatives Authorization [Abstract] | |
Commodity Derivatives Board Authorization | 50.00% |
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] | ||
Debt carrying value | $ 3,759,000 | $ 3,390,000 |
Estimated Fair Value | 3,984,699 | 2,220,100 |
Notes Due 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 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] | ||
Debt carrying value | $ 175,000 | 175,000 |
Estimated Fair Value | $ 193,665 | 115,911 |
Debt Instruments Interst Rates | 4.91% | |
Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 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 expense (benefit) | (655) | (3,414) | (6,819) | ||||||||
Deferred: | |||||||||||
Foreign - deferred | 1 | (990) | 995 | ||||||||
Total deferred tax expense (benefit) | 1 | (990) | 995 | ||||||||
Total income tax (benefit) | $ (349) | $ 45 | $ (160) | $ (190) | $ (999) | $ (1,133) | $ (250) | $ (2,022) | $ (654) | $ (4,404) | $ (5,824) |
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 provision net of federal benefit | (2,335) | (12,998) | 8,023 | ||||||||
Change in valuation allowance - earnings | (31,083) | 1,147,619 | (199,038) | ||||||||
Tax Effect Of Rate Change | 0 | 12,898 | 15,457 | ||||||||
Foreign tax 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 on sale | 40,867 | 44,593 |
U.S. federal tax credit carryforwards | 15,967 | 16,144 |
U. S. net operating loss carryforwards | 428,212 | 319,673 |
US state net operating loss carryforward | 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 | 0 | 1,424 |
Liabilities Subject To Compromise - Interest | 35,498 | 0 |
Liabilities Subject To Compromise - Interest Non US | 14,146 | 0 |
Net tax liabilities | 49,644 | 1,424 |
Net non-current tax liability | $ 0 | $ 1 |
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 |
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 ($) | Dec. 31, 2014USD ($) | |
Commitements And Contingencies Disclosure [Abstract] | |||
Commitment capacity per day of natural gas | MMBTU | 200 | ||
Increased commitment capacity per day of natural gas | MMBTU | 50 | ||
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. | ||
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 | ||
Committment 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 | ||
Ultra Resources Senior Noteholders Minimum Make-Whole Claim | $ 200,725,869 |
Credit Risk (Details)
Credit Risk (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule Of Significant Customers [Line Items] | |
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 Bank Loan 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 | |
Committment 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] | |||||||||||
Revenues from continuing operations | $ 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 | 0 | 0 | 0 | 0 | 2 | 9,390 | (3,646) | 36,865 | 0 | 42,611 | 82,402 |
Expenses from continuing operations | 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 | 0 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | 0 | 0 | 3,144,899 | 0 |
Interest Expense Debt | 0 | 0 | (16,662) | (49,903) | 43,494 | 43,137 | 42,619 | 42,668 | (66,565) | (171,918) | (126,157) |
Restructuring expenses | 0 | (28) | (1,569) | (5,579) | (7,176) | 0 | 0 | ||||
Contract Settlement | (131,106) | 0 | 0 | 0 | (131,106) | 0 | 0 | ||||
Gain on sale of property | 0 | 0 | 8,022 | ||||||||
Other (expense) income, net | 1,993 | 2,124 | 2,411 | 943 | 903 | 2,354 | 1,827 | (992) | 7,471 | 4,092 | |
Total other income (expense), net | (129,113) | 2,096 | (15,820) | (54,539) | (197,376) | (125,215) | (22,562) | ||||
Reorganization items, net | (22,211) | (3,109) | (22,183) | 0 | (47,503) | 0 | 0 | ||||
Income (loss) from continuing operations | (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 |
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) (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 72
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 73
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 74
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) - USD ($) | 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 | $ 1,865,649,000 | $ 5,233,483,000 | $ 3,187,969,000 |
Net revisions of previous quantity estimates | (9,623,000) | (2,126,998,000) | (603,795,000) |
Extensions, discoveries and other changes | 209,603,000 | 15,254,000 | 1,787,643,000 |
Sales of reserves in place | 0 | 0 | (398,506,000) |
Acquistion of reserves | 0 | 0 | 2,552,491,000 |
Changes in future development costs | 11,556,000 | 1,618,068,000 | (1,013,652,000) |
Sales of oil and gas, net of production costs | (454,725,000) | (550,879,000) | (949,389,000) |
Net change in prices and production costs | (72,939,000) | (6,996,416,000) | 1,010,052,000 |
Development costs incurred during the period that reduce future development costs | 22,523,000 | 548,112,000 | 342,987,000 |
Accretion of discount | 186,565,000 | 709,736,000 | 413,177,000 |
Net changes in production rates and other | (67,663,000) | 1,551,413,000 | (175,419,000) |
Net change in income taxes | 0 | 1,863,876,000 | (920,075,000) |
Aggregrate changes | (174,703,000) | (3,367,834,000) | 2,045,514,000 |
Standardized Measure, ending | $ 1,690,946,000 | $ 1,865,649,000 | $ 5,233,483,000 |
Disclosure About Oil and Gas 75
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 76
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 expense | (125,121) | (401,200) | (292,951) |
Write-downs of proved oil and gas properties | 0 | (3,144,899) | 0 |
Income taxes | 83,112 | (9,841) | 3,736 |
Total | $ 412,716 | $ (3,005,060) | $ 660,174 |
Disclosure About Oil and Gas 77
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Proven Properties [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $ 10,752,642 | $ 10,480,165 |
Less: Accumulated depletion, depreciation and amortization | (9,742,176) | (9,629,020) |
Proved | $ 1,010,466 | $ 851,145 |
Disclosure About Oil and Gas 78
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 | ||
Reserves Prepared Internally | 2.00% | ||
Expert Qualfications | 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 Textuals [Abstract] | |||
Weighted Average Sales Price For Proved Reserves Natural Gas | $ 2.07 | $ 4.32 | $ 2.21 |
Weighted Average Sales Price For Proved Reserves Condensate | 37.9 | $ 80.62 | 42.36 |
Weighted Average Sales Price For Proved Reserves Natural Gas Liquids | $ 19.17 | $ 20.61 |
Supplemental Financial Informat
Supplemental Financial Information (Parent - Statement of Operations) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ 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 | |
Revenues: | |||||||||||
Natural gas sales | $ 609,756 | $ 696,730 | $ 969,850 | ||||||||
Oil sales | 111,335 | 142,381 | 260,170 | ||||||||
Total 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 |
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 and depreciation | 125,121 | 401,200 | 292,951 | ||||||||
Ceiling test and other impairments | 0 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | 0 | 0 | 3,144,899 | 0 |
General and Administrative Expense | 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 Debt | 0 | 0 | (16,662) | (49,903) | 43,494 | 43,137 | 42,619 | 42,668 | (66,565) | (171,918) | (126,157) |
Gain (loss) on commodity derivatives | 0 | 0 | 0 | 0 | 2 | 9,390 | (3,646) | 36,865 | 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 | ||||||||
Gain on sale of property | 0 | 0 | 8,022 | ||||||||
Other income (expense) net | (3,082) | (2,060) | 2,618 | ||||||||
Total other income (expense), net | (129,113) | 2,096 | (15,820) | (54,539) | (197,376) | (125,215) | (22,562) | ||||
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 |
Basic Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Basic | $ (0.22) | $ 0.64 | $ 0.09 | $ (0.14) | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 0.37 | $ (20.94) | $ 3.54 |
Fully Diluted Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Diluted | $ (0.22) | $ 0.64 | $ 0.09 | $ (0.14) | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 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 | ||||||||
Parent [Member] | |||||||||||
Expenses: | |||||||||||
General and Administrative Expense | $ 650 | $ 308 | $ 261 | ||||||||
Other income (expense), net: | |||||||||||
Interest Expense Debt | (26,590) | (81,069) | (42,996) | ||||||||
Income from unconsolidated affiliates | 157,450 | (3,152,078) | 558,634 | ||||||||
Guarantee fee income | 6,073 | 23,029 | 23,045 | ||||||||
Other income (expense) net | (64,888) | (1,684) | (1,324) | ||||||||
Reorganization items parent, net | (15,827) | 0 | 0 | ||||||||
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 | $ 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 |
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 | ||
Deferred financing costs | 0 | 19,447,000 | ||
Other current assets | 6,020,000 | 4,300,000 | ||
Total current assets | 521,393,000 | 91,214,000 | ||
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||||
Proven | 1,010,466,000 | 851,145,000 | ||
Property, plant and equipment | 7,695,000 | 8,844,000 | ||
Deferred income taxes | 0 | 975 | ||
Other non-current assets | 1,374,000 | 835,000 | ||
Total assets | 1,540,928,000 | 952,038,975 | ||
Current liabilities: | ||||
Accounts payable | 28,171,000 | 93,415,000 | ||
Accrued and other current liabilities | 53,348,000 | 72,428,000 | ||
Production taxes payable | 44,329,000 | 52,273,000 | ||
Current maturities of long term debt | 0 | 3,370,553,000 | ||
Interest Payable Current | 0 | 42,657,000 | ||
Capital cost accrual | 12,360,000 | 20,571,000 | ||
Total current liabilities | 138,208,000 | 3,651,897,000 | ||
Liabilities not subject to compromise parent | 431,038,000 | 3,943,976,000 | ||
Deferred gain on sale of liquids gathering system | 115,742,000 | 126,295,000 | ||
Other long-term obligations | 177,088,000 | 165,784,000 | ||
Commitments and contingencies | ||||
Shareholders' equity: | ||||
Common stock - no par value; authorized - unlimited; issued and outstanding - 153,418,041 and 153,255,989, respectively | 510,063,000 | 502,050,000 | ||
Treasury stock | (49,000) | (176,000) | ||
Retained earnings | (3,438,165,000) | (3,493,811,000) | ||
Total shareholders' equity (deficit) | (2,928,151,000) | (2,991,937,000) | 211,660,000 | (331,490,000) |
Liabilities and Stockholders' 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 | ||
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||||
Other non-current assets | 0 | 24,197,000 | ||
Total assets | 35,048,000 | 94,412,000 | ||
Current liabilities: | ||||
Accrued and other current liabilities | 47,000 | 0 | ||
Current maturities of long term debt | 0 | 1,283,232,000 | ||
Interest Payable Current | 0 | 14,166,000 | ||
Total current liabilities | 47,000 | 1,297,398,000 | ||
Advances to unconsolidated affiliates | 1,623,414,000 | 1,788,951,000 | ||
Liabilities not subject to compromise parent | 1,623,461,000 | 3,086,349,000 | ||
Liabilities subject to compromise parent | 1,339,739,000 | 0 | ||
Shareholders' equity: | ||||
Total shareholders' equity (deficit) | (2,928,152,000) | (2,991,937,000) | ||
Liabilities and Stockholders' Equity | $ 35,048,000 | $ 94,412,000 |
Supplemental Financial Inform82
Supplemental Financial Information (Parent - Cash Flow Statement) (Details 3) - USD ($) | 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 | |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||||||||||
Depletion and depreciation | $ 125,121,000 | $ 401,200,000 | $ 292,951,000 | ||||||||
Ceiling test and other impairments | $ 0 | $ 0 | $ 0 | $ 0 | $ 3,144,899,000 | $ 0 | $ 0 | $ 0 | 0 | 3,144,899,000 | 0 |
Deferred and current non-cash income taxes | 1,000 | (990,000) | 995,000 | ||||||||
Unrealized loss (gain) on commodity derivatives | 0 | 104,190,000 | (130,066,000) | ||||||||
Deferred gain on sale of liquids gathering system | (10,553,000) | (10,553,000) | (10,553,000) | ||||||||
(Gain) on sale of property | 0 | 0 | (8,022,000) | ||||||||
Stock compensation | 5,562,000 | 4,128,000 | 5,467,000 | ||||||||
Other | 6,870,000 | 9,217,000 | 4,569,000 | ||||||||
Net changes in operating assets and liabilities: | |||||||||||
Restricted cash | (3,456,000) | 2,000 | 2,000 | ||||||||
Accounts receivable | (19,635,000) | 65,132,000 | (43,116,000) | ||||||||
Prepaid expenses and other | (15,647,000) | (20,106,000) | (1,920,000) | ||||||||
Other non-current assets | (539,000) | 21,112,000 | 284,000 | ||||||||
Accounts payable | (63,924,000) | 13,815,000 | 28,696,000 | ||||||||
Accrued liabilities | 133,144,000 | 1,655,000 | (5,938,000) | ||||||||
Production taxes payable | (7,944,000) | (3,312,000) | 15,115,000 | ||||||||
Interest payable | 57,117,000 | (3,441,000) | 14,233,000 | ||||||||
Other long-term obligations | 276,000 | (5,770,000) | 6,427,000 | ||||||||
Current taxes payable | 2,547,000 | 1,580,000 | 609,000 | ||||||||
Net cash provided by operating activities | 307,614,000 | 515,538,000 | 712,584,000 | ||||||||
Investing Activities: | |||||||||||
Acquisition costs | 0 | 3,964,000 | (891,075,000) | ||||||||
Oil and gas property expenditures | (269,314,000) | (494,025,000) | (599,913,000) | ||||||||
Gathering system expenditures | 0 | 0 | (6,842,000) | ||||||||
Proceeds from sale of property | 0 | 0 | 27,944,000 | ||||||||
Change in capital cost accrual | (8,134,000) | (25,380,000) | (125,577,000) | ||||||||
Inventory | (1,123,000) | 3,235,000 | 175,000 | ||||||||
Purchase of property, plant and equipment | (329,000) | (551,000) | (5,455,000) | ||||||||
Net cash used in investing activities | (278,900,000) | (512,757,000) | (1,600,743,000) | ||||||||
Financing activities: | |||||||||||
Borrowings on long-term debt | 369,000,000 | 1,165,000,000 | 1,095,000,000 | ||||||||
Payments on long-term debt | 0 | (1,153,000,000) | (1,037,000,000) | ||||||||
Proceeds from issuance of Senior Notes | 0 | 0 | 850,000,000 | ||||||||
Deferred financing costs | 0 | 6,000 | (13,245,000) | ||||||||
Repurchased shares/net share settlements | (379,000) | (2,514,000) | (9,111,000) | ||||||||
Payment of contingent consideration | 0 | (17,049,000) | 0 | ||||||||
Proceeds from exercise of options | 0 | 0 | 770,000 | ||||||||
Net cash provided by (used in) financing activities | 368,621,000 | (7,557,000) | 886,414,000 | ||||||||
(Decrease)/increase in cash during the period | 397,335,000 | (4,776,000) | (1,745,000) | ||||||||
Cash and cash equivalents, beginning of period | 4,143,000 | 8,919,000 | 4,143,000 | 8,919,000 | 10,664,000 | ||||||
Cash and cash equivalents, end of period | 401,478,000 | 4,143,000 | 401,478,000 | 4,143,000 | 8,919,000 | ||||||
Cash paid for: | |||||||||||
Interest | 4,793,000 | 169,867,000 | 108,889,000 | ||||||||
Income taxes | 94,000 | 0 | 1,752,000 | ||||||||
Non Cash Investing Activities Oil And Gas Properties | 0 | 0 | 20,000,000 | ||||||||
Parent [Member] | |||||||||||
Net changes in operating assets and liabilities: | |||||||||||
Net cash provided by operating activities | (21,309,000) | (101,277,000) | (35,818,000) | ||||||||
Investing Activities: | |||||||||||
Investment in subsidiary | 0 | 0 | (850,000,000) | ||||||||
Dividends received | 24,089,000 | 96,297,000 | 52,741,000 | ||||||||
Net cash used in investing activities | 24,089,000 | 96,297,000 | (797,259,000) | ||||||||
Financing activities: | |||||||||||
Proceeds from issuance of Senior Notes | 0 | 0 | 850,000,000 | ||||||||
Deferred financing costs | 0 | 6,000 | (13,245,000) | ||||||||
Repurchased shares/net share settlements | 43,000 | 0 | (6,471,000) | ||||||||
Shares re-issued from treasury | (337,000) | 4,725,000 | 2,936,000 | ||||||||
Net cash provided by (used in) financing activities | (294,000) | 4,731,000 | 833,220,000 | ||||||||
(Decrease)/increase in cash during the period | 2,486,000 | (249,000) | 143,000 | ||||||||
Cash and cash equivalents, beginning of period | $ 523,000 | $ 772,000 | 523,000 | 772,000 | 629,000 | ||||||
Cash and cash equivalents, end of period | $ 3,009,000 | $ 523,000 | $ 3,009,000 | $ 523,000 | $ 772,000 |