Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 09, 2016 | Jun. 30, 2015 | |
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, 2015 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 1,918,659,990 | ||
Entity Common Stock, Shares Outstanding (actual number) | 153,255,989 | ||
Trading Symbol | UPL |
Consolidated Statement of Opera
Consolidated Statement of Operations - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||||||||
Natural gas sales | $ 696,730 | $ 969,850 | $ 824,266 | ||||||||
Oil sales | 142,381 | 260,170 | 109,138 | ||||||||
Total operating revenues | $ 189,301 | $ 222,503 | $ 207,998 | $ 219,309 | $ 319,050 | $ 288,608 | $ 296,063 | $ 326,299 | 839,111 | 1,230,020 | 933,404 |
Expenses: | |||||||||||
Lease operating expenses | 106,906 | 96,496 | 68,106 | ||||||||
Liquids gathering system operating lease expense | 20,647 | 20,306 | 20,000 | ||||||||
Production taxes | 72,774 | 103,898 | 72,398 | ||||||||
Gathering fees | 87,904 | 59,931 | 52,074 | ||||||||
Transportation charges | 83,803 | 77,780 | 82,797 | ||||||||
Depletion and depreciation | 401,200 | 292,951 | 243,390 | ||||||||
Ceiling test and other impairments | 3,144,899 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | ||||
General and Administrative Expense | 7,387 | 19,069 | 22,373 | ||||||||
Total operating expenses | 3,925,520 | 670,431 | 561,138 | ||||||||
Operating income (loss) | (3,086,409) | 559,589 | 372,266 | ||||||||
Other income (expense), net: | |||||||||||
Interest expense | (43,494) | (43,137) | (42,619) | (42,668) | (42,196) | (29,599) | (27,294) | (27,068) | (171,918) | (126,157) | (101,486) |
Gain (loss) on commodity derivatives | 2 | 9,390 | (3,646) | 36,865 | 110,725 | 32,052 | (15,102) | (45,273) | 42,611 | 82,402 | (46,754) |
Deferred gain on sale of liquids gathering system | 10,553 | 10,553 | 10,553 | ||||||||
Litigation expense | (4,401) | 0 | 0 | ||||||||
Gain on sale of property | 8,022 | 0 | 0 | 0 | 0 | 8,022 | 0 | ||||
Other income (expense) net | (2,060) | 2,618 | (357) | ||||||||
Total other income (expense), net | (125,215) | (22,562) | (138,044) | ||||||||
Income (loss) before income tax (benefit) | (3,205,639) | (4,229) | (24,923) | 23,167 | 205,829 | 123,974 | 105,505 | 101,719 | (3,211,624) | 537,027 | 234,222 |
Income tax (benefit) | (999) | (1,133) | (250) | (2,022) | (3,901) | (1,383) | (544) | 4 | (4,404) | (5,824) | (3,616) |
Net income (loss) | $ (3,204,640) | $ (3,096) | $ (24,673) | $ 25,189 | $ 209,730 | $ 125,357 | $ 106,049 | $ 101,715 | $ (3,207,220) | $ 542,851 | $ 237,838 |
Basic Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Basic | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.37 | $ 0.82 | $ 0.69 | $ 0.66 | $ (20.94) | $ 3.54 | $ 1.55 |
Fully Diluted Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Diluted | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.36 | $ 0.81 | $ 0.68 | $ 0.66 | $ (20.94) | $ 3.51 | $ 1.54 |
Weighted average common shares outstanding - basic | 153,192,000 | 153,136,000 | 152,963,000 | ||||||||
Weighted average common shares outstanding - fully diluted | 153,192,000 | 154,694,000 | 154,426,000 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current assets: | ||||
Cash and cash equivalents | $ 4,143 | $ 8,919 | $ 10,664 | $ 12,921 |
Restricted cash | 115 | 117 | ||
Oil and gas revenue receivable | 61,881 | 111,915 | ||
Joint interest billing and other receivables | 11,356 | 32,502 | ||
Derivative assets | 0 | 104,190 | ||
Income tax receivable | 5,150 | 6,246 | ||
Inventory | 4,269 | 10,216 | ||
Deferred financing costs | 20,477 | 0 | ||
Other current assets | 3,270 | 3,033 | ||
Total current assets | 110,661 | 277,138 | ||
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||||
Proven | 851,145 | 3,636,643 | ||
Unproven properties not being amortized | 0 | 242,294 | ||
Property, plant and equipment | 8,844 | 12,186 | ||
Deferred income taxes | 1 | 30,640 | ||
Deferred financing costs and other | 835 | 26,789 | ||
Total assets | 971,486 | 4,225,690 | ||
Current liabilities: | ||||
Accounts payable | 93,415 | 77,580 | ||
Accrued liabilities | 72,428 | 89,865 | ||
Production taxes payable | 52,273 | 55,585 | ||
Current maturities of long term debt | 3,390,000 | 100,000 | ||
Interest Payable Current | 42,657 | 46,098 | ||
Current deferred tax liabilities | 0 | 30,638 | ||
Derivative liabilities | 0 | 0 | ||
Capital cost accrual | 20,571 | 45,952 | ||
Total current liabilities | 3,671,344 | 445,718 | ||
Long-term debt | 0 | 3,278,000 | ||
Deferred income tax liability | 0 | 992 | ||
Deferred gain on sale of liquids gathering system | 126,295 | 136,848 | ||
Other long-term obligations | $ 165,784 | $ 152,472 | ||
Commitments and contingencies | ||||
Shareholders' equity: | ||||
Common stock - no par value; authorized - unlimited; issued and outstanding - 153,255,989 and 152,896,315, respectively | $ 502,050 | $ 495,913 | ||
Treasury stock | (176) | (6,213) | ||
Retained earnings | (3,493,811) | (278,040) | ||
Total shareholders' equity (deficit) | (2,991,937) | 211,660 | $ (331,490) | $ (577,867) |
Total liabilities and shareholders' equity | $ 971,486 | $ 4,225,690 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Consolidated Balance Sheets [Abstract] | ||
Common stock, no par value | $ 0 | $ 0 |
Common stock, shares authorized | unlimited | unlimited |
Common stock, shares issued | 153,255,989 | 152,896,315 |
Common stock, shares outstanding | 153,255,989 | 152,896,315 |
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, 2012 | $ (577,867) | $ 474,016 | $ (1,051,870) | $ (13) |
Beginning Balance, Shares at Dec. 31, 2012 | 152,930,000 | |||
Stock options exercised | 11 | $ 11 | ||
Stock options exercised, Shares | 1,000 | |||
Employee stock plan grants | 700 | $ 700 | 0 | |
Shares re-issued from treasury | 0 | $ (711) | (652) | 1,363 |
Shares repurchased | (3,311) | (3,311) | ||
Shares repurchased, Shares | (165,000) | |||
Net share settlements | (2,118) | (2,118) | ||
Net share settlements, Shares | (122,000) | |||
Fair value of employee stock plan grants | 13,257 | $ 13,257 | ||
Tax benefit of stock options exercised | 0 | 0 | ||
Comprehensive earnings: | ||||
Net earnings (loss) | 237,838 | 237,838 | ||
Ending Balance at Dec. 31, 2013 | (331,490) | $ 487,273 | (816,802) | (1,961) |
Ending Balance, Shares at Dec. 31, 2013 | 152,991,000 | |||
Employee stock plan grants, Shares | 347,000 | |||
Stock options exercised | 770 | $ 770 | ||
Stock options exercised, Shares | 43,000 | |||
Employee stock plan grants | 700 | $ 700 | ||
Shares re-issued from treasury | 0 | $ (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 | |||
Stock options exercised | 0 | $ 0 | ||
Stock options exercised, Shares | 0 | |||
Employee stock plan grants | 700 | $ 700 | ||
Shares re-issued from treasury | 0 | $ 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 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating activities: | |||
Net (Loss) Income Attributable to Parent | $ (3,207,220) | $ 542,851 | $ 237,838 |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||
Depletion and depreciation | 401,200 | 292,951 | 243,390 |
Ceiling test and other impairments | 3,144,899 | 0 | 0 |
Deferred and current non-cash income taxes | (990) | 995 | (6) |
Unrealized loss (gain) on commodity derivatives | 104,190 | (130,066) | 25,876 |
Deferred gain on sale of liquids gathering system | (10,553) | (10,553) | (10,553) |
(Gain) on sale of property | 0 | (8,022) | 0 |
Excess tax benefit from stock based compensation | 0 | 0 | 0 |
Stock compensation | 4,128 | 5,467 | 9,767 |
Other | 9,217 | 4,569 | 2,252 |
Net changes in operating assets and liabilities: | |||
Restricted cash | 2 | 2 | 2 |
Accounts receivable | 65,132 | (43,116) | 16,565 |
Prepaid expenses and other | (20,106) | (1,920) | 1,180 |
Other non-current assets | 21,112 | 284 | 277 |
Accounts payable | 13,815 | 28,696 | (1,400) |
Accrued liabilities | 1,655 | (5,938) | (32,904) |
Production taxes payable | (3,312) | 15,115 | (7,207) |
Interest payable | (3,441) | 14,233 | 1,772 |
Other long-term obligations | (5,770) | 6,427 | 3,296 |
Current taxes payable | 1,580 | 609 | (17,507) |
Net cash provided by operating activities | 515,538 | 712,584 | 472,638 |
Investing Activities: | |||
Acquisition costs | 3,964 | (891,075) | (649,801) |
Oil and gas property expenditures | (494,025) | (599,913) | (370,662) |
Gathering system expenditures | 0 | (6,842) | (5,510) |
Proceeds from sale of property | 0 | 27,944 | 0 |
Proceeds from sale of liquids gathering system | 0 | 0 | (129) |
Proceeds from sale of marketable securities | 0 | 0 | 0 |
Change in capital cost accrual | (25,380) | (125,577) | (65,975) |
Inventory | 3,235 | 175 | (627) |
Purchase of property, plant and equipment | (551) | (5,455) | (815) |
Net cash used in investing activities | (512,757) | (1,600,743) | (1,093,519) |
Financing activities: | |||
Borrowings on long-term debt | 1,165,000 | 1,095,000 | 1,006,000 |
Payments on long-term debt | (1,153,000) | (1,037,000) | (823,000) |
Proceeds from issuance of Senior Notes | 0 | 850,000 | 450,000 |
Deferred financing costs | 6 | (13,245) | (8,958) |
Repurchased shares/net share settlements | (2,514) | (9,111) | (5,429) |
Shares re-issued from treasury | 0 | 0 | 0 |
Excess tax benefit from stock based compensation | 0 | 0 | 0 |
Payment of contingent consideration | (17,049) | 0 | 0 |
Proceeds from exercise of options | 0 | 770 | 11 |
Net cash provided by (used in) financing activities | (7,557) | 886,414 | 618,624 |
(Decrease)/increase in cash during the period | (4,776) | (1,745) | (2,257) |
Cash and cash equivalents, beginning of period | 8,919 | 10,664 | 12,921 |
Cash and cash equivalents, end of period | 4,143 | 8,919 | 10,664 |
Cash paid for: | |||
Interest | 169,867 | 108,889 | 99,542 |
Income taxes | 0 | 1,752 | 13,843 |
Non Cash Investing Activities Oil And Gas Properties | $ 0 | $ 20,000 | $ 12,651 |
Organization Disclosure
Organization Disclosure | 12 Months Ended |
Dec. 31, 2015 | |
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). Ultra Petroleum Corp. (the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil and natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are in the Green River Basin of southwest Wyoming, the north-central Pennsy lvania area of the Appalachian Basin and in the Uinta Basin in northeast Utah. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies Disclosures [Abstract] | |
SIGNIFICANT ACCOUNTING POLICIES | 1. SIGNIFICANT ACCOUNTING POLICIES: Liquidity and Ability to Continue as a Going Concern Our accompanying consolidated financial statements have been prepared assuming th at 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. C ontinued low oil and natural gas prices during 2015 have had a significant adverse impact on our business , and as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern. As of February 29, 2016 , the total outstand ing principal amount of our debt obligations was $3.76 billion, consisting of the following: $450 .0 million of unsecured senior notes due 2018 issued by us ( the “2018 Notes”) ; $850 .0 million of unsecured senior notes due 2024 issued by us (the “2024 Notes”); $999.0 million under the credit agreement between our wholly-owned subsidiary, Ultra Resources, Inc. ("Ultra Resources"), as the borrower, and JPMorgan Chase Bank, as the administrative agent (the "Credit Agreement") - Ultra Resources' obligations under the Credit Agreement are guaranteed by the Company and UP Energy Corporation; and $1.46 billion in unsecured senior notes (the "Senior Notes") issued by Ultra Resources - Ultra Resources' obligations under the Senior Notes are guaranteed by the Comp any and UP Energy Corporation. W e recently borrowed $266.0 million under the Credit Agreement, which represented substantially all of the remaining undrawn amount under the Credit Agreement. As a result, no material further extensions of credit are available under the Credit Agreement. As of February 29, 2016 , the Company's cash on hand exceeds the amount recently borrowed under the Credit Agreement. These funds are intended to be used for general corporate purposes . Our ability to continue as a “going c oncern” is dependent on many factors, including, among other things, our ability to comply with the covenants in our existing debt agreements, our ability to cure any defaults that occur under our debt agreements or to obtain waivers or forbearances with r espect to any such defaults, and our ability to pay, retire, amend, replace or refinance our indebtedness as defaults occur or as interest and principal payments come due. Covenant Compliance. Our Credit Agreement contains covenants, including: a consolidated leverage covenant pursuant to which Ultra Resources must maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0 ; 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 to 1.0 ; and a covenant requiring us to deliver annual, audited, consolidated financial statements of the Company with out a “going concern” or like qualification or exception. The Master Note Purchase Agreement governing our Senior Notes contains a consolidated leverage ratio covenant similar to the consolidated leverage ratio covenant in the Credit Agreement. The indentu res governing our 2018 Notes and our 2024 Notes contain an interest charge coverage ratio pursuant to which we are required to maintain a minimum ratio of our trailing four fiscal quarters’ consolidated EBITDA to total interest expense of no less than 2.25 to 1.00 as a precondition to our incurring additional indebtedness. Based on our EBITDAX for the trailing four fiscal quarters ended December 31, 2015, we were in compliance with the consolidated leverage ratio covenant in the Credit Agreement and the M aster Note Purchase Agreement at December 31, 2015. However, based on our estimates of forward commodity prices and our most recent production forecasts, we expect to breach the consolidated leverage covenant for the trailing four fiscal quarters ended Mar ch 31, 2016. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. Based on the net present value of Ultra Resources’ oil and gas properties and Ultra Resources’ t otal funded consolidated debt at December 31, 2015, we expect to breach the PV-9 ratio in the Credit Agreement when we report whether or not we are in compliance with the covenant on April 1, 2016. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. The audit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” As a result, we expect to be in default under the Credit Agreement on March 15, 2016 when we deliver our financial statements to the Credit Agreement lenders. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. Based on our EBITDA for the trailing four fiscal quarters ended December 31, 2015, we were in compliance with the interest charge coverage ratio in the indentures governing our 2018 Notes and our 2024 Not es at December 31, 2015. However, if commodity prices stay at or decline from recent levels or if we fail to develop new properties and operate our existing properties profitably or if our interest expense increases due to changes in the agreements governi ng our indebtedness or due to breaches of the covenants in the agreements governing our indebtedness, we may not be able to continue to comply with this covenant during the next twelve months. If we breach this covenant, our ability to incur additional ind ebtedness will be limited, or we may not be able to incur additional indebtedness at all. We cannot provide any assurances that we will be able to comply with the covenants or to make satisfactory alternative arrangements in the event we cannot do so. I f we are unable to cure any such default, or obtain a forbearance, a waiver or replacement financing, and those lenders, or other parties entitled to do so, accelerate the payment of such indebtedness or obligations, we may consider or pursue various forms of negotiated restructurings of our debt obligations and/or asset sales under court supervision pursuant to a voluntary bankruptcy filing under Chapter 11 of the U.S. Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act, which would have a materi al adverse effect on our business, financial condition, results of operations and cash flows. Under certain circumstances, it is also possible that our creditors may file an involuntary peti tion for bankruptcy against us. Maturities. At December 31, 201 5, we have the following obligations outstanding under the Credit Agreement, the 2018 Notes, the 2024 Notes, and the Senior Notes (maturity dates exclude the effect of the default provisions described above) : $630.0 million due October 2016 under the Cred it Agreement; $450.0 million due December 2018 with respect to the 2018 Notes; $850.0 million due September 2024 with respect to the 2024 Notes; and $1.46 billion due between March 2016 and October 2025 with respect to the Senior Notes (see Note 8 for maturity details) . In addition, we anticipate the following significant near-term interest and maturity payments: ( i ) an approximately $40 million interest payment on March 1, 2016 under the Senior Notes; (ii) a $62 million maturity payment on March 1, 2016 under one series of the Senior Notes; and (iii) an approximately $26 million interest payment on April 1, 2016 under the 2024 Notes. We are currently attempting to ( i ) amend, replace, refinance or restructure our Credit Agreement and Master Note Purc hase Agreement and the indentures related to our 2018 Notes and our 2024 Notes; and/or (ii) secure additional capital through possible asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps or any combin ation of these. We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating and financing needs. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans. O ur ability to continue as a going concern is dependent on many factors, including, among other things, our ability to comply with the covenants in our existing debt agreements and amend or replace our debt agreements as they mature. We cannot provide any assurances that we will be able to comply with the covenants or to make satisfactory alternative arrangements in the event we cannot do so. (a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accou nts of the Company and its wholly 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 consolidati on. (b) Cash and cash equivalents: 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 represents cash received by the Company from productio n sold where the final division 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 accounts receivable approximates fair value because of the short-term nature of the instru ments. 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 use ful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction, the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $ 91.8 million w as transferre d to proven oil and gas properties at September 30, 2014 . (f) Oil and natural gas properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Relea se 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 Activities – 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 related to exploration and development a ctivities 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 recorded based on the fair value of the a sset 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 capitalized 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 na tural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Comp any reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluat ed utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk we ighting factors. The amount of any impairment is transferred to the capitalized costs being amortized . Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10 %, plus the lower of cost or market value of unproved properties, less any associated ta x effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depleti on, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. During 2015, the Company recorded a $3.1 bill ion 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. Th e ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market d ifferentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2014 or 2013. (g) Inventories: At December 31, 2015 and 2014 , inventory of $4.3 million and $10.2 million, respectively, primarily includ es the cost of pipe and production equipment that will be utilized during the 2016 drilling program and crude oil inventory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly a nd indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and 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) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Compan y records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7). ( i ) Deferred financing costs: Included in current assets at December 31, 2015 are costs associated with th e issuance of our senior notes, revolving credit facility, 2018 Notes and 2024 Notes. The remaining unamortized issuance costs are being amortized over the life of the applicable debt or facility using the straight line method. (j) Income taxes: Income t axes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized 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 liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to b e recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more l ikely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the po sition following an audit. The Company has recorded a valuation allowance against certain deferred tax assets of $1.3 billion as of December 31, 2015 . Some or all of this valuation allowance may be reversed in future periods against future in come. (k) Earnings (loss) per share: Basic earnings (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted income (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 following table provides a reconciliation of components of basic and diluted net (loss) income per common share: December 31, 2015 2014 2013 Net (loss) income $ (3,207,220) $ 542,851 $ 237,838 Weighted average common shares outstanding during the period 153,192 153,136 152,963 Effect of dilutive instruments - (1) 1,558 1,463 Weighted average common shares outstanding during the period including the effects of dilutive instruments 153,192 154,694 154,426 Net (loss) income per common share - basic $ (20.94) $ 3.54 $ 1.55 Net (loss) income per common share - fully diluted $ (20.94) $ 3.51 $ 1.54 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) 1,377 1,406 ( 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 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 recognizes compensation expense for all share-based p ayment 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 accounting: The Company follows FASB ASC Topic 820, F air 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 liability with an associated increase in oil and gas prop erties 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 adjustment is recorded to both the asset retirement o bligation 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 timing of settling asset retirement obligations. As a f ull 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 accompanying 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 and under multi-year contracts that provide for a fixed price of oil and natural gas. 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 natura l gas sales using the “entitlements 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 of the volumes is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2015 and 2014 , the Company had a net natural gas imbalance liability of $1.3 million and $3.0 million , respectively . Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or , in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allow s for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. (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, as well as on w ork in p rocess relating to gathering systems that are not currently in service . ( 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 recl assified to conform to the current period financial statement presentation . (t) Recent accounting pronouncements: In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU No. 2016-0 2”). 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 also will require disclosures designed to giv e financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, a nd interim periods within those fiscal years, beginning after Dec. 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 November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU No. 2015-17”). The guidance eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent a mounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15 , 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period and may be applied either prospectively or retrospectively to all periods presented. T he Company has elected early adoption of ASU No. 2015-17 and has applied these changes prospectively. The adoption of this guidance has no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent affec ts presentation of our financial position. See Note 9 for additional information. 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 am endments 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 statement s. In April 2015, the FASB issued an amendment to U.S. GAAP to simplify the balance sheet presentation of the costs for issuing debt. The changes were adopted in ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Present ation of Debt Issuance Costs (“ASU No. 2015-3”) . Public companies will have to apply the amendments for reporting periods that start after December 15, 2015. The amendment requires adoption by revising the balance sheets for periods prior to the effective date, which makes it easier for investors to evaluate a company’s financial performance. The amendment to FASB ASC 835-30-45, Interest—Imputation of Interest, formerly Accounting Principles Board Opinion No. 21, means that the costs for issuing debt will a ppear on the balance sheet as a direct deduction of debt. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In June 2015, the FASB issued a delay by one year of the revenue recognition standard adopted in June 2014. In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers , and sup erseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition , and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. The new proposal related to ASU No. 2014-09 delays the application of the standard to reporting periods beginning after December 15, 2017 instead of December 15, 2016. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations . In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Conc ern (“ASU No. 2014-15”) that requires management to evaluate whether 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 a n interim and annual basis. Management is required to provide certain 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 beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
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, constructio n, 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, 2015 2014 Asset retirement obligations at beginning of period $ 127,240 $ 72,807 Accretion expense 9,122 6,571 Liabilities incurred 7,352 10,242 Liabilities acquired(1) - 53,270 Liabilities divested(1) - (15,760) Liabilities settled (1,861) (336) Revisions of estimated liabilities 4,357 446 Asset retirement obligations at end of period 146,210 127,240 Less: current asset retirement obligations (305) (417) Long-term asset retirement obligations $ 145,905 $ 126,823 (1 ) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment. |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Properties And Equipment Tables [Abstract] | |
OIL AND GAS PROPERTIES | 3. OIL AND GAS PROPERTIES: December 31, December 31, 2015 2014 Proven Properties : Acquisition, equipment, exploration, drilling and environmental costs (1) $ 10,480,165 $ 9,731,407 Less: Accumulated depletion, depreciation and amortization (2) (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Propertie s: Acquisition and exploration costs not being amortized (3), (4) - 242,294 Net capitalized costs - oil and gas properties $ 851,145 $ 3,878,937 On a unit basis, DD&A from continuing operations was $1.38 , $1.18 and $1.05 per Mcfe for the years ended December 31, 2015 , 2014 and 2013 , respectively. ( 1 ) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment . ( 2 ) 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 t he accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural g as and West Texas Intermediate oil, adjusted for market differentials. (3 ) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on w ork i n p rocess rel ating to g athering systems that are not currently in service . For the years ended December 31, 2015 and 2014 , total interest on outstanding debt was $185.0 million and $146.6 million, respectively, of which $13.1 mil lion and $20.4 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and w ork i n p rocess relating to g athering systems that are not currently in service . ( 4 ) At December 31, 2015, all costs related to un evaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool. Unproven Properties At December 31, 2015, all costs related to unevaluated properties that were previously excluded from capitalized costs being amortized have been impaired or not considered significant and transferred to the capitalized costs being amortized in the full cost pool. Based on the quarterly evaluation o f unproved leasehold costs, management determined th at assumptions of future oil and gas production, commodity prices, operating and development costs indicate that the recorded carrying value of the unevaluated pr operties may not be recoverable. Total 2015 2014 2013 Prior Acquisition costs $ - $ (228,516) $ (191,184) $ 419,700 $ - Exploration costs - 7,708 173 (7,881) - Capitalized interest - (21,486) 20,232 1,254 - Unproven properties $ - $ (242,294) $ (170,779) $ 413,073 $ - |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property Plant And Equipment Disclosure [Abstract] | |
PROPERTY, PLANT AND EQUIPMENT | 4. PROPERTY, PLANT AND EQUIPMENT: December 31, 2015 2014 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,797 (2,003) 794 917 Office equipment 520 (324) 196 57 Leasehold improvements 486 (219) 267 111 Land 4,637 - 4,637 5,778 Other 12,540 (9,590) 2,950 5,323 Property, plant and equipment, net $ 20,980 $ (12,136) $ 8,844 $ 12,186 |
Long Term Liabilities
Long Term Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
Long Term Liabilities Tables [Abstract] | |
LONG-TERM LIABILITIES | 5 . DEBT AND OTHER LONG-TERM LIABILITIES : December 31, December 31, 2015 2014 Short-term debt: Senior Notes $ 2,760,000 $ 100,000 Bank indebtedness 630,000 - Long-term debt and other long-term liabilities: Bank indebtedness - 518,000 Senior notes - 2,760,000 Other long-term obligations 165,784 152,472 $ 3,555,784 $ 3,530,472 Aggregate maturities of debt at December 31, 2015:(1) Beyond 2016 2017 2018 2019 2020 5 years Total $ 3,390,000 $ - $ - $ - $ - $ - $ 3,390,000 (1) Continued low oil and natural gas prices during 2015 have had a significant adverse impact on our business , and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern . As a result, we have reclassified all of our total outstanding debt as short-term. Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to comply with the covenants in our existing debt agr eements and amend or replace our debt agreements as they mature. Please refer to Not e 1 for further discussion . A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements may result in r educed borrowing capacity or an event of a default, causing our debt obligations under such financing agreements (and any other indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. Ultra Resources, Inc. – Bank indebtedness. The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the consent of lenders who are willing to increase their loa n commitments, provides for the issuance of letters of credit of up to $ 250.0 million in aggregate, and matures in October 2016. With the majority (over 50 %) lender consent, the term of the consenting lenders’ commitments may be extended for up to two succ essive one-year periods at the Borrower’s request. At December 31, 2015 , the Company had $630.0 million in outstanding borrowings and $370.0 million of available borrowing capacity under the Credit Agreement. Loans under the Credit Agreem ent are unsecured and bear 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 Ultra R esources, Inc.’s consolidated leverage ratio ( 150 basis points as of December 31, 2015 ) 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 ( 250 basis points per annum as of December 31, 2015 ). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio. For the year ended December 31, 2015 , the Company incurred $1.7 million in commitment fees associated with its credit facility. The Credit Agreement is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Ultra Petroleum Corp. and UP Energy Corporation are holding companies that own no operating ass ets and have no significant operations independent of its subsidiary, Ultra Resources, Inc. The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive coven ants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as Ultra Resources, Inc.’s debt rating is below investment grade, the maintenance of an annual ratio of the net present va lue of Ultra Resources, Inc.’s oil and gas properties to total funded debt of no less than one and one half times to one. At December 31, 2015 , the Company was in compliance with all of its debt covenants under the Credit Agreement except as described b elow in Covenants and Events of Default. Senior Notes. U ltra Resources also has outstanding $1.46 billion in principal amount of Senior Notes. Ultra Resources’ Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Ultra Petroleum Corp. and UP Energy Corporation are holding companies that own no operating assets and have no significant o perations independent of its subsidiary, Ultra Resources, Inc. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole premium and are subject to representations, warranties, covenants and events of default s imilar to those in the Credit Facility. At December 31, 2015 , the Company was in compliance with all of its debt covenants under the Senior Notes. Ultra Petroleum Corp. – Senior Notes due 2024: On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by Ul tra Resources, Inc. The 2024 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after October 1, 2019, the Company may redeem all or, f rom time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 – 103.063%; 2020 – 102.042%; 2021 – 101.021%; and 2022 and thereafter – 100.000%). The 2024 Notes are subject to cov enants 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. In addition, the 2024 Notes contain ev ents of default customary for a senior note financing. At December 31, 2015 , the Company was in compliance with all of its debt covenants under the 2024 Notes. Senior Notes due 2018: On December 12, 2013, the Company issued $450.0 million of 5.75% Se nior 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 Ultra Resources, Inc. The 2018 Notes are not guaranteed by the Compa ny’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following pric es expressed as a percentage of principal amount of the 2018 Notes: (2015 – 102.875%; 2016 – 101.438%; and 2017 and thereafter – 100.000%). The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributi ons and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2018 Notes contain events of default customary for a senior note financing. At December 31, 2015 , t he Company was in compliance with all of its debt covenants under the 2018 Notes. Maturities At December 31, 2015, we have the following obligations outstanding under the Credit Agreement, the 2018 Notes, the 2024 Notes, and the Senior Notes (maturity d ates exclude the effect of the default provisions described in Note 1): $630.0 million due October 2016 under the Credit Agreement; $450.0 million due December 2018 with respect to the 2018 Notes; $850.0 million due September 2024 with respect to the 2 024 Notes; and $1.46 billion due between March 2016 and October 2025 (see Note 8 for maturity details) . In addition, we anticipate the following significant near-term interest and maturity payments: ( i ) an approximately $40 million interest payment on March 1, 2016 under the Senior Notes; (ii) a $62 million maturity payment on March 1, 2016 under one series of the Senior Notes; and (iii) an approximately $26 million interest payment on April 1, 2016 under the 2024 Notes. We are currently attempting to ( i ) amend, replace, refinance or restructure our Credit Agreement and Master Note Purchase Agreement and the indentures related to our 2018 Notes and our 2024 Notes; and/or (ii) secure additional capital through possible asse t sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps or any combination of these . We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating and financing needs. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans. Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to comply with the coven ants in our existing debt agreements and amend or replace our debt agreements as they mature. We cannot provide any assurances that we will be able to comply with the covenants or to make satisfactory alternative arrangements in the event we cannot do so. Please refer to Not e 1 for further discussion. Covenants and Events of Default Our Credit Agreement contains covenants, including: a consolidated leverage covenant pursuant to which Ultra Resources must maintain a maximum ratio of its total funded co nsolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0; 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 con solidated debt of 1.5 to 1.0; and a covenant requiring us to deliver annual, audited, consolidated financial statements of the Company without a “going concern” or like qualification or exception. The Master Note Purchase Agreement governing our Senior Not es contains a consolidated leverage ratio covenant similar to the consolidated leverage ratio covenant in the Credit Agreement. The indentures governing our 2018 Notes and our 2024 Notes contain an interest charge coverage ratio pursuant to which we are re quired to maintain a minimum ratio of our trailing four fiscal quarters’ consolidated EBITDA to total interest expense of no less than 2.25 to 1.00 as a precondition to our incurring additional indebtedness. Based on our EBITDAX for the trailing four fis cal quarters ended December 31, 2015, we were in compliance with the consolidated leverage ratio covenant in the Credit Agreement and the Master Note Purchase Agreement at December 31, 2015. However, based on our estimates of forward commodity prices and o ur most recent production forecasts, we expect to breach the consolidated leverage covenant for the trailing four fiscal quarters ended March 31, 2016. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. Based on the net present value of Ultra Resources’ oil and gas properties and Ultra Resources’ total funded consolidated debt at December 31, 2015, we expect to breach the PV-9 ratio in the Credit Agreement when w e report whether or not we are in compliance with the covenant on April 1, 2016. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. The audit report prepared by our auditors with r espect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” As a result, we expect to be in default under the Credit Agreement on March 15, 2016 when we d eliver our financial statements to the Credit Agreement lenders. A violation of this covenant can become an event of default under our debt agreements and result in the acceleration of all of our indebtedness. Based on our EBITDA for the trailing four fiscal quarters ended D ecember 31, 2015, we were in compliance with the interest charge coverage ratio in the indentures governing our 2018 Notes and our 2024 Notes at December 31, 2015. However, if commodity prices stay at or decline from recent levels or if we fail to develop new properties and operate our existing properties profitably or if our interest expense increases due to changes in the agreements governing our indebtedness or due to breaches of the covenants in the agreements governing our indebtedness, we may not be a ble to continue to comply with this covenant during the next twelve months. If we breach this covenant, our ability to incur additional indebtedness will be limited, or we may not be able to incur additional indebtedness at all. A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements may result in reduced borrowing capacity or an event of a default, causing our debt obligations under such financing agreements (and any other indebted ness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. If we are unable to cure any such default, or obtain a forbearance, a waiver or repl acement financing, and those lenders, or other parties entitled to do so, accelerate the payment of such indebtedness or obligations, we may consider or pursue various forms of negotiated restructurings of our debt obligations and/or asset sales under cour t supervision pursuant to a voluntary bankruptcy filing under Chapter 11 of the U.S. Bankruptcy Code, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. Under certain circumstances, it is also possible that our creditors may file an involuntary petition for bankruptcy against us. Other long-term obligations: These costs primarily relate to the long-term portion of production taxes payable and our asset retirement obligations. |
Share Based Compensation
Share Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
SHARE BASED COMPENSATION | 6. SHARE BASED COMPENSATION: The Company sponsors two share based compensation plans: the 2005 Stock Incentive Plan (the “2005 Plan”) and the 2015 Stock Incentive Plan (“2015 Plan”; and together with the 2005 Plan, the “Plans”). The Plans are 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 2005 Plan was adopted by the Company’s Board of Directors on January 1, 2005 and approved by the Company’s shareholders on April 29, 2005. The 2015 Plan was adopted by the Compan y’s Board of Directors on March 31, 2014 and approved by our shareholders on May 20, 2014. The purpose of the Plans is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and reta ining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, en abling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the Plans permit the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other s tock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restriction s and estimates forfeitures that may occur. The Committee may grant awards under the 2005 Plan until December 31, 2014, unless terminated sooner by the Board of Directors, and under the 2015 Plan until December 31, 2024. Valuation and Expense Information Year Ended December 31, 2015 2014 2013 Total cost of share-based payment plans $ 6,137 $ 8,640 $ 13,957 Amounts capitalized in oil and gas properties and equipment $ 2,009 $ 3,173 $ 4,190 Amounts charged against income, before income tax benefit $ 4,128 $ 5,467 $ 9,767 Amount of related income tax benefit recognized in income before valuation allowances $ 1,645 $ 2,285 $ 4,083 Securities Authorized for Issuance Under Equity Compensation Plans As of December 31, 2015 , 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 519 $58.98 4,555 Equity compensation plans not approved by security holders n/a n/a n/a Total 519 $58.98 4,555 Changes in Stock Options and Stock Options Outstanding The following table summarizes the changes in stock options for the three year period ended December 31, 2015 : Weighted Average Number of Exercise Price Options (US$) (000's) Balance, December 31, 2012 1,357 $16.97 to $98.87 Forfeited (110) $25.68 to $75.18 Exercised (1) $16.97 to $16.97 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 The following table summarizes information about the stock options outstanding and exercisable at December 31, 2015: 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) $ 50.15 - $ 63.05 103 0.60 $55.37 $- $ 49.05 - $ 62.23 268 1.29 $53.96 $- $ 51.60 - $ 98.87 148 2.45 $70.61 $- The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $2.50 per share on December 31, 2015 , 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, 2015 . The following table summarizes information about the weighted-average grant-date fair value of share options: 2015 2014 2013 Options forfeited during the year $ 28.00 $ 24.40 $ 25.44 As of December 31, 2011, all options were fully vested; therefore, no options vested during the years ended December 31, 2015 , 2014 or 2013 . There were no stock options exercised during the years ended December 31, 2015 and 2014 . The intrinsic value of stock options exercised during 2013 was immaterial . At December 31, 2015 , there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 3 1, 2011. PERFORMANCE SHARE PLANS: Long Term Incentive Plans. For at least each of the last three years, the Company has 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 established since 2013, the Committee establishes time-based and performance-based measures at the beginning of each three-year performance period. For all LTIPs established prio r to 2013, the Committee established performance-based measures at the beginning of each three-year performance period, but did not establish time-based measures. In addition, for all LTIPs established prior to 2013, the Committee approved payment of award s in shares of our common stock. For the LTIP awards in 2015, 2014 and 2013, the 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 awards. Market-Based Measure ( Total Shareholder Return) : LTIP awards g ranted to officers during 2015 , 2014 and 2013 , include 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 2013 LTIP Volatility of common stock 40.1% 39.0% 39.2% Average volatility of peer companies 46.5% n/a n/a Average correlation coefficient of peer companies 0.454 n/a n/a Risk-free interest rate 1.02% 0.66% 0.40% Stock-Based Compensation Cost : For the year ended December 31, 2015 , the Company recognized $2.9 million in pre-tax compensation expense related to the 2013 , 2014 and 2015 LTIP awards. For the year ended December 31, 2014 , the Company recognized $6.3 million in pre-tax compensation expense related to the 2012 , 2013 and 2014 LTIP awards. For the year ended December 31, 2013 , the Company recognized $6.9 million in pre-tax compensation expense relat ed to the 2011 , 2012 and 2013 LTIP awards. The amounts recognized during the year ended December 31, 2015 assumes that performance objectives between less than threshold and up to maximum are attained for the 2013 LTIP, 2014 LTIP and 2015 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2015 , for each of the three-year performance periods is expected to be approximately $8.0 million, $9.5 million, and $10.3 million related to the 2013 , 2014 and 2015 LTIP awards of restricted stock units, respectively. Based on the Company’s achievement relative to the 2012 LTIP ’s performance-based measures, during the first quarter of 2015, the Compensation Committee approved payment of the 2012 LTIP in shares of the Company’s stock. The payout of the 2012 LTIP was during the first quarter of 2015 and totaled $9.2 million (resulting in delivery of 232,626 net shares of our common stock to eligible participants in the 2012 LTIP). Based on the Company’s achievement relative to the 2013 LTIP’s performance-based measures, and based on the continued employment with the Company by those participants who received a payment in connection with the 2013 LTIP relative to the 2013 LTIP’s time-based measures, during the first quarter of 2016 the Compensation Committee approved payment of the 2013 LTIP. This was the first payment of an LTIP since our LTIPs were modified in 2013 to include time-based and performance-based measures. As such, the Compensation Committee elected to pay the time-based portion of the LTIP awards in cash at the award value and the performance-based portion of the LT IP awards in shares of our common stock . |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 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, 2015 , 2014 and 2013 : For the Year Ended December 31, Commodity Derivatives : 2015 2014 2013 Realized gain (loss) on commodity derivatives-natural gas (1) $ 146,801 $ (48,170) $ (20,552) Realized gain (loss) on commodity derivatives-crude oil (1) - 506 (326) Unrealized gain (loss) on commodity derivatives (1) (104,190) 130,066 (25,876) Total gain (loss) on commodity derivatives $ 42,611 $ 82,402 $ (46,754) (1) Included in gain (loss) on commodity derivatives in the Consolidated Statements of Operations. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value 5.45% Notes due March 2015, issued 2008 $ - $ - $ 100,000 $ 101,931 7.31% Notes due March 2016, issued 2009 62,000 63,604 62,000 65,027 4.98% Notes due January 2017, issued 2010 116,000 113,420 116,000 116,240 5.92% Notes due March 2018, issued 2008 200,000 191,985 200,000 203,738 5.75% Notes due December 2018, issued 2013 450,000 111,451 450,000 414,505 7.77% Notes due March 2019, issued 2009 173,000 174,488 173,000 187,105 5.50% Notes due January 2020, issued 2010 207,000 185,052 207,000 201,371 4.51% Notes due October 2020, issued 2010 315,000 258,520 315,000 283,335 5.60% Notes due January 2022, issued 2010 87,000 73,034 87,000 82,581 4.66% Notes due October 2022, issued 2010 35,000 25,558 35,000 30,476 6.125% Notes due October 2024, issued 2014 850,000 206,321 850,000 754,485 5.85% Notes due January 2025, issued 2010 90,000 70,756 90,000 83,876 4.91% Notes due October 2025, issued 2010 175,000 115,911 175,000 147,649 Credit Facility due October 2016 630,000 630,000 518,000 518,000 $ 3,390,000 $ 2,220,100 $ 3,378,000 $ 3,190,319 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes Disclosure [Abstract] | |
INCOME TAXES | 9. INCOME TAXES (Loss) income before income tax benefit is as follows: Year Ended December 31, 2015 2014 2013 United States $ (3,249,590) $ 505,689 $ 210,580 Foreign 37,966 31,338 23,642 Total $ (3,211,624) $ 537,027 $ 234,222 The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2015 2014 2013 Current tax: U.S. federal, state and local $ - $ (110) $ (8,491) Foreign (3,414) (6,709) 4,881 Total current tax (benefit) (3,414) (6,819) (3,610) Deferred tax: Foreign (990) 995 (6) Total deferred tax (benefit) expense (990) 995 (6) Total income tax (benefit) $ (4,404) $ (5,824) $ (3,616) 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, 2015 2014 2013 Income tax (benefit) provision computed at the U.S. statutory rate $ (1,124,069) $ 187,959 $ 81,978 State income tax (benefit) provision net of federal benefit (12,998) 8,023 1,329 Valuation allowance 1,147,619 (199,038) (81,923) Tax effect of rate change 12,898 15,457 (2,871) Foreign rate differential (26,740) (16,314) (3,508) Other, net (1,114) (1,911) 1,379 Total income tax (benefit) $ (4,404) $ (5,824) $ (3,616) 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, 2015 2014 Deferred tax assets - current : Incentive compensation/other, net - 6,150 - 6,150 Net deferred tax assets - current $ - $ 6,150 Deferred tax liabilities - current : Derivative instruments, net $ - $ 36,788 Net deferred tax liabilities - current $ - $ 36,788 Net deferred tax liability - current $ - $ 30,638 Deferred tax assets - non-current : Property and equipment 776,504 - Deferred gain 44,593 48,319 U.S. federal tax credit carryforwards 16,144 16,144 U.S. net operating loss carryforwards 319,673 147,336 U.S. state net operating loss carryforwards 61,919 53,654 Non-U.S. net operating loss carryforwards 9,142 - Asset retirement obligations 51,815 45,039 Incentive compensation/other, net 28,711 19,142 1,308,501 329,634 Valuation allowance (1,307,076) (161,480) Net deferred tax assets - non-current $ 1,425 $ 168,154 Deferred tax liabilities - non-current : Property and equipment - 137,514 Other - non-US 1,424 - Net non-current tax liabilities $ 1,424 $ 137,514 Net non-current tax asset $ 1 $ 30,640 Deferred tax liabilities - non-current : Other - non-US - 992 As further described in Note 1, the Company adopted ASU 2015-17 on a prospective basis in 2015. As a result, the deferred tax assets and liabilities are classified as long-term in the Consolidated Balance Sheets as of December 31, 2015. 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 g eneration of future taxable income during the periods in which the temporary differences become deductible. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable inco me, and available tax planning strategies. At December 31, 2015 and 2014 , the Company recorded a valuation allowance against certain deferred tax assets of $1.3 billion and $161.5 million, respectively. Some or all of this valuation all owance may be reversed in future periods against future income. The Company’s valuation allowance changed by $1.1 billion from December 31, 2014 to December 31, 2015 . Of this amount, $1.1 billion reduced the Company’s current year deferred tax benefit, and -$1.9 million was reflected through shareholders’ equity. As of December 31, 2015 , the Company had approximately $14.1 million of U.S. federal alternative minimum tax (AMT) credits av ailable to offset regular U.S. F ederal income taxes. These AMT credits do not expire and can be carried forward indefinitely. The Company has $0.5 million of general business credits available to offset U.S. federal income taxes. These general business credits expire in 2032. In addition, the Company has $1.6 million of foreign tax credit carryforwards, none of which expire prior to 2017. The Company generated a U.S. federal tax loss of $494.8 million and $213.0 million for the years ended Decemb er 31, 2015 and 2014 , respectively. The total U.S. federal tax net operating loss of $913.4 million will be carried forward to offset taxable income generated in future years, and if unutilized, will expire between 2033 and 2035. The Company ha s Pennsylvania s tate tax net operating loss carry forwards of $920.7 million which will expire between 2031 and 2035. The Company has Utah state tax net operating loss carry forwards of $65.6 million which will expire between 2033 and 2 035. The Company has immaterial state tax net operating loss carry forwards in other jurisdictions, none of which expire prior to 2020. Without regard to the recorded valuation allowance, if the Company experiences or has experienced an ownership change as determined by 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 generated a Canada Federal and Provincial tax loss of $61.3 million and $23.8 million for the years ended December 31, 2015 and 2014 , respectively. To the extent possible, these losses will be carried back to offset taxable income generated in the prior three tax years . An income tax receivable of $5.2 million and $6.2 million has been recorded at December 31, 2015 and 2014 , respectively, and is reflected as a reduction in 2015 and 2014 income tax expense in the Consolidated St atement of Operations. The remaining Canada Federal and Provincial tax loss of $33.9 million will be carried forward to offset taxable income generated in future years and will expire in 2035. The Company did not have any unrecognized tax ben efits 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, 2015 . Estimated interest and penalties relate d 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 C ompany 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 ye ars 2012 through 2015 remain open to examination by the major taxing jurisdictions in which the Company has business activity . The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon . |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2015 | |
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 , $2.0 million and $1.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitements And Contingencies Disclosures [Abstract] | |
COMMITMENTS AND CONTINGENCIES | 11. COMMITMENTS AND CONTINGENCIES: Outstanding debt and interest payments. Continued low oil and natural gas prices during 2015 have had a significant adverse impact on our business , and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern . As a result, we have reclassified our total outstanding debt as short-term. Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to comply with the covenants in our existing debt agreements and amend or replace our debt agreements as they mature. Please refer to Note 1 for further discussion . A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements may result in reduced borr owing capacity or an event of a default, causing our debt obligations under such financing agreements (and any other indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentia lly become immediately due and payable. We cannot provide any assurances that we will be able to comply with the covenants or to make satisfactory alternative arrangements in the event we cannot do so. If satisfactory alternative arrangements are made, t he total interest expense associated with our total outstanding debt is approximately $906.6 million at December 31, 2015 ; ( $168.6 million in 2016 ; $287.6 million in total for 2017 and 2018 ; $184.5 million in total for 2019 and 2020 ; and $265.9 million due beyond five years.) Transportation contract. The Company is an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ul timate terminus in eastern Ohio . The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas through November 2019. During the first quarter of 2009, the Company entered into agreements to secure an additional capacity of 50 MMMBtu pe r day on the REX pipeline system, beginning in January 2012 through December 2018. The Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The Company has the right , but not the obligation, to deliver its natural gas production into the REX pipeline, but has an obligation to pay reservation charges to REX in either event. On February 25, 2016, we received a letter from REX asserting that we were in default of the ob ligations under our transportation agreement for failing to provide adequate assurance of performance and for failing to timely pay invoice for transportation services provided by REX during January 2016. The letter also notified us that, according to REX, unless we remedy the alleged defaults of our obligations before the end of the 30-day notice period provided in the tariff, our transportation agreement will terminate automatically at the end of the notice period. Any termination of our transportation ag reement on REX would not have a material adverse effect on our a bility to market our production. The Company currently projects that demand charges related to the remaining term of the contract will total approximately $368.1 million. Operating l ease . During December 2012, the Company sold its system of pipelines and central gathering facilities (the “Pinedale LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agre ement (the “Pinedale Lease Agreement”) relating to the use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the Pinedale LGS at the sole discretion of the Company. Annual rent for the initial term under the Pinedale Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Pinedale Lease Agreement will total approximately $248.2 million. The audit report we received with respect to our year-end 2015 consolidated financial statements contains an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.” Our Credit Agreement requires us to deliver audited, consolidated financial statements without a “g oing concern” or like qualification or exception. As a result, we will be in default under our Credit Agreement on March 15, 2016 when we deliver our financial statements to the lenders under the Credit Agreement. Our failure to obtain a waiver of this req uirement under the Credit Agreement within the applicable grace period could result in an acceleration of all of our outstanding debt obligations and the potential termination of the Pinedale Lease Agreement. All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classific ation 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 commitmen ts for office leases of $7.8 million at December 31, 2015 ; ( $1.4 million in 2016 ; $1.4 million in 2017 ; $1.3 million in 2018 ; $1.2 million in 2019 ; and $1.0 million in 2020 with the remainder due beyond five years). During the years ended December 31, 2015 , 2014 and 2013 , the Company recognized expense associated with its office leases in the amount of $1.3 million, $1.0 million, and $1.0 million, respectively. Delivery Commitments . With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2016 , the Company has long-term natural gas delivery commitments of 5.1 MMMBtu in 2016 and 13.5 MMMBtu in 2017 under existing agreements. As of February 9, 2016 , the Company has long-term crude oil delivery commitments of 3.4 MMBbls in 2016 , 2.8 MMBbls in 2017 , 1.1 MMBbls in 2018 and 0.2 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 quan tities 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 th ose 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 commitmen ts. Other. 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, management, after consultation with legal cou nsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. |
Credit Risk
Credit Risk | 12 Months Ended |
Dec. 31, 2015 | |
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 and commodity derivative contracts associated with the Company’s hedging program . The Company’s revenues related to natural gas and oil sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and e nd-users in various industries. Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in t hose 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 analys is, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2015 . A significant counter party is defined as one that individually accounts for 10 % or more of the Company’s total revenues during the year. In 2015 , the Company had no single customer that represented 10% or more of its total revenues. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | 13. SUBSEQUENT EVENTS: We recently borrowed $266.0 million under our revolving credit facility, which represented substantially all of the remaining undrawn amount under the revolving credit facility. As a result, no material further extensions of credit are available under our revolving credit facility. As of February 29, 2016 , the Company's cash on hand exceeds the amount recently borrowed under the Credit Agreement. These funds are intended to be used for general corp orate purposes . For more information about the Credit Facility, see Note 5. U nder our Credit Agreement, we are required to deliver audited, consolidated financial statements without a “going concern” or like qualification or explanation. Because the au dit report prepared by our auditors with respect to the financial statements in this Form 10-K includes an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern,” we are in default under our Credit Agreement. We are currently in discussions with the lenders under our Credit Agreement regarding a waiver of this requirement. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement before the expiration of the 30-day grace perio d, there will exist an event of default under the Credit Agreement. If an event of default occurs under our Credit Agreement, the lenders could accelerate the loans outstanding under the Credit Agreement. In addition, if the lenders under our Credit Agree ment accelerate the loans outstanding under the Credit Agreement, we will then also be in default under the Master Note Purchase Agreement and the indentures related to our 2018 Notes and our 2024 Notes. If we default under the Master Note Purchase Agreeme nt, the holders of the Senior Notes could accelerate the Senior Notes. Likewise, if we default under the indentures, the holders of the 2018 Notes or the 2024 Not es could accelerate those notes . |
Summarized Quarterly Financial
Summarized Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Summarized Quarterly Financial Information Disclosure [Abstract] | |
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Revenues from continuing operations $ 219,309 $ 207,998 $ 222,503 $ 189,301 $ 839,111 Gain (loss) on commodity derivatives 36,865 (3,646) 9,390 2 42,611 Expenses from continuing operations 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 (benefit) 23,167 (24,923) (4,229) (3,205,639) (3,211,624) Income tax provision (benefit) (2,022) (250) (1,133) (999) (4,404) Net income (loss) $ 25,189 $ (24,673) $ (3,096) $ (3,204,640) $ (3,207,220) Net income (loss) per common share - basic $ 0.16 $ (0.16) $ (0.02) $ (20.91) $ (20.94) Net income (loss) per common share - fully diluted $ 0.16 $ (0.16) $ (0.02) $ (20.91) $ (20.94) 2014 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Revenues from continuing operations $ 326,299 $ 296,063 $ 288,608 $ 319,050 $ 1,230,020 (Loss) gain on commodity derivatives (45,273) (15,102) 32,052 110,725 82,402 Expenses from continuing operations 154,829 150,850 169,669 195,083 670,431 Interest expense 27,068 27,294 29,599 42,196 126,157 Gain on sale of property - - - 8,022 8,022 Other income (expense), net 2,590 2,688 2,582 5,311 13,171 Income before income tax provision (benefit) 101,719 105,505 123,974 205,829 537,027 Income tax provision (benefit) 4 (544) (1,383) (3,901) (5,824) Net income $ 101,715 $ 106,049 $ 125,357 $ 209,730 $ 542,851 Net income per common share - basic $ 0.66 $ 0.69 $ 0.82 $ 1.37 $ 3.54 Net income per common share - fully diluted $ 0.66 $ 0.68 $ 0.81 $ 1.36 $ 3.51 |
Disclosure About Oil and Gas Pr
Disclosure About Oil and Gas Producing Activities | 12 Months Ended |
Dec. 31, 2015 | |
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 Director – Reservoir Engineering & Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering and is a licensed Profe ssional Engineer with over 14 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. The esti mates of proved reserves and future net revenue as of December 31, 2015 , are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and c ost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geosci ence methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and r egulations, 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 judgmen t. 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 cont inuing 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 s chedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years . The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the res erve estimates for all of the Company’s assets for the year ended December 31, 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 Wyo ming and Pennsylvania in this annual report. Due to the timing of the closing of the acquisition in Utah in December 2013 relative to the timing of preparing annual corporate reserves, the Company’s Reservoir Engineering Department prepared the proved rese rve 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 inte rnal professional staff works closely with our independent engineers, NSAI, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seism ic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of the ir 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 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 prep aring the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. Phillip R. Hodgson. Mr. Barg , a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum enginee ring at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical 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 Uni versity 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 Infor mation 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 guidelin es. Sin ce January 1, 2015 , no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of En ergy. We file Form 23, including reserve and other information, with the EIA. The following unaudited tables as of December 31, 2015 , 2014 , and 2013 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2015 , 2014 and 2013 . 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, 2012 18,137 2,966,445 - Extensions, discoveries and additions 11,329 1,409,528 - Acquistions 10,114 - - Production (1,196) (224,912) - Revisions (4,265) (741,319) - 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 United States Oil Natural Gas NGLs (MBbls) (MMcf) (MBbls) Proved: Developed 10,531 1,820,994 - Undeveloped 7,606 1,145,451 - Total Proved - 2012 18,137 2,966,445 - 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 Changes in proved developed reserves : During 2015 , substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2015 . Changes in proved undeveloped reserves : In 2015 , the Company converted 516.2 Bcfe of proved undeveloped reserves to proved developed reserves, representing an 18% annual conversion rate. At December 31, 2015 , the Company transferred 2.4 Tcfe of proved undevelo ped reserves to unproven categories. Because substantial doubt exists about our ability to continue as a going concern, in determining year-end 2015 reserve amounts, we concluded we lacked the required degree of certainty about our financial capability to fund a development program and the availability of capital that would be required to develop PUD reserves. As a result of our inability to meet the reasonable certainty criteria for recording these PUD reserves as prescribed under the SEC requirements, we did not book any PUD locations in the December 31, 2015 reserve report. Of the 5.0 Tcfe of total proved reserves booked in the reserve report included in our year-end 2011 Form 10-K, we concluded that 106 Bcfe of the proved undeveloped reserves attribut able to locations in Pennsylvania should not have been booked due to uncertainty regarding the future development of those reserves. These reserves were not material and this change to the year-end 2011 reserve report did not have a material impact on our financial statements for year-end 2011 or any subsequent year. NGLs : As part of the SWEPI Transaction, 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. 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 occasiona l changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders. As commodity prices fell during 2015 , we revised our development plan and decreased our development pace. As of February 29, 2016 , we are developing our properties at a substantially slower pace than was anticipated in our December 31, 2014 reserve report. In addition, as a part of our internal controls for determining a plan to develop our proved reserves each year, we consider whether we have the financial capability to dev elop 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, 2015 , we transferred all of our proved undeveloped reserves to unproved status. As of February 29, 2016 , the Company has 3 rigs running in the Pinedale field (2 operated, 1 non-operated) and, subject to available capital, intends to continue drilling and completing wells. We expect to report PUD reserves in future filings if we determine that we have the financial capabilit y 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, 2015 , 2014 and 2013 was $2.21 , $4.32 and $3.51 per Mcf , respectivel y, for natural gas, and $42.36 , $80.62 and $84.97 per barrel, respectively, for oil and condensate. As part of the SWEPI Transaction, 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 . For 2015 and 2014 , the average sales price utilized for purposes of estimating the Company’s proved reserves and future net revenues associated with NGLs was $20.61 and $46.27 per barrel , respectively . The prices utilized i n 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 a nd producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers. As of December 31, 2015 2014 2013 Future cash inflows $ 6,312,095 $ 27,331,391 $ 14,861,131 Future production costs (3,006,265) (8,627,657) (4,540,209) Future development costs (358,848) (3,859,385) (2,014,751) Future income taxes - (3,898,355) (1,897,340) Future net cash flows 2,946,982 10,945,994 6,408,831 Discount at 10% (1,081,333) (5,712,511) (3,220,862) Standardized measure of discounted future net cash flows $ 1,865,649 $ 5,233,483 $ 3,187,969 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, 2015 2014 2013 Standardized measure, beginning $ 5,233,483 $ 3,187,969 $ 1,894,317 Net revisions of previous quantity estimates (2,126,998) (603,795) (1,089,316) Extensions, discoveries and other changes 15,254 1,787,643 2,098,644 Sales of reserves in place - (398,506) - Acquisition of reserves - 2,552,491 86,196 Changes in future development costs 1,618,068 (1,013,652) (252,992) Sales of oil and gas, net of production costs (550,879) (949,389) (720,826) Net change in prices and production costs (6,996,416) 1,010,052 1,204,041 Development costs incurred during the period that reduce future development costs 548,112 342,987 171,149 Accretion of discount 709,736 413,177 226,326 Net changes in production rates and other 1,551,413 (175,419) 145,289 Net change in income taxes 1,863,876 (920,075) (574,859) Aggregate changes (3,367,834) 2,045,514 1,293,652 Standardized measure, ending $ 1,865,649 $ 5,233,483 $ 3,187,969 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, 2015 2014 2013 United States Property Acquisitions: Unproved $ 13,845 $ 26,106 $ 424,540 Proved - 895,179 224,410 Exploration* 18,164 197,664 184,007 Development 461,458 382,984 186,755 Total $ 493,467 $ 1,501,933 $ 1,019,712 * 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, 2015 2014 2013 United States Oil and gas revenue $ 839,111 $ 1,230,020 $ 933,404 Production expenses (288,231) (280,631) (212,578) Depletion and depreciation (401,200) (292,951) (243,390) Ceiling test and other impairments (3,144,899) - - Income tax benefit (expense) (9,841) 3,736 (2,821) Total $ (3,005,060) $ 660,174 $ 474,615 G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2015 2014 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,480,165 $ 9,731,407 Less: accumulated depletion, depreciation and amortization (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Properties: Acquisition and exploration costs not being amortized - 242,294 $ 851,145 $ 3,878,937 |
Supplemental Financial Statemen
Supplemental Financial Statement Information | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 General and administrative expense $ 308 $ 261 $ 102 Other income (expense): Interest expense (81,069) (42,996) (1,438) Income from unconsolidated affiliates (3,152,078) 558,634 223,685 Guarantee fee income 23,029 23,045 22,406 Other expense (1,684) (1,324) (1,836) Income before income taxes (3,212,110) 537,098 242,715 Income tax (benefit) expense (4,890) (5,753) 4,877 Net income $ (3,207,220) $ 542,851 $ 237,838 CONDENSED BALANCE SHEET December 31, December 31, 2015 2014 ASSETS Current Assets: Cash and cash equivalents $ 523 $ 772 Accounts receivable from related companies 64,542 33,146 Other current assets 21,918 6,246 Total current assets 86,983 40,164 Investment in unconsolidated affiliates - 1,461,226 Other non-current assets 24,197 27,339 Total assets $ 111,180 $ 1,528,729 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Current portion of long-term debt $ 1,300,000 $ - Interest payable 14,166 16,046 Accrued and other current liabilities - 31 Total current liabilities 1,314,166 16,077 Long-term debt - 1,300,000 Advances to unconsolidated affiliates 1,788,951 - Other long-term obligations - 992 Total shareholders' equity (2,991,937) 211,660 Total liabilities and shareholders' equity $ 111,180 $ 1,528,729 CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2015 2014 2013 Net cash (used in) provided by operating activities $ (101,277) $ (35,818) $ 17,772 Investing Activities: Investment in subsidiaries - (850,000) (464,405) Dividends received 96,297 52,741 4,580 Net cash provided by (used in) investing activities 96,297 (797,259) (459,825) Financing activities: Proceeds from issuance of Senior Notes - 850,000 450,000 Deferred financing costs 6 (13,245) (8,958) Repurchased shares - (6,471) (3,311) Shares re-issued from treasury 4,725 2,936 1,496 Net cash provided by financing activities 4,731 833,220 439,227 (Decrease) increase in cash during the period (249) 143 (2,826) Cash and cash equivalents, beginning of period 772 629 3,455 Cash and cash equivalents, end of period $ 523 $ 772 $ 629 |
Significant Accounting Polici24
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of presentation | (a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accou nts of the Company and its wholly 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 consolidati on. |
Cash and cash equivalents | (b) Cash and cash equivalents: 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 represents cash received by the Company from productio n sold where the final division 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 accounts receivable approximates fair value because of the short-term nature of the instru ments. 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 use ful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction, the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $ 91.8 million w as transferre d to proven oil and gas properties at September 30, 2014 . |
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 Securities and Exchange Commission (“SEC”) Relea se 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 Activities – 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 related to exploration and development a ctivities 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 recorded based on the fair value of the a sset 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 capitalized 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 na tural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion. Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Comp any reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluat ed utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk we ighting factors. The amount of any impairment is transferred to the capitalized costs being amortized . Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10 %, plus the lower of cost or market value of unproved properties, less any associated ta x effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depleti on, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. During 2015, the Company recorded a $3.1 bill ion 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. Th e ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market d ifferentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2014 or 2013. |
Inventories | (g) Inventories: At December 31, 2015 and 2014 , inventory of $4.3 million and $10.2 million, respectively, primarily includ es the cost of pipe and production equipment that will be utilized during the 2016 drilling program and crude oil inventory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly a nd indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and 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) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Compan y records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. 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: Included in current assets at December 31, 2015 are costs associated with th e issuance of our senior notes, revolving credit facility, 2018 Notes and 2024 Notes. The remaining unamortized issuance costs are being amortized over the life of the applicable debt or facility using the straight line method. |
Income Taxes Policy | (j) Income taxes: Income t axes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized 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 liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to b e recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more l ikely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the po sition following an audit. The Company has recorded a valuation allowance against certain deferred tax assets of $1.3 billion as of December 31, 2015 . Some or all of this valuation allowance may be reversed in future periods against future in come. |
Earnings per share | (k) Earnings (loss) per share: Basic earnings (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted income (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 following table provides a reconciliation of components of basic and diluted net (loss) income per common share: December 31, 2015 2014 2013 Net (loss) income $ (3,207,220) $ 542,851 $ 237,838 Weighted average common shares outstanding during the period 153,192 153,136 152,963 Effect of dilutive instruments - (1) 1,558 1,463 Weighted average common shares outstanding during the period including the effects of dilutive instruments 153,192 154,694 154,426 Net (loss) income per common share - basic $ (20.94) $ 3.54 $ 1.55 Net (loss) income per common share - fully diluted $ (20.94) $ 3.51 $ 1.54 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) 1,377 1,406 ( 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 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 recognizes compensation expense for all share-based p ayment 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 accounting: The Company follows FASB ASC Topic 820, F air 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 liability with an associated increase in oil and gas prop erties 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 adjustment is recorded to both the asset retirement o bligation 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 timing of settling asset retirement obligations. As a f ull 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 accompanying 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 and under multi-year contracts that provide for a fixed price of oil and natural gas. 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 natura l gas sales using the “entitlements 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 of the volumes is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2015 and 2014 , the Company had a net natural gas imbalance liability of $1.3 million and $3.0 million , respectively . Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or , in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allow s for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. |
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, as well as on w ork in p rocess relating to gathering systems that are not currently in service . |
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 recl assified to conform to the current period financial statement presentation . |
Recent accounting pronouncements | (t) Recent accounting pronouncements: In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU No. 2016-0 2”). 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 also will require disclosures designed to giv e financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. For public companies, the standard will take effect for fiscal years, a nd interim periods within those fiscal years, beginning after Dec. 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 November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU No. 2015-17”). The guidance eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent a mounts in a classified balance sheet. The new standard requires deferred tax assets and liabilities to be classified as noncurrent. The amendments in this update are effective for financial statements issued for annual periods beginning after December 15 , 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period and may be applied either prospectively or retrospectively to all periods presented. T he Company has elected early adoption of ASU No. 2015-17 and has applied these changes prospectively. The adoption of this guidance has no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent affec ts presentation of our financial position. See Note 9 for additional information. 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 am endments 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 statement s. In April 2015, the FASB issued an amendment to U.S. GAAP to simplify the balance sheet presentation of the costs for issuing debt. The changes were adopted in ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Present ation of Debt Issuance Costs (“ASU No. 2015-3”) . Public companies will have to apply the amendments for reporting periods that start after December 15, 2015. The amendment requires adoption by revising the balance sheets for periods prior to the effective date, which makes it easier for investors to evaluate a company’s financial performance. The amendment to FASB ASC 835-30-45, Interest—Imputation of Interest, formerly Accounting Principles Board Opinion No. 21, means that the costs for issuing debt will a ppear on the balance sheet as a direct deduction of debt. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In June 2015, the FASB issued a delay by one year of the revenue recognition standard adopted in June 2014. In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers , and sup erseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition , and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. The new proposal related to ASU No. 2014-09 delays the application of the standard to reporting periods beginning after December 15, 2017 instead of December 15, 2016. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations . In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Conc ern (“ASU No. 2014-15”) that requires management to evaluate whether 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 a n interim and annual basis. Management is required to provide certain 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 beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements . |
Derivatives and Hedging Activities Policies [Abstract] | |
Derivative Instruments and hedging activities | (h) Derivative instruments and hedging activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Compan y records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7). |
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, as well as on w ork in p rocess relating to gathering systems that are not currently in service . |
Significant Accounting Polici25
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Tables Policies [Abstract] | |
Schedule Of Earnings Per Share | The following table provides a reconciliation of components of basic and diluted net (loss) income per common share: December 31, 2015 2014 2013 Net (loss) income $ (3,207,220) $ 542,851 $ 237,838 Weighted average common shares outstanding during the period 153,192 153,136 152,963 Effect of dilutive instruments - (1) 1,558 1,463 Weighted average common shares outstanding during the period including the effects of dilutive instruments 153,192 154,694 154,426 Net (loss) income per common share - basic $ (20.94) $ 3.54 $ 1.55 Net (loss) income per common share - fully diluted $ (20.94) $ 3.51 $ 1.54 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) 1,377 1,406 ( 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 loss per share. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Schedule Of Asset Retirement Obligations | December 31, 2015 2014 Asset retirement obligations at beginning of period $ 127,240 $ 72,807 Accretion expense 9,122 6,571 Liabilities incurred 7,352 10,242 Liabilities acquired(1) - 53,270 Liabilities divested(1) - (15,760) Liabilities settled (1,861) (336) Revisions of estimated liabilities 4,357 446 Asset retirement obligations at end of period 146,210 127,240 Less: current asset retirement obligations (305) (417) Long-term asset retirement obligations $ 145,905 $ 126,823 (1 ) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment. |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Properties And Equipment Tables [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities | December 31, December 31, 2015 2014 Proven Properties : Acquisition, equipment, exploration, drilling and environmental costs (1) $ 10,480,165 $ 9,731,407 Less: Accumulated depletion, depreciation and amortization (2) (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Propertie s: Acquisition and exploration costs not being amortized (3), (4) - 242,294 Net capitalized costs - oil and gas properties $ 851,145 $ 3,878,937 ( 1 ) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment . ( 2 ) 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 t he accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural g as and West Texas Intermediate oil, adjusted for market differentials. (3 ) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on w ork i n p rocess rel ating to g athering systems that are not currently in service . For the years ended December 31, 2015 and 2014 , total interest on outstanding debt was $185.0 million and $146.6 million, respectively, of which $13.1 mil lion and $20.4 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and w ork i n p rocess relating to g athering systems that are not currently in service . ( 4 ) At December 31, 2015, all costs related to un evaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool. G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2015 2014 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,480,165 $ 9,731,407 Less: accumulated depletion, depreciation and amortization (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Properties: Acquisition and exploration costs not being amortized - 242,294 $ 851,145 $ 3,878,937 |
Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization Text Block | Total 2015 2014 2013 Prior Acquisition costs $ - $ (228,516) $ (191,184) $ 419,700 $ - Exploration costs - 7,708 173 (7,881) - Capitalized interest - (21,486) 20,232 1,254 - Unproven properties $ - $ (242,294) $ (170,779) $ 413,073 $ - |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Property, Plant and Equipment | December 31, 2015 2014 Cost Accumulated Depreciation Net Book Value Net Book Value Computer equipment 2,797 (2,003) 794 917 Office equipment 520 (324) 196 57 Leasehold improvements 486 (219) 267 111 Land 4,637 - 4,637 5,778 Other 12,540 (9,590) 2,950 5,323 Property, plant and equipment, net $ 20,980 $ (12,136) $ 8,844 $ 12,186 |
Long Term Liabilities (Tables)
Long Term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Long Term Liabilities Tables [Abstract] | |
Schedule of Long-term Liabilities | December 31, December 31, 2015 2014 Short-term debt: Senior Notes $ 2,760,000 $ 100,000 Bank indebtedness 630,000 - Long-term debt and other long-term liabilities: Bank indebtedness - 518,000 Senior notes - 2,760,000 Other long-term obligations 165,784 152,472 $ 3,555,784 $ 3,530,472 |
Maturity Schedule | Aggregate maturities of debt at December 31, 2015:(1) Beyond 2016 2017 2018 2019 2020 5 years Total $ 3,390,000 $ - $ - $ - $ - $ - $ 3,390,000 (1) Continued low oil and natural gas prices during 2015 have had a significant adverse impact on our business , and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern . As a result, we have reclassified all of our total outstanding debt as short-term. Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to comply with the covenants in our existing debt agr eements and amend or replace our debt agreements as they mature. Please refer to Not e 1 for further discussion . A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements may result in r educed borrowing capacity or an event of a default, causing our debt obligations under such financing agreements (and any other indebtedness or contractual obligations to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. |
Share Based Compensation (Table
Share Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Share Based Compensation Tables [Abstract] | |
Valuation and Expense Information | Valuation and Expense Information Year Ended December 31, 2015 2014 2013 Total cost of share-based payment plans $ 6,137 $ 8,640 $ 13,957 Amounts capitalized in oil and gas properties and equipment $ 2,009 $ 3,173 $ 4,190 Amounts charged against income, before income tax benefit $ 4,128 $ 5,467 $ 9,767 Amount of related income tax benefit recognized in income before valuation allowances $ 1,645 $ 2,285 $ 4,083 |
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 519 $58.98 4,555 Equity compensation plans not approved by security holders n/a n/a n/a Total 519 $58.98 4,555 |
Changes in Stock Options Outstanding | Weighted Average Number of Exercise Price Options (US$) (000's) Balance, December 31, 2012 1,357 $16.97 to $98.87 Forfeited (110) $25.68 to $75.18 Exercised (1) $16.97 to $16.97 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 |
Share Based Compensation by Exercise Price Table | The following table summarizes information about the stock options outstanding and exercisable at December 31, 2015: 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) $ 50.15 - $ 63.05 103 0.60 $55.37 $- $ 49.05 - $ 62.23 268 1.29 $53.96 $- $ 51.60 - $ 98.87 148 2.45 $70.61 $- |
Weighted Average Grant Date Fair Value of Stock Options | 2015 2014 2013 Options forfeited during the year $ 28.00 $ 24.40 $ 25.44 |
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 2013 LTIP Volatility of common stock 40.1% 39.0% 39.2% Average volatility of peer companies 46.5% n/a n/a Average correlation coefficient of peer companies 0.454 n/a n/a Risk-free interest rate 1.02% 0.66% 0.40% |
Derivative Financial Instrume31
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014 and 2013 : For the Year Ended December 31, Commodity Derivatives : 2015 2014 2013 Realized gain (loss) on commodity derivatives-natural gas (1) $ 146,801 $ (48,170) $ (20,552) Realized gain (loss) on commodity derivatives-crude oil (1) - 506 (326) Unrealized gain (loss) on commodity derivatives (1) (104,190) 130,066 (25,876) Total gain (loss) on commodity derivatives $ 42,611 $ 82,402 $ (46,754) (1) Included in gain (loss) on commodity derivatives in the Consolidated Statements of Operations. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Measurements Tables [Abstract] | |
Fair Value of Long-Term Debt | December 31, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value 5.45% Notes due March 2015, issued 2008 $ - $ - $ 100,000 $ 101,931 7.31% Notes due March 2016, issued 2009 62,000 63,604 62,000 65,027 4.98% Notes due January 2017, issued 2010 116,000 113,420 116,000 116,240 5.92% Notes due March 2018, issued 2008 200,000 191,985 200,000 203,738 5.75% Notes due December 2018, issued 2013 450,000 111,451 450,000 414,505 7.77% Notes due March 2019, issued 2009 173,000 174,488 173,000 187,105 5.50% Notes due January 2020, issued 2010 207,000 185,052 207,000 201,371 4.51% Notes due October 2020, issued 2010 315,000 258,520 315,000 283,335 5.60% Notes due January 2022, issued 2010 87,000 73,034 87,000 82,581 4.66% Notes due October 2022, issued 2010 35,000 25,558 35,000 30,476 6.125% Notes due October 2024, issued 2014 850,000 206,321 850,000 754,485 5.85% Notes due January 2025, issued 2010 90,000 70,756 90,000 83,876 4.91% Notes due October 2025, issued 2010 175,000 115,911 175,000 147,649 Credit Facility due October 2016 630,000 630,000 518,000 518,000 $ 3,390,000 $ 2,220,100 $ 3,378,000 $ 3,190,319 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes [Abstract] | |
Consolidated income tax provision table | (Loss) income before income tax benefit is as follows: Year Ended December 31, 2015 2014 2013 United States $ (3,249,590) $ 505,689 $ 210,580 Foreign 37,966 31,338 23,642 Total $ (3,211,624) $ 537,027 $ 234,222 The consolidated income tax (benefit) provision is comprised of the following: Year Ended December 31, 2015 2014 2013 Current tax: U.S. federal, state and local $ - $ (110) $ (8,491) Foreign (3,414) (6,709) 4,881 Total current tax (benefit) (3,414) (6,819) (3,610) Deferred tax: Foreign (990) 995 (6) Total deferred tax (benefit) expense (990) 995 (6) Total income tax (benefit) $ (4,404) $ (5,824) $ (3,616) |
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, 2015 2014 2013 Income tax (benefit) provision computed at the U.S. statutory rate $ (1,124,069) $ 187,959 $ 81,978 State income tax (benefit) provision net of federal benefit (12,998) 8,023 1,329 Valuation allowance 1,147,619 (199,038) (81,923) Tax effect of rate change 12,898 15,457 (2,871) Foreign rate differential (26,740) (16,314) (3,508) Other, net (1,114) (1,911) 1,379 Total income tax (benefit) $ (4,404) $ (5,824) $ (3,616) |
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, 2015 2014 Deferred tax assets - current : Incentive compensation/other, net - 6,150 - 6,150 Net deferred tax assets - current $ - $ 6,150 Deferred tax liabilities - current : Derivative instruments, net $ - $ 36,788 Net deferred tax liabilities - current $ - $ 36,788 Net deferred tax liability - current $ - $ 30,638 Deferred tax assets - non-current : Property and equipment 776,504 - Deferred gain 44,593 48,319 U.S. federal tax credit carryforwards 16,144 16,144 U.S. net operating loss carryforwards 319,673 147,336 U.S. state net operating loss carryforwards 61,919 53,654 Non-U.S. net operating loss carryforwards 9,142 - Asset retirement obligations 51,815 45,039 Incentive compensation/other, net 28,711 19,142 1,308,501 329,634 Valuation allowance (1,307,076) (161,480) Net deferred tax assets - non-current $ 1,425 $ 168,154 Deferred tax liabilities - non-current : Property and equipment - 137,514 Other - non-US 1,424 - Net non-current tax liabilities $ 1,424 $ 137,514 Net non-current tax asset $ 1 $ 30,640 Deferred tax liabilities - non-current : Other - non-US - 992 |
Summarized Quarterly Financia34
Summarized Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summarized Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Financial Information Table Text Block | 2015 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Revenues from continuing operations $ 219,309 $ 207,998 $ 222,503 $ 189,301 $ 839,111 Gain (loss) on commodity derivatives 36,865 (3,646) 9,390 2 42,611 Expenses from continuing operations 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 (benefit) 23,167 (24,923) (4,229) (3,205,639) (3,211,624) Income tax provision (benefit) (2,022) (250) (1,133) (999) (4,404) Net income (loss) $ 25,189 $ (24,673) $ (3,096) $ (3,204,640) $ (3,207,220) Net income (loss) per common share - basic $ 0.16 $ (0.16) $ (0.02) $ (20.91) $ (20.94) Net income (loss) per common share - fully diluted $ 0.16 $ (0.16) $ (0.02) $ (20.91) $ (20.94) 2014 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Total Revenues from continuing operations $ 326,299 $ 296,063 $ 288,608 $ 319,050 $ 1,230,020 (Loss) gain on commodity derivatives (45,273) (15,102) 32,052 110,725 82,402 Expenses from continuing operations 154,829 150,850 169,669 195,083 670,431 Interest expense 27,068 27,294 29,599 42,196 126,157 Gain on sale of property - - - 8,022 8,022 Other income (expense), net 2,590 2,688 2,582 5,311 13,171 Income before income tax provision (benefit) 101,719 105,505 123,974 205,829 537,027 Income tax provision (benefit) 4 (544) (1,383) (3,901) (5,824) Net income $ 101,715 $ 106,049 $ 125,357 $ 209,730 $ 542,851 Net income per common share - basic $ 0.66 $ 0.69 $ 0.82 $ 1.37 $ 3.54 Net income per common share - fully diluted $ 0.66 $ 0.68 $ 0.81 $ 1.36 $ 3.51 |
Disclosures About Oil and Gas P
Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2012 18,137 2,966,445 - Extensions, discoveries and additions 11,329 1,409,528 - Acquistions 10,114 - - Production (1,196) (224,912) - Revisions (4,265) (741,319) - 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 United States Oil Natural Gas NGLs (MBbls) (MMcf) (MBbls) Proved: Developed 10,531 1,820,994 - Undeveloped 7,606 1,145,451 - Total Proved - 2012 18,137 2,966,445 - 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 |
Standardized measure | As of December 31, 2015 2014 2013 Future cash inflows $ 6,312,095 $ 27,331,391 $ 14,861,131 Future production costs (3,006,265) (8,627,657) (4,540,209) Future development costs (358,848) (3,859,385) (2,014,751) Future income taxes - (3,898,355) (1,897,340) Future net cash flows 2,946,982 10,945,994 6,408,831 Discount at 10% (1,081,333) (5,712,511) (3,220,862) Standardized measure of discounted future net cash flows $ 1,865,649 $ 5,233,483 $ 3,187,969 |
Summary of changes in the standardized measure of discounted future net cash flows | December 31, 2015 2014 2013 Standardized measure, beginning $ 5,233,483 $ 3,187,969 $ 1,894,317 Net revisions of previous quantity estimates (2,126,998) (603,795) (1,089,316) Extensions, discoveries and other changes 15,254 1,787,643 2,098,644 Sales of reserves in place - (398,506) - Acquisition of reserves - 2,552,491 86,196 Changes in future development costs 1,618,068 (1,013,652) (252,992) Sales of oil and gas, net of production costs (550,879) (949,389) (720,826) Net change in prices and production costs (6,996,416) 1,010,052 1,204,041 Development costs incurred during the period that reduce future development costs 548,112 342,987 171,149 Accretion of discount 709,736 413,177 226,326 Net changes in production rates and other 1,551,413 (175,419) 145,289 Net change in income taxes 1,863,876 (920,075) (574,859) Aggregate changes (3,367,834) 2,045,514 1,293,652 Standardized measure, ending $ 1,865,649 $ 5,233,483 $ 3,187,969 |
Costs incurred in oil and gas exploration and development activities | Years Ended December 31, 2015 2014 2013 United States Property Acquisitions: Unproved $ 13,845 $ 26,106 $ 424,540 Proved - 895,179 224,410 Exploration* 18,164 197,664 184,007 Development 461,458 382,984 186,755 Total $ 493,467 $ 1,501,933 $ 1,019,712 * 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, 2015 2014 2013 United States Oil and gas revenue $ 839,111 $ 1,230,020 $ 933,404 Production expenses (288,231) (280,631) (212,578) Depletion and depreciation (401,200) (292,951) (243,390) Ceiling test and other impairments (3,144,899) - - Income tax benefit (expense) (9,841) 3,736 (2,821) Total $ (3,005,060) $ 660,174 $ 474,615 |
Capitalized Costs Relating to Oil and Gas Producing Activities | December 31, December 31, 2015 2014 Proven Properties : Acquisition, equipment, exploration, drilling and environmental costs (1) $ 10,480,165 $ 9,731,407 Less: Accumulated depletion, depreciation and amortization (2) (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Propertie s: Acquisition and exploration costs not being amortized (3), (4) - 242,294 Net capitalized costs - oil and gas properties $ 851,145 $ 3,878,937 ( 1 ) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties in Pennsylvania and a cash payment . ( 2 ) 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 t he accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural g as and West Texas Intermediate oil, adjusted for market differentials. (3 ) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on w ork i n p rocess rel ating to g athering systems that are not currently in service . For the years ended December 31, 2015 and 2014 , total interest on outstanding debt was $185.0 million and $146.6 million, respectively, of which $13.1 mil lion and $20.4 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and w ork i n p rocess relating to g athering systems that are not currently in service . ( 4 ) At December 31, 2015, all costs related to un evaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool. G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: December 31, 2015 2014 Proven Properties: Acquisition, equipment, exploration, drilling and environmental costs $ 10,480,165 $ 9,731,407 Less: accumulated depletion, depreciation and amortization (9,629,020) (6,094,764) 851,145 3,636,643 Unproven Properties: Acquisition and exploration costs not being amortized - 242,294 $ 851,145 $ 3,878,937 |
Supplemental Financial Statem36
Supplemental Financial Statement Information (Parent Company) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Parent Company Financial Statements [Abstract] | |
Supplemental Statement of Operations Disclosures Parent Company | CONDENSED STATEMENT OF OPERATIONS Year Ended December 31, 2015 2014 2013 General and administrative expense $ 308 $ 261 $ 102 Other income (expense): Interest expense (81,069) (42,996) (1,438) Income from unconsolidated affiliates (3,152,078) 558,634 223,685 Guarantee fee income 23,029 23,045 22,406 Other expense (1,684) (1,324) (1,836) Income before income taxes (3,212,110) 537,098 242,715 Income tax (benefit) expense (4,890) (5,753) 4,877 Net income $ (3,207,220) $ 542,851 $ 237,838 |
Supplemental Balance Sheet Disclosures Parent Company | CONDENSED BALANCE SHEET December 31, December 31, 2015 2014 ASSETS Current Assets: Cash and cash equivalents $ 523 $ 772 Accounts receivable from related companies 64,542 33,146 Other current assets 21,918 6,246 Total current assets 86,983 40,164 Investment in unconsolidated affiliates - 1,461,226 Other non-current assets 24,197 27,339 Total assets $ 111,180 $ 1,528,729 LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Current portion of long-term debt $ 1,300,000 $ - Interest payable 14,166 16,046 Accrued and other current liabilities - 31 Total current liabilities 1,314,166 16,077 Long-term debt - 1,300,000 Advances to unconsolidated affiliates 1,788,951 - Other long-term obligations - 992 Total shareholders' equity (2,991,937) 211,660 Total liabilities and shareholders' equity $ 111,180 $ 1,528,729 |
Supplemental Cash Flow Statement Disclosures Parent Company | CONDENSED STATEMENT OF CASH FLOWS Year Ended December 31, 2015 2014 2013 Net cash (used in) provided by operating activities $ (101,277) $ (35,818) $ 17,772 Investing Activities: Investment in subsidiaries - (850,000) (464,405) Dividends received 96,297 52,741 4,580 Net cash provided by (used in) investing activities 96,297 (797,259) (459,825) Financing activities: Proceeds from issuance of Senior Notes - 850,000 450,000 Deferred financing costs 6 (13,245) (8,958) Repurchased shares - (6,471) (3,311) Shares re-issued from treasury 4,725 2,936 1,496 Net cash provided by financing activities 4,731 833,220 439,227 (Decrease) increase in cash during the period (249) 143 (2,826) Cash and cash equivalents, beginning of period 772 629 3,455 Cash and cash equivalents, end of period $ 523 $ 772 $ 629 |
Significant Accounting Polici37
Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings Per Share Reconciliation | |||||||||||
Net earnings (loss) | $ (3,204,640) | $ (3,096) | $ (24,673) | $ 25,189 | $ 209,730 | $ 125,357 | $ 106,049 | $ 101,715 | $ (3,207,220) | $ 542,851 | $ 237,838 |
Weighted average common shares outstanding - basic | 153,192,000 | 153,136,000 | 152,963,000 | ||||||||
Effect of dilutive instruments | 0 | 1,558,000 | 1,463,000 | ||||||||
Weighted average common shares outstanding - fully diluted | 153,192,000 | 154,694,000 | 154,426,000 | ||||||||
Net (income (loss) per common share - basic | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.37 | $ 0.82 | $ 0.69 | $ 0.66 | $ (20.94) | $ 3.54 | $ 1.55 |
Net income (loss) per common share - fully diluted | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.36 | $ 0.81 | $ 0.68 | $ 0.66 | $ (20.94) | $ 3.51 | $ 1.54 |
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount | 1,700,000 | 1,377,000 | 1,406,000 |
Significant Accounting Polici38
Significant Accounting Policies (Narratives) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 29, 2016 | |
Significant Accounting Policies Details [Abstract] | ||||
Outstanding debt obligations | $ 3,760,000,000 | |||
Senior Notes Ultra Petroleum Corp Due 2018 | $ 450,000,000 | 450,000,000 | ||
Senior Notes Ultra Petroleum Corp Due 2024 | 850,000,000 | 850,000,000 | ||
Bank indebtedness current | 630,000,000 | $ 0 | 999,000,000 | |
Senior Notes Ultra Resources Inc | $ 1,460,000,000 | 1,460,000,000 | ||
Bank loan borrowings | $ 266,000,000 | |||
Restrictive covenants Ultra Resources debt | 3.5 to 1.0 | |||
Restrictive covenants present value Ultra Resources revolving credit facility | 1.5 to 1.0 | |||
Restrictive covenants Ultra Petroleum Corp | 2.25 to 1.00 | |||
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 | |||
Discount rate future net revenues | 10.00% | |||
Ceiling test limitation | $ 3,100,000,000 | 0 | $ 0 | |
Inventory | 4,269,000 | 10,216,000 | ||
Valuation allowance | 1,300,000,000 | 161,500,000 | ||
Natural gas imbalance liability | $ 1,300,000 | $ 3,000,000 |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation [Abstract] | ||
Asset retirement obligations at beginning of period | $ 127,240 | $ 72,807 |
Accretion expense | 9,122 | 6,571 |
Liabilities incurred | 7,352 | 10,242 |
Liabilities acquired | 0 | 53,270 |
Liabilities divested | 0 | (15,760) |
Liabilities settled | (1,861) | (336) |
Asset Retirement Obligation, Revision of Estimate | 4,357 | 446 |
Asset retirement obligations at end of period | 146,210 | 127,240 |
Less: current asset requirement obligations | (305) | (417) |
Long-term asset retirement obligations | $ 145,905 | $ 126,823 |
Oil and Gas Properties (Details
Oil and Gas Properties (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Proven Properties [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $ 10,480,165 | $ 9,731,407 |
Less: Accumulated depletion, depreciation and amortization | (9,629,020) | (6,094,764) |
Proved | 851,145 | 3,636,643 |
Unproven Properties: | ||
Unproven properties not being amortized | 0 | 242,294 |
Net capitalized costs - oil and gas properties | $ 851,145 | $ 3,878,937 |
Oil and Gas Properties (Detai41
Oil and Gas Properties (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2011 | |
Unproven Properties: | ||||
Net Acquisition Costs | $ 0 | |||
Exploration costs | 0 | |||
Interest Costs Capitalized | 0 | |||
Total | 0 | $ 242,294 | ||
Acquisition costs | (228,516) | (191,184) | $ 419,700 | $ 0 |
Exploration costs | 7,708 | 173 | (7,881) | 0 |
Interest Costs Capitalized | (21,486) | 20,232 | 1,254 | 0 |
Total | $ (242,294) | $ (170,779) | $ 413,073 | $ 0 |
Oil and Gas Properties (Narrati
Oil and Gas Properties (Narratives) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)$ / Mcf | Dec. 31, 2014USD ($)$ / Mcf | Dec. 31, 2013USD ($)$ / Mcf | |
Oil And Gas Property [Abstract] | |||
DD&A per Mcfe | $ / Mcf | 1.38 | 1.18 | 1.05 |
Ceiling test limitation | $ 3,100 | $ 0 | $ 0 |
Total interest on outstanding debt | 185 | 146.6 | |
Capitalized interest detail | $ 13.1 | $ 20.4 |
Property, Plant & Equipment (De
Property, Plant & Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | $ 20,980 | |
Accumulated Depreciation | (12,136) | |
Property, plant and equipment | 8,844 | $ 12,186 |
Computer equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 2,797 | |
Accumulated Depreciation | (2,003) | |
Property, plant and equipment | 794 | 917 |
Office equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 520 | |
Accumulated Depreciation | (324) | |
Property, plant and equipment | 196 | 57 |
Leasehold improvements [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 486 | |
Accumulated Depreciation | (219) | |
Property, plant and equipment | 267 | 111 |
Land [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 4,637 | |
Accumulated Depreciation | 0 | |
Property, plant and equipment | 4,637 | 5,778 |
Other [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 12,540 | |
Accumulated Depreciation | (9,590) | |
Property, plant and equipment | $ 2,950 | $ 5,323 |
Debt and Other Long Term Liabil
Debt and Other Long Term Liabilities (Details) - USD ($) $ in Thousands | Feb. 29, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Long Term Liabilities [Abstract] | |||
Bank indebtedness | $ 0 | $ 518,000 | |
Senior notes | 0 | 2,760,000 | |
Other long-term obligations | 165,784 | 152,472 | |
Total Debt And Long Term Liabilities | 3,555,784 | 3,530,472 | |
Short-term Debt [Abstract] | |||
Senior Notes | 2,760,000 | 100,000 | |
Bank indebtedness current | $ 999,000 | $ 630,000 | $ 0 |
Debt and Other Long Term Liab45
Debt and Other Long Term Liabilities (Details 1) $ in Thousands | Dec. 31, 2015USD ($) |
Long Term Debt Maturities | $ 3,390,000 |
Maturities Of Long Term Debt One Year [Member] | |
Long Term Debt Maturities | 3,390,000 |
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 Liab46
Debt and Other Long Term Liabilities (Narratives) (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Feb. 29, 2016USD ($) | Dec. 31, 2014USD ($) | |
Senior Credit Facility Details [Abstract] | |||
Revolving Bank Loan Comitment Value | $ 1,000,000,000 | ||
Max Revolving Bank Loan Comitment Value | 1,250,000,000 | ||
Letters Of Credit Availability | $ 250,000,000 | ||
Credit Facility Lender Consent Requirement | 50.00% | ||
Bank indebtedness current | $ 630,000,000 | $ 999,000,000 | $ 0 |
Available borrowing capacity | $ 370,000,000 | ||
Debt Instrument Interest Rate Terms Prime | 150 | ||
Debt Instrument Interest Rate Terms Libor | 250 | ||
Commitment fees incurred in current year | $ 1,700,000 | ||
Ultra Resources Inc Senior Notes | |||
Senior Notes Ultra Resources Inc | 1,460,000,000 | 1,460,000,000 | |
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% | ||
Debt Instrument Call Feature Ultra Petroleum Corp Senior Notes Due 2024 | On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 – 103.063%; 2020 – 102.042%; 2021 – 101.021%; and 2022 and thereafter – 100.000%). | ||
Senior Notes Ultra Petroleum Corp Due 2018 | $ 450,000,000 | 450,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2018 Interest Rate | 5.75% | ||
Debt Instrument Call Feature | On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following prices expressed as a percentage of principal amount of the 2018 Notes: (2015 – 102.875%; 2016 – 101.438%; and 2017 and thereafter – 100.000%). | ||
Maturities Abstract | |||
Bank indebtedness current | $ 630,000,000 | 999,000,000 | $ 0 |
Senior Notes Ultra Petroleum Corp Due 2018 | 450,000,000 | 450,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2024 | 850,000,000 | 850,000,000 | |
Senior Notes Ultra Resources Inc | 1,460,000,000 | $ 1,460,000,000 | |
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 | ||
Covenants And Events Of Default [Abstract] | |||
Restrictive covenants Ultra Resources debt | 3.5 to 1.0 | ||
Restrictive covenants present value Ultra Resources revolving credit facility | 1.5 to 1.0 | ||
Restrictive covenants Ultra Petroleum Corp | 2.25 to 1.00 |
Share Based Compensation (Detai
Share Based Compensation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Valuation And Expense Information [Abstract] | |||
Total Cost Of Share Based Payment Plans | $ 6,137 | $ 8,640 | $ 13,957 |
Amounts capitalized in fixed costs | 2,009 | 3,173 | 4,190 |
Amounts charged against income, before income tax benefit | 4,128 | 5,467 | 9,767 |
Amount of related income tax benefit recognized in income | $ 1,645 | $ 2,285 | $ 4,083 |
Share Based Compensation (Det48
Share Based Compensation (Details 1) | Dec. 31, 2015USD ($)shares |
Share Based Compensation Details [Abstract] | |
Number of Securities to be Issued Upon Exercise of Outstanding Options | 519,000 |
Weighted Averaged Exercise Price of Outstanding Options | $ | 58.98 |
Number Of Securities Remaining Available For Future Issuance Under Equity Compenstation Plans Excluding Securities Reflected In The First Column | 4,555,000 |
Share Based Compensation (Det49
Share Based Compensation (Details 2) - $ / shares | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Stock Options Outstanding Summary [Line Items] | ||||
Balance | 519,000 | |||
Number Of Options [Member] | ||||
Stock Options Outstanding Summary [Line Items] | ||||
Balance | 690,000 | 1,246,000 | 1,357,000 | |
Forfeited | (171,000) | (513,000) | (110,000) | |
Exercised | (43,000) | (1,000) | ||
Balance | 519,000 | 690,000 | 1,246,000 | 1,357,000 |
Weighted Average Exercise Price [Member] | ||||
Stock Options Outstanding Summary [Line Items] | ||||
Exercise Price, Lower Range Limit | $ 49.05 | $ 25.68 | $ 16.97 | $ 16.97 |
Exercise Price, Upper Range Limit | 98.87 | 98.87 | 98.87 | $ 98.87 |
Exercise Price, Lower Range Limit Forfeited | 25.68 | 33.57 | 25.68 | |
Exercise Price, Upper Range Limit Forfeited | $ 75.18 | 75.18 | 75.18 | |
Exercise Price, Lower Range Limit Exercised | 16.97 | 16.97 | ||
Exercise Price, Upper Range Limit Exercised | $ 25.68 | $ 16.97 |
Share Based Compensation (Det50
Share Based Compensation (Details 3) $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)$ / sharesshares | |
Range 5 [Member] | |
Stock Options Outstanding Summary [Line Items] | |
Exercise Price, Lower Range Limit | $ 50.15 |
Exercise Price, Upper Range Limit | $ 63.05 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
Number Outstanding | shares | 103,000 |
Weighted Average Remaining Contractual Life | 7 months 6 days |
Weighted Average Exercise Price | $ 55.37 |
Aggregate Intrinsic Value | $ | $ 0 |
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 | 268,000 |
Weighted Average Remaining Contractual Life | 1 year 3 months 14 days |
Weighted Average Exercise Price | $ 53.96 |
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 | 148,000 |
Weighted Average Remaining Contractual Life | 2 years 5 months 12 days |
Weighted Average Exercise Price | $ 70.61 |
Aggregate Intrinsic Value | $ | $ 0 |
Share Based Compensation (Det51
Share Based Compensation (Details 4) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | |||
Options forfeited during the year | $ 28 | $ 24.4 | $ 25.44 |
Share Based Compensaton (TSR) (
Share Based Compensaton (TSR) (Details 5) | 12 Months Ended |
Dec. 31, 2015 | |
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% |
Long Term Incentive 2013 Plan [Member] | |
Total Shareholder Retun [Line Items] | |
Volatility of common stock | 39.20% |
Risk-free interest rate | 0.40% |
Share Based Compensation (Narra
Share Based Compensation (Narratives) (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Share Based Compensation Details [Abstract] | |||
Companys Closing Stock Price Last Day Of Year | 2.5 | ||
Number Of In The Money Options Exercisable | shares | 0 | ||
Total intrinsic value of stock options excercised | $ 0 | $ 0 | $ 0 |
Long Term Incentive Program Period | 2,900,000 | $ 6,300,000 | $ 6,900,000 |
Long Term Incentive Program Total 2013 Program | 8,000,000 | ||
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 2012 Program | $ 9,200,000 | ||
Long Term Incentive Program Total 2012 Program Shares | shares | 232,626 |
Derivative Financial Instrume54
Derivative Financial Instruments (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Commodity Derivatives [Abstract] | |||||||||||
Realized (loss) gain on commodity derivatives - natural gas | $ 146,801 | $ (48,170) | $ (20,552) | ||||||||
Realized (loss) gain on commodity derivatives - crude oil | 0 | 506 | (326) | ||||||||
Unrealized loss (gain) on commodity derivatives | (104,190) | 130,066 | (25,876) | ||||||||
Gain loss on commodity derivatives | $ 2 | $ 9,390 | $ (3,646) | $ 36,865 | $ 110,725 | $ 32,052 | $ (15,102) | $ (45,273) | $ 42,611 | $ 82,402 | $ (46,754) |
Derivative Financial Instrume55
Derivative Financial Instruments (Narratives) (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Commodity Derivatives Authorization [Abstract] | |
Commodity Derivatives Board Authorization | 50.00% |
Fair Value Measurments (Details
Fair Value Measurments (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Assets Abstract | ||
Derivative assets | $ 0 | $ 104,190 |
Derivative Liabilities Abstract | ||
Derivative liabilities | $ 0 | $ 0 |
Fair Value Measurments (Detai57
Fair Value Measurments (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | ||
Debt carrying value | $ 3,390,000 | $ 3,378,000 |
Estimated Fair Value | 2,220,100 | 3,190,319 |
Notes Due 2015 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 0 | 100,000 |
Estimated Fair Value | $ 0 | 101,931 |
Debt Instruments Interst Rates | 5.45% | |
Notes Due 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 62,000 | 62,000 |
Estimated Fair Value | $ 63,604 | 65,027 |
Debt Instruments Interst Rates | 7.31% | |
Notes Due 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 116,000 | 116,000 |
Estimated Fair Value | $ 113,420 | 116,240 |
Debt Instruments Interst Rates | 4.98% | |
Notes Due 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 200,000 | 200,000 |
Estimated Fair Value | $ 191,985 | 203,738 |
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 | $ 111,451 | 414,505 |
Debt Instruments Interst Rates | 5.75% | |
Notes Due 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 173,000 | 173,000 |
Estimated Fair Value | $ 174,488 | 187,105 |
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 | $ 185,052 | 201,371 |
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 | $ 258,520 | 283,335 |
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 | $ 73,034 | 82,581 |
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 | $ 25,558 | 30,476 |
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 | $ 206,321 | 754,485 |
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 | $ 70,756 | 83,876 |
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 | $ 115,911 | 147,649 |
Debt Instruments Interst Rates | 4.91% | |
Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | $ 630,000 | 518,000 |
Estimated Fair Value | $ 630,000 | $ 518,000 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Loss From Continuing Operations [Abstract] | |||||||||||
United States | $ (3,249,590) | $ 505,689 | $ 210,580 | ||||||||
Foreign | 37,966 | 31,338 | 23,642 | ||||||||
Income (loss) before income tax (benefit) | $ (3,205,639) | $ (4,229) | $ (24,923) | $ 23,167 | $ 205,829 | $ 123,974 | $ 105,505 | $ 101,719 | $ (3,211,624) | $ 537,027 | $ 234,222 |
Income Taxes (Details 1)
Income Taxes (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current: | |||||||||||
U.S. federal, state and local - current | $ 0 | $ (110) | $ (8,491) | ||||||||
Foreign - current | (3,414) | (6,709) | 4,881 | ||||||||
Total current tax expense (benefit) | (3,414) | (6,819) | (3,610) | ||||||||
Deferred: | |||||||||||
Foreign - deferred | (990) | 995 | (6) | ||||||||
Total deferred tax expense (benefit) | (990) | 995 | (6) | ||||||||
Total income tax (benefit) | $ (999) | $ (1,133) | $ (250) | $ (2,022) | $ (3,901) | $ (1,383) | $ (544) | $ 4 | $ (4,404) | $ (5,824) | $ (3,616) |
Income Taxes (Details 2)
Income Taxes (Details 2) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation Abstract | |||||||||||
Income tax provision (benefit) computed at the U.S. statutory rate | $ (1,124,069) | $ 187,959 | $ 81,978 | ||||||||
State income tax provision net of federal benefit | (12,998) | 8,023 | 1,329 | ||||||||
Valuation allowance | 1,147,619 | (199,038) | (81,923) | ||||||||
Tax Effect Of Rate Change | 12,898 | 15,457 | (2,871) | ||||||||
Foreign tax rate differential | (26,740) | (16,314) | (3,508) | ||||||||
Other, net | (1,114) | (1,911) | 1,379 | ||||||||
Total income tax (benefit) | $ (999) | $ (1,133) | $ (250) | $ (2,022) | $ (3,901) | $ (1,383) | $ (544) | $ 4 | $ (4,404) | $ (5,824) | $ (3,616) |
Income Taxes (Details 3)
Income Taxes (Details 3) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax assets - current: | ||
Incentive compensation-other, net | $ 0 | $ 6,150 |
Net deferred tax assets - current | 0 | 6,150 |
Deferred Tax Liabilities Current [Abstract] | ||
Derivative instruments, net | 0 | 36,788 |
Deferred Tax Assets Liabilities Net Current | 0 | 30,638 |
Deferred tax assets - non - current [Abstract] | ||
Property and equipment | 776,504 | 0 |
Deferred gain on sale | 44,593 | 48,319 |
U.S. federal tax credit carryforwards | 16,144 | 16,144 |
U. S. net operating loss carryforwards | 319,673 | 147,336 |
US state net operating loss carryforward | 61,919 | 53,654 |
Non U.S. net operating loss carryforwards | 9,142 | 0 |
Asset retirement obligations | 51,815 | 45,039 |
Incentive compensation/other, net | 28,711 | 19,142 |
Deferred tax assets noncurrent before valuation allowances | 1,308,501 | 329,634 |
Valuation allowance | (1,307,076) | (161,480) |
Net deferred tax assets - non-current | 1,425 | 168,154 |
Deferred Tax Liabilities - non current [Abstract] | ||
Property and equipment | 0 | 137,514 |
Other | 1,424 | 0 |
Net non-current tax liabilities | 1,424 | 137,514 |
Net non-current tax asset | 1 | 30,640 |
Non-US Deferred tax liabilities - non-current | ||
Other - Non US | $ 0 | $ 992 |
Income Taxes (Narratives) (Deta
Income Taxes (Narratives) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 161,500 | |
Total change in valuation allowance | 1,100,000 | ||
Change in valuation allowance - earnings | (1,147,619) | 199,038 | $ 81,923 |
Change in valuation allowance - equity | (1,900) | ||
U.S. federal alternative minimum tax credits | 14,100 | ||
Deferred Tax Assets Tax Credit Carryforwards General Business | 500 | ||
Foreign tax credit carryforward | 1,600 | ||
U.S. federal tax operating loss | 494,800 | 213,000 | |
U.S. federal tax net operating loss carryforward | 913,400 | ||
PA state tax net operating loss carryforwards | 920,700 | ||
UT state tax net operating loss carryforwards | 65,600 | ||
Canadian Operating Loss | 61,300 | 23,800 | |
Income taxes receivable - Canada | 5,200 | $ 6,200 | |
Canadian Federal and Provincial tax loss balance | $ 33,900 |
Employee Benefits (Details)
Employee Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 1.6 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)MMBTU | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Commitements And Contingencies Disclosure [Abstract] | |||
Total interest expense contractual obligation | $ 906.6 | ||
Interest expense due in one year | 168.6 | ||
Interest expense due in two to three years | 287.6 | ||
Interest expense due in three to five years | 184.5 | ||
Interest expense due in five or more years | $ 265.9 | ||
Commitment capacity per day of natural gas | MMBTU | 200 | ||
Increased commitment capacity per day of natural gas | MMBTU | 50 | ||
Demand charges related to remaining contract | $ 368.1 | ||
Initial Term Liquids Gathering System Lease | 15 | ||
Renewal Term Liquids Gathering System Lease | 5 | ||
Renewal Term Liquids Gathering System Lease Useful Life | 75.00% | ||
Liquids Gathering System Operating Lease Rental Expense | $ 20 | ||
Lease And Rental Expense Total | 248.2 | ||
Office Space Operating Lease Total Future Minimum Payments | 7.8 | ||
Commitment to office leases, current | 1.4 | ||
Commitment to office leases, due in two years | 1.4 | ||
Commitment to office leases, due in three years | 1.3 | ||
Commitment to office leases, due in four years | 1.2 | ||
Commitment to office leases, due in five years | 1 | ||
Office leases expense | $ 1.3 | $ 1 | $ 1 |
Oil and gas delivery commitments details | Delivery Commitments. With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2016, the Company has long-term natural gas delivery commitments of 5.1 MMMBtu in 2016 and 13.5 MMMBtu in 2017 under existing agreements. As of February 9, 2016, the Company has long-term crude oil delivery commitments of 3.4 MMBbls in 2016, 2.8 MMBbls in 2017, 1.1 MMBbls in 2018 and 0.2 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments. |
Credit Risk (Details)
Credit Risk (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule Of Significant Customers [Line Items] | |
Percentage of revenue | 10.00% |
Subsequent Event (Details)
Subsequent Event (Details) $ in Millions | Feb. 29, 2016USD ($) |
Subsequent Events [Abstract] | |
Bank loan borrowings | $ 266 |
Summarized Quarterly Financia67
Summarized Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Selected Quarterly Financial Information [Abstract] | |||||||||||
Revenues from continuing operations | $ 189,301 | $ 222,503 | $ 207,998 | $ 219,309 | $ 319,050 | $ 288,608 | $ 296,063 | $ 326,299 | $ 839,111 | $ 1,230,020 | $ 933,404 |
Gain (loss) on commodity derivatives | 2 | 9,390 | (3,646) | 36,865 | 110,725 | 32,052 | (15,102) | (45,273) | 42,611 | 82,402 | (46,754) |
Expenses from continuing operations | 207,452 | 195,339 | 188,483 | 189,347 | 195,083 | 169,669 | 150,850 | 154,829 | 780,621 | 670,431 | |
Ceiling test and other impairments | 3,144,899 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | ||||
Interest expense | 43,494 | 43,137 | 42,619 | 42,668 | 42,196 | 29,599 | 27,294 | 27,068 | 171,918 | 126,157 | 101,486 |
Gain on sale of property | 8,022 | 0 | 0 | 0 | 0 | 8,022 | 0 | ||||
Other (expense) income, net | 903 | 2,354 | 1,827 | (992) | 5,311 | 2,582 | 2,688 | 2,590 | 4,092 | 13,171 | |
Income (loss) from continuing operations | (3,205,639) | (4,229) | (24,923) | 23,167 | 205,829 | 123,974 | 105,505 | 101,719 | (3,211,624) | 537,027 | 234,222 |
Income tax (benefit) | (999) | (1,133) | (250) | (2,022) | (3,901) | (1,383) | (544) | 4 | (4,404) | (5,824) | (3,616) |
Net income (loss) | $ (3,204,640) | $ (3,096) | $ (24,673) | $ 25,189 | $ 209,730 | $ 125,357 | $ 106,049 | $ 101,715 | $ (3,207,220) | $ 542,851 | $ 237,838 |
Net (income (loss) per common share - basic | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.37 | $ 0.82 | $ 0.69 | $ 0.66 | $ (20.94) | $ 3.54 | $ 1.55 |
Net income (loss) per common share - fully diluted | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.36 | $ 0.81 | $ 0.68 | $ 0.66 | $ (20.94) | $ 3.51 | $ 1.54 |
Disclosure About Oil and Gas 68
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details) Mcf in Thousands | 12 Months Ended | ||
Dec. 31, 2015bblMcf | Dec. 31, 2014bblMcf | Dec. 31, 2013bblMcf | |
Oil Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | 67,766,000 | 34,119,000 | 18,137,000 |
Extensions, discoveries and additions | 166,000 | 34,275,000 | 11,329,000 |
Sales | 0 | ||
Acquisitions | 9,381,000 | 10,114,000 | |
Production | (3,533,000) | (3,409,000) | (1,196,000) |
Revisions | (42,224,000) | (6,600,000) | (4,265,000) |
Reserves, Ending Balance | 22,175,000 | 67,766,000 | 34,119,000 |
Natural Gas Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | Mcf | 4,831,194 | 3,409,742 | 2,966,445 |
Extensions, discoveries and additions | Mcf | 17,415 | 866,513 | 1,409,528 |
Sales | Mcf | (239,290) | ||
Acquisitions | Mcf | 1,345,964 | 0 | |
Production | Mcf | (268,954) | (228,517) | (224,912) |
Revisions | Mcf | (2,243,375) | (323,218) | (741,319) |
Reserves, Ending Balance | Mcf | 2,336,280 | 4,831,194 | 3,409,742 |
Natural Gas Liquids Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | 21,993,000 | 0 | 0 |
Extensions, discoveries and additions | 3,000 | 210,000 | 0 |
Sales | 0 | ||
Acquisitions | 21,740,000 | 0 | |
Production | 0 | 0 | 0 |
Revisions | (12,156,000) | 43,000 | 0 |
Reserves, Ending Balance | 9,840,000 | 21,993,000 | 0 |
Disclosure About Oil and Gas 69
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 1) bbl in Thousands, Mcf in Thousands | Dec. 31, 2015bblMcf | Dec. 31, 2014bblMcf | Dec. 31, 2013bblMcf | Dec. 31, 2012bblMcf |
Oil Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | 22,175 | 28,481 | 20,566 | 10,531 |
Undeveloped | 0 | 39,285 | 13,553 | 7,606 |
Total Proved | 22,175 | 67,766 | 34,119 | 18,137 |
Natural Gas Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | Mcf | 2,336,280 | 2,245,004 | 1,777,267 | 1,820,994 |
Undeveloped | Mcf | 0 | 2,586,190 | 1,632,475 | 1,145,451 |
Total Proved | Mcf | 2,336,280 | 4,831,194 | 3,409,742 | 2,966,445 |
Natural Gas Liquids Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | 9,840 | 9,118 | 0 | 0 |
Undeveloped | 0 | 12,875 | 0 | 0 |
Total Proved | 9,840 | 21,993 | 0 | 0 |
Disclosure About Oil and Gas 70
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 2) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract | ||||
Future Cash Inflows | $ 6,312,095 | $ 27,331,391 | $ 14,861,131 | |
Future Production Costs | (3,006,265) | (8,627,657) | (4,540,209) | |
Future Development Costs | (358,848) | (3,859,385) | (2,014,751) | |
Future Income Taxes | 0 | (3,898,355) | (1,897,340) | |
Future Net Cash Flows | 2,946,982 | 10,945,994 | 6,408,831 | |
Discount at 10% | (1,081,333) | (5,712,511) | (3,220,862) | |
Standardized measure of discounted future net cash flows | $ 1,865,649 | $ 5,233,483 | $ 3,187,969 | $ 1,894,317 |
Disclosure About Oil and Gas 71
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized Measure, beginning | $ 5,233,483,000 | $ 3,187,969,000 | $ 1,894,317,000 |
Net revisions of previous quantity estimates | (2,126,998,000) | (603,795,000) | (1,089,316,000) |
Extensions, discoveries and other changes | 15,254,000 | 1,787,643,000 | 2,098,644,000 |
Sales of reserves in place | 0 | (398,506,000) | 0 |
Acquistion of reserves | 0 | 2,552,491,000 | 86,196,000 |
Changes in future development costs | 1,618,068,000 | (1,013,652,000) | (252,992,000) |
Sales of oil and gas, net of production costs | (550,879,000) | (949,389,000) | (720,826,000) |
Net change in prices and production costs | (6,996,416,000) | 1,010,052,000 | 1,204,041,000 |
Development costs incurred during the period that reduce future development costs | 548,112,000 | 342,987,000 | 171,149,000 |
Accretion of discount | 709,736,000 | 413,177,000 | 226,326,000 |
Net changes in production rates and other | 1,551,413,000 | (175,419,000) | 145,289,000 |
Net change in income taxes | 1,863,876,000 | (920,075,000) | (574,859,000) |
Aggregrate changes | (3,367,834,000) | 2,045,514,000 | 1,293,652,000 |
Standardized Measure, ending | $ 1,865,649,000 | $ 5,233,483,000 | $ 3,187,969,000 |
Disclosure About Oil and Gas 72
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 4) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||
Acquisition costs - unproved properties | $ 13,845 | $ 26,106 | $ 424,540 |
Acquisition costs - proved properties | 0 | 895,179 | 224,410 |
Exploration | 18,164 | 197,664 | 184,007 |
Development | 461,458 | 382,984 | 186,755 |
Total | $ 493,467 | $ 1,501,933 | $ 1,019,712 |
Disclosure About Oil and Gas 73
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 5) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract] | |||
Oil and gas revenue | $ 839,111 | $ 1,230,020 | $ 933,404 |
Production expenses | (288,231) | (280,631) | (212,578) |
Depletion and depreciation expense | (401,200) | (292,951) | (243,390) |
Write-downs of proved oil and gas properties | (3,144,899) | 0 | 0 |
Income taxes | (9,841) | 3,736 | (2,821) |
Total | $ (3,005,060) | $ 660,174 | $ 474,615 |
Disclosure About Oil and Gas 74
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Proven Properties [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $ 10,480,165 | $ 9,731,407 |
Less: Accumulated depletion, depreciation and amortization | (9,629,020) | (6,094,764) |
Proved | 851,145 | 3,636,643 |
Unproven Properties: | ||
Oil Gas Properties Using Full Cost Method Accounting Unproved | 0 | 242,294 |
Net capitalized costs - oil and gas properties | $ 851,145 | $ 3,878,937 |
Disclosure About Oil and Gas 75
Disclosure About Oil and Gas Producing Activities (Unaudited) (Narratives) (Details) | 12 Months Ended | |||
Dec. 31, 2015USD ($)BcfeTcfe | Dec. 31, 2013USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2011BcfeTcfe | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | ||||
Internal Engineer Experience | 14 | |||
Reserves Prepared Internally | 2.00% | |||
Expert Qualfications | The reserves estimates shown herein have been independently evaluated by 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. Robert C. Barg and Mr. Phillip R. Hodgson. Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 6 years of prior industry experience. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical 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. | |||
Proved Undeveloped Reserve Changes [Abstract] | ||||
Proved Undeveloped Reserve Conversions | Bcfe | 516.2 | |||
Proved Undeveloped Reserve Conversion Rate | 18.00% | |||
Proved Undeveloped Reserve Transfers To Unproven | Tcfe | 2.4 | |||
Total Proved Reserves Equivalent | Tcfe | 5 | |||
Proved Undeveloped Resesrves Reclassified in Pennsylvania | Bcfe | 106 | |||
Weighted Average Sales Price For Proved Reserves Textuals [Abstract] | ||||
Weighted Average Sales Price For Proved Reserves Natural Gas | $ 2.21 | $ 3.51 | $ 4.32 | |
Weighted Average Sales Price For Proved Reserves Condensate | 42.36 | 84.97 | 80.62 | |
Weighted Average Sales Price For Proved Reserves Natural Gas Liquids | $ 20.61 | $ 0 | $ 46.27 |
Supplemental Financial Informat
Supplemental Financial Information (Parent - Statement of Operations) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||||||||
Natural gas sales | $ 696,730 | $ 969,850 | $ 824,266 | ||||||||
Oil sales | 142,381 | 260,170 | 109,138 | ||||||||
Total operating revenues | $ 189,301 | $ 222,503 | $ 207,998 | $ 219,309 | $ 319,050 | $ 288,608 | $ 296,063 | $ 326,299 | 839,111 | 1,230,020 | 933,404 |
Expenses: | |||||||||||
Lease operating expenses | 106,906 | 96,496 | 68,106 | ||||||||
Liquids gathering system operating lease expense | 20,647 | 20,306 | 20,000 | ||||||||
Production taxes | 72,774 | 103,898 | 72,398 | ||||||||
Gathering fees | 87,904 | 59,931 | 52,074 | ||||||||
Transportation charges | 83,803 | 77,780 | 82,797 | ||||||||
Depletion and depreciation | 401,200 | 292,951 | 243,390 | ||||||||
Ceiling test and other impairments | 3,144,899 | 0 | 0 | 0 | 3,144,899 | 0 | 0 | ||||
General and Administrative Expense | 7,387 | 19,069 | 22,373 | ||||||||
Total operating expenses | 3,925,520 | 670,431 | 561,138 | ||||||||
Operating income (loss) | (3,086,409) | 559,589 | 372,266 | ||||||||
Other income (expense), net: | |||||||||||
Interest expense | (43,494) | (43,137) | (42,619) | (42,668) | (42,196) | (29,599) | (27,294) | (27,068) | (171,918) | (126,157) | (101,486) |
Gain (loss) on commodity derivatives | 2 | 9,390 | (3,646) | 36,865 | 110,725 | 32,052 | (15,102) | (45,273) | 42,611 | 82,402 | (46,754) |
Deferred gain on sale of liquids gathering system | 10,553 | 10,553 | 10,553 | ||||||||
Litigation expense | (4,401) | 0 | 0 | ||||||||
Gain on sale of property | 8,022 | 0 | 0 | 0 | 0 | 8,022 | 0 | ||||
Other income (expense) net | (2,060) | 2,618 | (357) | ||||||||
Total other income (expense), net | (125,215) | (22,562) | (138,044) | ||||||||
Income (loss) before income tax (benefit) | (3,205,639) | (4,229) | (24,923) | 23,167 | 205,829 | 123,974 | 105,505 | 101,719 | (3,211,624) | 537,027 | 234,222 |
Income tax (benefit) | (999) | (1,133) | (250) | (2,022) | (3,901) | (1,383) | (544) | 4 | (4,404) | (5,824) | (3,616) |
Net income (loss) | $ (3,204,640) | $ (3,096) | $ (24,673) | $ 25,189 | $ 209,730 | $ 125,357 | $ 106,049 | $ 101,715 | $ (3,207,220) | $ 542,851 | $ 237,838 |
Basic Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Basic | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.37 | $ 0.82 | $ 0.69 | $ 0.66 | $ (20.94) | $ 3.54 | $ 1.55 |
Fully Diluted Earnings (Loss) per Share: | |||||||||||
Earnings Per Share, Diluted | $ (20.91) | $ (0.02) | $ (0.16) | $ 0.16 | $ 1.36 | $ 0.81 | $ 0.68 | $ 0.66 | $ (20.94) | $ 3.51 | $ 1.54 |
Weighted average common shares outstanding - basic | 153,192,000 | 153,136,000 | 152,963,000 | ||||||||
Weighted average common shares outstanding - fully diluted | 153,192,000 | 154,694,000 | 154,426,000 | ||||||||
Parent [Member] | |||||||||||
Expenses: | |||||||||||
General and Administrative Expense | $ 308 | $ 261 | $ 102 | ||||||||
Other income (expense), net: | |||||||||||
Interest expense | (81,069) | (42,996) | (1,438) | ||||||||
Income from unconsolidated affiliates | (3,152,078) | 558,634 | 223,685 | ||||||||
Guarantee fee income | 23,029 | 23,045 | 22,406 | ||||||||
Other income (expense) net | (1,684) | (1,324) | (1,836) | ||||||||
Income (loss) before income tax (benefit) | (3,212,110) | 537,098 | 242,715 | ||||||||
Income tax (benefit) | (4,890) | (5,753) | 4,877 | ||||||||
Net income (loss) | $ (3,207,220) | $ 542,851 | $ 237,838 |
Supplemental Financial Inform77
Supplemental Financial Information (Parent - Balance Sheet) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current assets: | ||||
Cash and cash equivalents | $ 4,143,000 | $ 8,919,000 | $ 10,664,000 | $ 12,921,000 |
Restricted cash | 115,000 | 117,000 | ||
Oil and gas revenue receivable | 61,881,000 | 111,915,000 | ||
Joint interest billing and other receivables | 11,356,000 | 32,502,000 | ||
Derivative assets | 0 | 104,190,000 | ||
Income tax receivable | 5,150,000 | 6,246,000 | ||
Inventory | 4,269,000 | 10,216,000 | ||
Deferred financing costs | 20,477,000 | 0 | ||
Other current assets | 3,270,000 | 3,033,000 | ||
Total current assets | 110,661,000 | 277,138,000 | ||
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||||
Proven | 851,145,000 | 3,636,643,000 | ||
Unproven properties not being amortized | 0 | 242,294,000 | ||
Property, plant and equipment | 8,844,000 | 12,186,000 | ||
Deferred income taxes | 1,000 | 30,640,000 | ||
Other non-current assets | 835,000 | 26,789,000 | ||
Total assets | 971,486,000 | 4,225,690,000 | ||
Current liabilities: | ||||
Accounts payable | 93,415,000 | 77,580,000 | ||
Accrued and other current liabilities | 72,428,000 | 89,865,000 | ||
Production taxes payable | 52,273,000 | 55,585,000 | ||
Current maturities of long term debt | 3,390,000,000 | 100,000,000 | ||
Interest Payable Current | 42,657,000 | 46,098,000 | ||
Current deferred tax liabilities | 0 | 30,638,000 | ||
Derivative liabilities | 0 | 0 | ||
Capital cost accrual | 20,571,000 | 45,952,000 | ||
Total current liabilities | 3,671,344,000 | 445,718,000 | ||
Long-term debt | 0 | 3,278,000,000 | ||
Deferred income tax liability | 0 | 992,000 | ||
Deferred gain on sale of liquids gathering system | 126,295,000 | 136,848,000 | ||
Other long-term obligations | $ 165,784,000 | $ 152,472,000 | ||
Commitments and contingencies | ||||
Shareholders' equity: | ||||
Common stock - no par value; authorized - unlimited; issued and outstanding - 153,255,989 and 152,896,315, respectively | $ 502,050,000 | $ 495,913,000 | ||
Treasury stock | (176,000) | (6,213,000) | ||
Retained earnings | (3,493,811,000) | (278,040,000) | ||
Total shareholders' equity (deficit) | (2,991,937,000) | 211,660,000 | (331,490,000) | (577,867,000) |
Total liabilities and shareholders' equity | 971,486,000 | 4,225,690,000 | ||
Parent [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 523,000 | 772,000 | $ 629,000 | $ 3,455,000 |
Accounts receivable from related companies | 64,542,000 | 33,146,000 | ||
Other current assets | 21,918,000 | 6,246,000 | ||
Total current assets | 86,983,000 | 40,164,000 | ||
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||||
Other non-current assets | 24,197,000 | 27,339,000 | ||
Investment in unconsolidated affiliates | 0 | 1,461,226,000 | ||
Total assets | 111,180,000 | 1,528,729,000 | ||
Current liabilities: | ||||
Accrued and other current liabilities | 0 | 31,000 | ||
Current maturities of long term debt | 1,300,000,000 | 0 | ||
Interest Payable Current | 14,166,000 | 16,046,000 | ||
Total current liabilities | 1,314,166,000 | 16,077,000 | ||
Long-term debt | 0 | 1,300,000,000 | ||
Advances to unconsolidated affiliates | 1,788,951,000 | 0 | ||
Other long-term obligations | 0 | 992,000 | ||
Shareholders' equity: | ||||
Total shareholders' equity (deficit) | (2,991,937,000) | 211,660,000 | ||
Total liabilities and shareholders' equity | $ 111,180,000 | $ 1,528,729,000 |
Supplemental Financial Inform78
Supplemental Financial Information (Parent - Cash Flow Statement) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||||||
Depletion and depreciation | $ 401,200,000 | $ 292,951,000 | $ 243,390,000 | ||||
Ceiling test and other impairments | $ 3,144,899,000 | $ 0 | $ 0 | $ 0 | 3,144,899,000 | 0 | 0 |
Deferred and current non-cash income taxes | (990,000) | 995,000 | (6,000) | ||||
Unrealized loss (gain) on commodity derivatives | 104,190,000 | (130,066,000) | 25,876,000 | ||||
Deferred gain on sale of liquids gathering system | (10,553,000) | (10,553,000) | (10,553,000) | ||||
(Gain) on sale of property | 0 | (8,022,000) | 0 | ||||
Excess tax benefit from stock based compensation | 0 | 0 | 0 | ||||
Stock compensation | 4,128,000 | 5,467,000 | 9,767,000 | ||||
Other | 9,217,000 | 4,569,000 | 2,252,000 | ||||
Net changes in operating assets and liabilities: | |||||||
Restricted cash | 2,000 | 2,000 | 2,000 | ||||
Accounts receivable | 65,132,000 | (43,116,000) | 16,565,000 | ||||
Prepaid expenses and other | (20,106,000) | (1,920,000) | 1,180,000 | ||||
Other non-current assets | 21,112,000 | 284,000 | 277,000 | ||||
Accounts payable | 13,815,000 | 28,696,000 | (1,400,000) | ||||
Accrued liabilities | 1,655,000 | (5,938,000) | (32,904,000) | ||||
Production taxes payable | (3,312,000) | 15,115,000 | (7,207,000) | ||||
Interest payable | (3,441,000) | 14,233,000 | 1,772,000 | ||||
Other long-term obligations | (5,770,000) | 6,427,000 | 3,296,000 | ||||
Current taxes payable | 1,580,000 | 609,000 | (17,507,000) | ||||
Net cash provided by operating activities | 515,538,000 | 712,584,000 | 472,638,000 | ||||
Investing Activities: | |||||||
Acquisition costs | 3,964,000 | (891,075,000) | (649,801,000) | ||||
Oil and gas property expenditures | (494,025,000) | (599,913,000) | (370,662,000) | ||||
Gathering system expenditures | 0 | (6,842,000) | (5,510,000) | ||||
Proceeds from sale of property | 0 | 27,944,000 | 0 | ||||
Proceeds from sale of liquids gathering system | 0 | 0 | (129,000) | ||||
Proceeds from sale of marketable securities | 0 | 0 | 0 | ||||
Change in capital cost accrual | (25,380,000) | (125,577,000) | (65,975,000) | ||||
Inventory | 3,235,000 | 175,000 | (627,000) | ||||
Purchase of property, plant and equipment | (551,000) | (5,455,000) | (815,000) | ||||
Net cash used in investing activities | (512,757,000) | (1,600,743,000) | (1,093,519,000) | ||||
Financing activities: | |||||||
Borrowings on long-term debt | 1,165,000,000 | 1,095,000,000 | 1,006,000,000 | ||||
Payments on long-term debt | (1,153,000,000) | (1,037,000,000) | (823,000,000) | ||||
Proceeds from issuance of Senior Notes | 0 | 850,000,000 | 450,000,000 | ||||
Deferred financing costs | 6,000 | (13,245,000) | (8,958,000) | ||||
Repurchased shares/net share settlements | (2,514,000) | (9,111,000) | (5,429,000) | ||||
Shares re-issued from treasury | 0 | 0 | 0 | ||||
Excess tax benefit from stock based compensation | 0 | 0 | 0 | ||||
Payment of contingent consideration | (17,049,000) | 0 | 0 | ||||
Proceeds from exercise of options | 0 | 770,000 | 11,000 | ||||
Net cash provided by (used in) financing activities | (7,557,000) | 886,414,000 | 618,624,000 | ||||
(Decrease)/increase in cash during the period | (4,776,000) | (1,745,000) | (2,257,000) | ||||
Cash and cash equivalents, beginning of period | 8,919,000 | 8,919,000 | 10,664,000 | 12,921,000 | |||
Cash and cash equivalents, end of period | 4,143,000 | 4,143,000 | 8,919,000 | 10,664,000 | |||
Cash paid for: | |||||||
Interest | 169,867,000 | 108,889,000 | 99,542,000 | ||||
Income taxes | 0 | 1,752,000 | 13,843,000 | ||||
Non Cash Investing Activities Oil And Gas Properties | 0 | 20,000,000 | 12,651,000 | ||||
Parent [Member] | |||||||
Net changes in operating assets and liabilities: | |||||||
Net cash provided by operating activities | (101,277,000) | (35,818,000) | 17,772,000 | ||||
Investing Activities: | |||||||
Investment in subsidiary | 0 | (850,000,000) | (464,405,000) | ||||
Dividends received | 96,297,000 | 52,741,000 | 4,580,000 | ||||
Net cash used in investing activities | 96,297,000 | (797,259,000) | (459,825,000) | ||||
Financing activities: | |||||||
Proceeds from issuance of Senior Notes | 0 | 850,000,000 | 450,000,000 | ||||
Deferred financing costs | 6,000 | (13,245,000) | (8,958,000) | ||||
Repurchased shares/net share settlements | 0 | (6,471,000) | (3,311,000) | ||||
Shares re-issued from treasury | 4,725,000 | 2,936,000 | 1,496,000 | ||||
Net cash provided by (used in) financing activities | 4,731,000 | 833,220,000 | 439,227,000 | ||||
(Decrease)/increase in cash during the period | (249,000) | 143,000 | (2,826,000) | ||||
Cash and cash equivalents, beginning of period | $ 772,000 | 772,000 | 629,000 | 3,455,000 | |||
Cash and cash equivalents, end of period | $ 523,000 | $ 523,000 | $ 772,000 | $ 629,000 |