Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 11, 2015 | Jun. 30, 2014 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | Ultra Petroleum Corp. | ||
Entity Central Index Key | 1022646 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $4,548,975,499 | ||
Entity Common Stock, Shares Outstanding (actual number) | 152,901,361 | ||
Trading Symbol | UPL |
Consolidated_Statement_of_Oper
Consolidated Statement of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Natural gas sales | $969,850 | $824,266 | $695,733 |
Oil sales | 260,170 | 109,138 | 114,241 |
Total operating revenues | 1,230,020 | 933,404 | 809,974 |
Expenses: | |||
Lease operating expenses | 96,496 | 68,106 | 63,823 |
Liquids gathering system operating lease expense | 20,306 | 20,000 | 645 |
Production taxes | 103,898 | 72,398 | 60,757 |
Gathering fees | 59,931 | 52,074 | 59,004 |
Transportation charges | 77,780 | 82,797 | 84,470 |
Depletion and depreciation | 292,951 | 243,390 | 388,985 |
Ceiling test and other impairments | 0 | 0 | 2,972,464 |
General and Administrative Expense | 19,069 | 22,373 | 25,104 |
Total operating expenses | 670,431 | 561,138 | 3,655,252 |
Operating income (loss) | 559,589 | 372,266 | -2,845,278 |
Other income (expense), net: | |||
Interest expense | -126,157 | -101,486 | -88,180 |
Gain (loss) on commodity derivatives | 82,402 | -46,754 | 73,581 |
Deferred gain on sale of liquids gathering system | 10,553 | 10,553 | 0 |
Contract Cancellation Fees | 0 | 0 | -15,469 |
Gain on sale of property | 8,022 | 0 | 0 |
Other income (expense) net | 2,618 | -357 | -1,765 |
Total other income (expense), net | -22,562 | -138,044 | -31,833 |
Income (loss) before income tax (benefit) | 537,027 | 234,222 | -2,877,111 |
Income tax (benefit) | -5,824 | -3,616 | -700,213 |
Net income (loss) | $542,851 | $237,838 | ($2,176,898) |
Basic Earnings (Loss) per Share: | |||
Earnings Per Share, Basic | $3.54 | $1.55 | ($14.24) |
Fully Diluted Earnings (Loss) per Share: | |||
Earnings Per Share, Diluted | $3.51 | $1.54 | ($14.24) |
Weighted average common shares outstanding - basic | 153,136,000 | 152,963,000 | 152,845,000 |
Weighted average common shares outstanding - fully diluted | 154,694,000 | 154,426,000 | 152,845,000 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $8,919 | $10,664 |
Restricted cash | 117 | 119 |
Oil and gas revenue receivable | 111,915 | 84,095 |
Joint interest billing and other receivables | 32,502 | 17,725 |
Derivative assets | 104,190 | 1,415 |
Other current assets | 19,495 | 14,613 |
Total current assets | 277,138 | 128,631 |
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract] | ||
Proven | 3,636,643 | 2,008,538 |
Unproven properties not being amortized | 242,294 | 413,073 |
Property, plant and equipment | 12,186 | 216,909 |
Deferred income taxes | 30,640 | 6 |
Deferred financing costs and other | 26,789 | 18,162 |
Total assets | 4,225,690 | 2,785,319 |
Current liabilities: | ||
Accounts payable | 77,580 | 54,806 |
AccruedLiabilitiesCurrent | 89,865 | 79,811 |
Production taxes payable | 55,585 | 40,538 |
Senior Notes due March 2015 | 100,000 | 0 |
Interest Payable Current | 46,098 | 31,865 |
Current deferred tax liabilities | 30,638 | 0 |
Derivative liabilities | 0 | 27,291 |
Capital cost accrual | 45,952 | 173,165 |
Total current liabilities | 445,718 | 407,476 |
Long-term debt | 3,278,000 | 2,470,000 |
Deferred income tax liability | 992 | 0 |
Deferred gain on sale of liquids gathering system | 136,848 | 147,401 |
Other long-term obligations | 152,472 | 91,932 |
CommitmentsAndContingencies | ||
Shareholders' equity: | ||
Common stock - no par value; authorized - unlimited; issued and outstanding - 152,896,315 and 152,990,123, respectively | 495,913 | 487,273 |
Treasury stock | -6,213 | -1,961 |
Retained earnings | -278,040 | -816,802 |
Total shareholders' equity (deficit) | 211,660 | -331,490 |
Total liabilities and shareholders' equity | $4,225,690 | $2,785,319 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Consolidated Balance Sheets [Abstract] | ||
Common stock, no par value | $0 | $0 |
Common stock, shares authorized | unlimited | unlimited |
Common stock, shares issued | 152,896,315 | 152,990,123 |
Common stock, shares outstanding | 152,896,315 | 152,990,123 |
Statement_of_Shareholders_Equi
Statement of Shareholders Equity (USD $) | Total | Common Stock [Member] | Retained Earnings [Member] | Treasury Stock [Member] |
In Thousands, except Share data, unless otherwise specified | ||||
Beginning Balance at Dec. 31, 2011 | $1,593,709 | $463,221 | $1,145,439 | ($14,951) |
Beginning Balance, Shares at Dec. 31, 2011 | 152,477,000 | |||
Stock options exercised | 632 | 632 | ||
Stock options exercised, Shares | 34,000 | |||
Employee stock plan grants | 613 | 613 | 0 | |
Employee stock plan grants, Shares | 708,000 | |||
Shares re-issued from treasury | 0 | -1,245 | -14,793 | 16,038 |
Shares repurchased | -1,100 | -1,100 | ||
Shares repurchased, Shares | -50,000 | |||
Net share settlements | -5,618 | -5,618 | ||
Net share settlements, Shares | -239,000 | |||
Fair value of employee stock plan grants | 15,222 | 15,222 | ||
Tax benefit of stock options exercised | -4,427 | -4,427 | ||
Comprehensive earnings: | ||||
Net earnings (loss) | -2,176,898 | -2,176,898 | ||
Ending Balance at Dec. 31, 2012 | -577,867 | 474,016 | -1,051,870 | -13 |
Ending 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 | ||
Employee stock plan grants, Shares | 347,000 | |||
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 | ||
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 | |||
Stock options exercised | 770 | 770 | ||
Stock options exercised, Shares | 43,000 | |||
Employee stock plan grants | 700 | 700 | ||
Employee stock plan grants, Shares | 298,000 | |||
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 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Operating activities: | |||
Net (Loss) Income Attributable to Parent | $542,851,000 | $237,838,000 | ($2,176,898,000) |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||
Depletion and depreciation | 292,951,000 | 243,390,000 | 388,985,000 |
Ceiling test and other impairments | 0 | 0 | 2,972,464,000 |
Deferred and current non-cash income taxes | 995,000 | -6,000 | -712,576,000 |
Unrealized loss (gain) on commodity derivatives | -130,066,000 | 25,876,000 | 230,385,000 |
Deferred gain on sale of liquids gathering system | -10,553,000 | -10,553,000 | 0 |
(Gain) on sale of property | -8,022,000 | 0 | 0 |
Excess tax benefit from stock based compensation | 0 | 0 | 4,427,000 |
Stock compensation | 5,467,000 | 9,767,000 | 10,756,000 |
Other | 4,569,000 | 2,252,000 | 3,667,000 |
Net changes in operating assets and liabilities: | |||
Restricted cash | 2,000 | 2,000 | 0 |
Accounts receivable | -43,116,000 | 16,565,000 | 62,758,000 |
Prepaid expenses and other | -1,920,000 | 1,180,000 | 1,740,000 |
Other non-current assets | 284,000 | 277,000 | 284,000 |
Accounts payable | 28,696,000 | -1,400,000 | -37,964,000 |
Accrued liabilities | -5,938,000 | -32,904,000 | -77,633,000 |
Production taxes payable | 15,115,000 | -7,207,000 | -14,372,000 |
Interest payable | 14,233,000 | 1,772,000 | -213,000 |
Other long-term obligations | 6,427,000 | 3,296,000 | -9,031,000 |
Current taxes payable | 609,000 | -17,507,000 | 8,046,000 |
Net cash provided by operating activities | 712,584,000 | 472,638,000 | 654,825,000 |
Investing Activities: | |||
Acquisition costs | -891,075,000 | -649,801,000 | 0 |
Oil and gas property expenditures | -599,913,000 | -370,662,000 | -708,017,000 |
Gathering system expenditures | -6,842,000 | -5,510,000 | -127,149,000 |
Proceeds from sale of property | 27,944,000 | 0 | 0 |
Proceeds from sale of liquids gathering system | 0 | -129,000 | 203,046,000 |
Proceeds from sale of marketable securities | 0 | 0 | 21,235,000 |
Change in capital cost accrual | -125,577,000 | -65,975,000 | 38,338,000 |
Inventory | 175,000 | -627,000 | -374,000 |
Purchase of property, plant and equipment | -5,455,000 | -815,000 | -4,302,000 |
Net cash used in investing activities | -1,600,743,000 | -1,093,519,000 | -577,223,000 |
Financing activities: | |||
Borrowings on long-term debt | 1,095,000,000 | 1,006,000,000 | 852,000,000 |
Payments on long-term debt | -1,037,000,000 | -823,000,000 | -918,000,000 |
Proceeds from issuance of Senior Notes | 850,000,000 | 450,000,000 | 0 |
Deferred financing costs | -13,245,000 | -8,958,000 | 0 |
Repurchased shares/net share settlements | -9,111,000 | -5,429,000 | -6,718,000 |
Excess tax benefit from stock based compensation | 0 | 0 | -4,427,000 |
Proceeds from exercise of options | 770,000 | 11,000 | 1,157,000 |
Net cash provided by (used in) financing activities | 886,414,000 | 618,624,000 | -75,988,000 |
(Decrease)/increase in cash during the period | -1,745,000 | -2,257,000 | 1,614,000 |
Cash and cash equivalents, beginning of period | 10,664,000 | 12,921,000 | 11,307,000 |
Cash and cash equivalents, end of period | 8,919,000 | 10,664,000 | 12,921,000 |
Cash paid for: | |||
Interest | 108,889,000 | 99,542,000 | 101,237,000 |
Income taxes | 1,752,000 | 13,843,000 | 4,379,000 |
Non Cash Investing Activities Oil And Gas Properties | $20,000,000 | $12,651,000 | $0 |
Significant_Accounting_Policie
Significant Accounting Policies | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Significant Accounting Policies Disclosures [Abstract] | |||||||||
SIGNIFICANT ACCOUNTING POLICIES | 1. SIGNIFICANT ACCOUNTING POLICIES: | ||||||||
(a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts 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 consolidation. | |||||||||
(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 production 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 instruments. The Company routinely assesses the collectability of all material trade and other receivables. | |||||||||
(e) Property, plant and equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. 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 (See Note 13), 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 was transferred 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”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Separate cost centers are maintained for each country in which the Company incurs costs. 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 activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between 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 proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion. | |||||||||
Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized. | |||||||||
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. | |||||||||
During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2014 or 2013. | |||||||||
(g) Inventories: At December 31, 2014 and 2013, inventory of $10.2 million and $5.2 million primarily includes the cost of pipe and production equipment that will be utilized during the 2015 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 and 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 Company 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) Income taxes: Income taxes 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 be 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 likely 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 position following an audit. | |||||||||
The Company has recorded a valuation allowance against certain deferred tax assets of $161.5 million as of December 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income. | |||||||||
(j) 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 income (loss) per common share: | |||||||||
December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Net income (loss) | $ | 542,851 | $ | 237,838 | $ | -2,176,898 | |||
Weighted average common shares outstanding | |||||||||
during the period | 153,136 | 152,963 | 152,845 | ||||||
Effect of dilutive instruments | 1,558 | 1,463 | - | -1 | |||||
Weighted average common shares outstanding during | |||||||||
the period including the effects of dilutive instruments | 154,694 | 154,426 | 152,845 | ||||||
Net income (loss) per common share - basic | $ | 3.54 | $ | 1.55 | $ | -14.24 | |||
Net income (loss) per common share - fully diluted | $ | 3.51 | $ | 1.54 | $ | -14.24 | |||
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 | 1,377 | 1,406 | - | -1 | |||||
(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share. | |||||||||
(k) 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. | |||||||||
(l) Accounting for share-based compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. | |||||||||
(m) Fair value accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information. | |||||||||
(n) Asset retirement obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets. | |||||||||
(o) 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 natural 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, 2014 and 2013, the Company had a net natural gas imbalance liability of $3.0 million and $3.3 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 allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. | |||||||||
(p) 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 work in process relating to gathering systems that are not currently in service. | |||||||||
(q) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. | |||||||||
(r) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. | |||||||||
(s) Recent accounting pronouncements: In August 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require 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 an interim and annual basis. Management will be 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. | |||||||||
In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which supersedes 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. ASU No. 2014-09 becomes effective at the beginning of 2017. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations. | |||||||||
In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Asset Retirement Obligations Disclosure [Abstract] | |||||||
ASSET RETIREMENT OBLIGATIONS | 2. ASSET RETIREMENT OBLIGATIONS: | ||||||
The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended: | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Asset retirement obligations at beginning of period | $ | 72,807 | $ | 60,814 | |||
Accretion expense | 6,571 | 5,171 | |||||
Liabilities incurred | 10,242 | 7,730 | |||||
Liabilities acquired(1) | 53,270 | - | |||||
Liabilities divested(1) | -15,760 | - | |||||
Liabilities settled | -336 | -2,334 | |||||
Revisions of estimated liabilities | 446 | 1,426 | |||||
Asset retirement obligations at end of period | 127,240 | 72,807 | |||||
Less: current asset retirement obligations | -417 | -96 | |||||
Long-term asset retirement obligations | $ | 126,823 | $ | 72,711 | |||
(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 (See Note 13 for further details). |
Oil_and_Gas_Properties
Oil and Gas Properties | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Oil and Gas Properties And Equipment Tables [Abstract] | ||||||||||||
OIL AND GAS PROPERTIES | 3. OIL AND GAS PROPERTIES: | |||||||||||
December 31, | December 31, | |||||||||||
2014 | 2013 | |||||||||||
Proven Properties: | ||||||||||||
Acquisition, equipment, exploration, drilling and environmental costs(2), (3) | $ | 9,731,407 | $ | 7,817,374 | ||||||||
Less: Accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||||||
3,636,643 | 2,008,538 | |||||||||||
Unproven Properties: | ||||||||||||
Acquisition and exploration costs not being amortized (1), (2) | 242,294 | 413,073 | ||||||||||
Net capitalized costs - oil and gas properties | $ | 3,878,937 | $ | 2,421,611 | ||||||||
On a unit basis, DD&A from continuing operations was $1.18, $1.05 and $1.51 per Mcfe for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||||
(1) 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 work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service. | ||||||||||||
(2) On December 12, 2013 the Company, through its subsidiary, UPL Three Rivers Holdings, LLC, closed on the acquisition of crude oil assets located in Three Rivers Field in Uintah County, Utah. The assets consist of producing wells, undeveloped acreage and water and gas gathering assets. | ||||||||||||
(3) On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming (the “SWEPI Properties”) from SWEPI, LP, an affiliate of Royal Dutch Shell, plc in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania (the “Pennsylvania Properties”) and a cash payment. See Note 13. | ||||||||||||
Unproven Properties | ||||||||||||
The Company holds interests in domestic projects in which costs related to these interests are not being depleted pending determination of existence of estimated proved reserves. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized. | ||||||||||||
Total | 2014 | 2013 | 2012 | Prior | ||||||||
Acquisition costs | $ | 228,516 | $ | -191,184 | $ | 419,700 | $ | -481,689 | $ | 481,689 | ||
Exploration costs | -7,708 | 173 | -7,881 | -9,962 | 9,962 | |||||||
Capitalized interest | 21,486 | 20,232 | 1,254 | -45,875 | 45,875 | |||||||
Unproven properties | $ | 242,294 | $ | -170,779 | $ | 413,073 | $ | -537,526 | $ | 537,526 |
Property_Plant_and_Equipment
Property, Plant and Equipment | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property Plant And Equipment Disclosure [Abstract] | |||||||||
PROPERTY, PLANT AND EQUIPMENT | 4. PROPERTY, PLANT AND EQUIPMENT: | ||||||||
December 31, | |||||||||
2014 | 2013 | ||||||||
Cost | Accumulated Depreciation | Net Book Value | Net Book Value | ||||||
Gathering systems(1)(2) | $ | - | $ | - | $ | - | $ | 189,110 | |
Computer equipment | 2,967 | -2,050 | 917 | 892 | |||||
Office equipment | 467 | -410 | 57 | 41 | |||||
Leasehold improvements | 471 | -360 | 111 | 136 | |||||
Land(3) | 5,778 | - | 5,778 | 22,359 | |||||
Other | 13,656 | -8,333 | 5,323 | 4,371 | |||||
Property, plant and equipment, net | $ | 23,339 | $ | -11,153 | $ | 12,186 | $ | 216,909 | |
(1)Historically, 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 (See Note 13), 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 has been transferred to proven oil and gas properties. | |||||||||
(2)On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania and a cash payment (See Note 13 for further details). | |||||||||
(3)During November 2014, the Company sold certain real property in El Paso County, Colorado for proceeds of $27.9 million. |
Long_Term_Liabilities
Long Term Liabilities | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Long Term Liabilities Tables [Abstract] | |||||||||||||||
LONG-TERM LIABILITIES | 5. DEBT AND OTHER LONG-TERM LIABILITIES: | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2014 | 2013 | ||||||||||||||
Short-term debt: | |||||||||||||||
Senior Notes due March 2015 | $ | 100,000 | $ | - | |||||||||||
Long-term debt and other long-term liabilities: | |||||||||||||||
Bank indebtedness | 518,000 | 460,000 | |||||||||||||
Senior notes | 2,760,000 | 2,010,000 | |||||||||||||
Other long-term obligations | 152,472 | 91,932 | |||||||||||||
$ | 3,530,472 | $ | 2,561,932 | ||||||||||||
Aggregate maturities of debt at December 31, 2014: | |||||||||||||||
Beyond | |||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 5 years | Total | |||||||||
$ | 100,000 | $ | 580,000 | $ | 116,000 | $ | 650,000 | $ | 173,000 | $ | 1,759,000 | $ | 3,378,000 | ||
Ultra Resources, Inc. Bank Indebtedness – | |||||||||||||||
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 loan 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 successive one-year periods at the Borrower’s request. At December 31, 2014, the Company had $518.0 million in outstanding borrowings and $482.0 million of available borrowing capacity under the Credit Agreement. | |||||||||||||||
Loans under the Credit Agreement 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 Resources, Inc.’s consolidated leverage ratio (100 basis points as of December 31, 2014) 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 (200 basis points per annum as of December 31, 2014). 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, 2014, the Company incurred $2.0 million in commitment fees associated with its credit facility. | |||||||||||||||
The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants 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 value 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, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement. | |||||||||||||||
Ultra Resources, Inc. Senior Notes – | |||||||||||||||
Ultra Resources also has outstanding $1.56 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. 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 similar to those in the Credit Facility. At December 31, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes. | |||||||||||||||
Ultra Petroleum Corp. Senior Notes – | |||||||||||||||
Senior Notes due 2024: On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and 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, 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%). The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At December 31, 2014, 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% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and 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 prices 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 distributions 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, 2014, the Company was in compliance with all of its debt covenants under the 2018 Notes. | |||||||||||||||
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, 2014 | ||||||||||||
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 importance 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 Company’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 retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the Plans permit the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions and estimates forfeitures that may occur. The Committee may grant awards under the 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Total cost of share-based payment plans | $ | 8,640 | $ | 13,957 | $ | 15,835 | ||||||
Amounts capitalized in oil and gas properties and equipment | $ | 3,173 | $ | 4,190 | $ | 5,079 | ||||||
Amounts charged against income, before | ||||||||||||
income tax benefit | $ | 5,467 | $ | 9,767 | $ | 10,756 | ||||||
Amount of related income tax benefit recognized | ||||||||||||
in income before valuation allowances | $ | 2,285 | $ | 4,083 | $ | 4,463 | ||||||
Securities Authorized for Issuance Under Equity Compensation Plans | ||||||||||||
As of December 31, 2014, 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 | 690 | $56.58 | 2,608 | |||||||||
Equity compensation plans not approved | ||||||||||||
by security holders | n/a | n/a | n/a | |||||||||
Total | 690 | $56.58 | 2,608 | |||||||||
Changes in Stock Options and Stock Options Outstanding | ||||||||||||
The following table summarizes the changes in stock options for the three year period ended December 31, 2014: | ||||||||||||
Weighted | ||||||||||||
Average | ||||||||||||
Number of | Exercise Price | |||||||||||
Options | (US$) | |||||||||||
(000's) | ||||||||||||
Balance, December 31, 2011 | 1,459 | $16.97 | to | $98.87 | ||||||||
Forfeited | -68 | $25.08 | to | $75.18 | ||||||||
Exercised | -34 | $16.97 | to | $19.18 | ||||||||
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 | ||||||||
The following table summarizes information about the stock options outstanding and exercisable at December 31, 2014: | ||||||||||||
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) | |||||||||||
$ | 25.68 | - | $ | 53.39 | 126 | 0.64 | $44.25 | $- | ||||
$ | 50.15 | - | $ | 65.04 | 125 | 1.55 | $57.00 | $- | ||||
$ | 49.05 | - | $ | 62.23 | 281 | 2.28 | $53.85 | $- | ||||
$ | 51.6 | - | $ | 98.87 | 158 | 3.43 | $70.92 | $- | ||||
The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $13.16 per share on December 31, 2014, 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, 2014. | ||||||||||||
The following table summarizes information about the weighted-average grant-date fair value of share options: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Options forfeited during the year | $ | 24.4 | $ | 25.44 | $ | 27.05 | ||||||
As of December 31, 2011, all options were fully vested; therefore, no options vested during the years ended December 31, 2014, 2013 or 2012. The total intrinsic value of stock options exercised during the years ended December 31, 2014, 2013 and 2012 was $0.4 million, immaterial and $0.3 million, respectively. | ||||||||||||
At December 31, 2014, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011. | ||||||||||||
PERFORMANCE SHARE PLANS: | ||||||||||||
Long Term Incentive Plans. The Company offers 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. In 2012, 2013 and 2014, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant. | ||||||||||||
For each LTIP award, the Committee establishes performance measures at the beginning of each three-year performance period. Under each LTIP, the Committee also establishes a percentage of base salary for each participant which 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 that actual performance is below or above target levels. For the LTIP awards in 2012, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth. For the LTIP awards in 2014 and 2013, the Committee established the following performance measures: return on capital employed, debt level, reserve replacement ratio, and total shareholder return (officers only). | ||||||||||||
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 of restricted stock units. For the year ended December 31, 2013, the Company recognized $6.9 million in pre-tax compensation expense related to the 2011, 2012 and 2013 LTIP awards of restricted stock units. For the year ended December 31, 2012, the Company recognized $7.9 million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units. The amounts recognized during the year ended December 31, 2014 assumes that performance objectives between target and maximum are attained for the 2012 LTIP and maximum performance objectives are attained under the 2013 LTIP and 2014 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2014, for each of the three year performance periods is expected to be approximately $10.2 million, $12.6 million, and $13.0 million related to the 2012, 2013 and 2014 LTIP awards of restricted stock units, respectively. The 2011 LTIP Common Stock Award was paid in shares of the Company’s stock to employees during the first quarter of 2014 and totaled $8.4 million (106,437 net shares). |
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Financial Instruments Disclosure [Abstract] | ||||||||||||
DERIVATIVE FINANCIAL INSTRUMENTS | 7. DERIVATIVE FINANCIAL INSTRUMENTS: | |||||||||||
Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise. | ||||||||||||
The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program. | ||||||||||||
The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. | ||||||||||||
Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments. | ||||||||||||
Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Consolidated Statements of Cash Flows. | ||||||||||||
Commodity Derivative Contracts: At December 31, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties. | ||||||||||||
Natural Gas: | ||||||||||||
Type | Commodity Reference Price | Remaining Contract Period | Volume - MMBTU/Day | Average Price/MMBTU | Fair Value - December 31, 2014 | |||||||
Asset | ||||||||||||
Swap | NYMEX-Henry Hub | Jan - Mar 2015 | 210,000 | $4.54 | $ | 29,201 | ||||||
Swap | NYMEX-Henry Hub | Apr - Oct 2015 | 522,500 | $3.65 | $ | 74,989 | ||||||
Subsequent to December 31, 2014 and through February 11, 2015, the Company has entered into the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price: | ||||||||||||
Natural Gas: | ||||||||||||
Type | Commodity Reference Price | Remaining Contract Period | Volume - MMBTU/Day | Average Price/MMBTU | ||||||||
Swap | NYMEX-Henry Hub | Apr - Oct 2015 | 150,000 | $2.98 | ||||||||
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, 2014, 2013 and 2012: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
Commodity Derivatives: | 2014 | 2013 | 2012 | |||||||||
Realized (loss) gain on commodity derivatives-natural gas (1) | $ | -48,170 | $ | -20,552 | $ | 303,966 | ||||||
Realized gain (loss) on commodity derivatives-crude oil (1) | 506 | -326 | - | |||||||||
Unrealized gain (loss) on commodity derivatives (1) | 130,066 | -25,876 | -230,385 | |||||||||
Total gain (loss) on commodity derivatives | $ | 82,402 | $ | -46,754 | $ | 73,581 | ||||||
(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, 2014 | ||||||||||
Fair Value Disclosures [Abstract] | ||||||||||
FAIR VALUE MEASUREMENTS | 8. FAIR VALUE MEASUREMENTS: | |||||||||
As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories: | ||||||||||
Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. | ||||||||||
Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps. | ||||||||||
Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. | ||||||||||
The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). | ||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||
Assets: | ||||||||||
Current derivative asset | $ | - | $ | 104,190 | $ | - | $ | 104,190 | ||
In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. | ||||||||||
Assets and Liabilities Measured on a Non-recurring Basis | ||||||||||
The Company uses fair value to determine the value of its asset retirement obligations (“ARO”). The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs. | ||||||||||
Fair Value of Financial Instruments | ||||||||||
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt. The inputs utilized to estimate the fair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows. | ||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||
Carrying | Estimated | Carrying | Estimated | |||||||
Amount | Fair Value | Amount | Fair Value | |||||||
5.45% Notes due March 2015, issued 2008 | $ | 100,000 | $ | 101,931 | $ | 100,000 | $ | 105,913 | ||
7.31% Notes due March 2016, issued 2009 | 62,000 | 65,027 | 62,000 | 70,228 | ||||||
4.98% Notes due January 2017, issued 2010 | 116,000 | 116,240 | 116,000 | 126,342 | ||||||
5.92% Notes due March 2018, issued 2008 | 200,000 | 203,738 | 200,000 | 226,127 | ||||||
5.75% Notes due December 2018, issued 2013 | 450,000 | 414,505 | 450,000 | 466,946 | ||||||
7.77% Notes due March 2019, issued 2009 | 173,000 | 187,105 | 173,000 | 211,877 | ||||||
5.50% Notes due January 2020, issued 2010 | 207,000 | 201,371 | 207,000 | 229,068 | ||||||
4.51% Notes due October 2020, issued 2010 | 315,000 | 283,335 | 315,000 | 323,732 | ||||||
5.60% Notes due January 2022, issued 2010 | 87,000 | 82,581 | 87,000 | 95,736 | ||||||
4.66% Notes due October 2022, issued 2010 | 35,000 | 30,476 | 35,000 | 35,494 | ||||||
6.125% Notes due October 2024, issued 2014 | 850,000 | 754,485 | - | - | ||||||
5.85% Notes due January 2025, issued 2010 | 90,000 | 83,876 | 90,000 | 99,142 | ||||||
4.91% Notes due October 2025, issued 2010 | 175,000 | 147,649 | 175,000 | 175,744 | ||||||
Credit Facility due October 2016 | 518,000 | 518,000 | 460,000 | 460,000 | ||||||
$ | 3,378,000 | $ | 3,190,319 | $ | 2,470,000 | $ | 2,626,349 |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Income Taxes Disclosure [Abstract] | |||||||
INCOME TAXES | 9. INCOME TAXES: | ||||||
Income (loss) before income tax benefit is as follows: | |||||||
Year Ended December 31, | |||||||
2014 | 2013 | 2012 | |||||
United States | $ | 505,689 | $ | 210,580 | $ | -2,892,207 | |
Foreign | 31,338 | 23,642 | 15,096 | ||||
Total | $ | 537,027 | $ | 234,222 | $ | -2,877,111 | |
The consolidated income tax (benefit) provision is comprised of the following: | |||||||
Year Ended December 31, | |||||||
2014 | 2013 | 2012 | |||||
Current tax: | |||||||
U.S. federal, state and local | $ | -110 | $ | -8,491 | $ | 9,037 | |
Foreign | -6,709 | 4,881 | 3,326 | ||||
(Reduction in) current tax benefit on stock based compensation: | |||||||
U.S. federal, state and local | - | - | -4,427 | ||||
Total current tax expense (benefit) | -6,819 | -3,610 | 7,936 | ||||
Deferred tax: | |||||||
U.S. federal, state and local | - | - | -708,160 | ||||
Foreign | 995 | -6 | 11 | ||||
Total deferred tax expense (benefit) | 995 | -6 | -708,149 | ||||
Total income tax (benefit) provision | $ | -5,824 | $ | -3,616 | $ | -700,213 | |
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, | |||||||
2014 | 2013 | 2012 | |||||
Income tax provision (benefit) computed at the U.S. statutory rate | $ | 187,959 | $ | 81,978 | $ | -1,006,989 | |
State income tax provision (benefit) net of federal benefit | 8,023 | 1,329 | -136,112 | ||||
Valuation allowance | -199,038 | -81,923 | 446,148 | ||||
Tax effect of rate change | 15,457 | -2,871 | 1,358 | ||||
Foreign rate differential | -16,314 | -3,508 | -5,531 | ||||
Other, net | -1,911 | 1,379 | 913 | ||||
Total income tax (benefit) provision | $ | -5,824 | $ | -3,616 | $ | -700,213 | |
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, | |||||||
2014 | 2013 | ||||||
Deferred tax assets - current: | |||||||
Derivative instruments, net | $ | - | $ | 9,636 | |||
Incentive compensation/other, net | 6,150 | 7,641 | |||||
6,150 | 17,277 | ||||||
Valuation allowance | - | -16,778 | |||||
Net deferred tax assets - current | $ | 6,150 | $ | 499 | |||
Deferred tax liabilities - current: | |||||||
Derivative instruments, net | $ | 36,788 | $ | 499 | |||
Net deferred tax liabilities - current | $ | 36,788 | $ | 499 | |||
Net deferred tax liability - current | $ | 30,638 | $ | - | |||
Deferred tax assets - non-current: | |||||||
Property and equipment | - | 131,340 | |||||
Deferred gain | 48,319 | 52,045 | |||||
U.S. federal tax credit carryforwards | 16,144 | 16,254 | |||||
U.S. net operating loss carryforwards | 147,336 | 71,843 | |||||
U.S. state net operating loss carryforwards | 53,654 | 36,205 | |||||
Asset retirement obligations | 45,039 | 26,876 | |||||
Incentive compensation/other, net | 19,142 | 13,007 | |||||
329,634 | 347,570 | ||||||
Valuation allowance | -161,480 | -346,596 | |||||
Net deferred tax assets - non-current | $ | 168,154 | $ | 974 | |||
Deferred tax liabilities - non-current: | |||||||
Property and equipment | 137,514 | - | |||||
Other | - | 968 | |||||
Net non-current tax liabilities | $ | 137,514 | $ | 968 | |||
Net non-current tax asset | $ | 30,640 | $ | 6 | |||
Deferred tax liabilities - non-current: | |||||||
Other - non-US | 992 | - | |||||
In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies. | |||||||
At December 31, 2014 and 2013, the Company recorded a valuation allowance against certain deferred tax assets of $161.5 million and $363.4 million, respectively. Some or all of this valuation allowance may be reversed in future periods against future income. The Company’s valuation allowance changed by $201.9 million from December 31, 2013 to December 31, 2014. Of this amount, $199.0 million reduced the Company’s current year deferred tax expense, and $2.9 million was reflected through shareholders’ equity. | |||||||
As of December 31, 2014, the Company had approximately $14.1 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. The Company has $0.5 million of general business credits available to offset U.S. federal income taxes. These general business credits expire in 2032. In addition, the Company has $1.7 million of foreign tax credit carryforwards, none of which expire prior to 2017. | |||||||
The Company generated a U.S. federal tax loss of $214.9 million and $260.1 million for the years ended December 31, 2014 and 2013, respectively. Of the 2013 loss, $54.5 million was carried back to offset taxable income generated in prior tax years. An income tax receivable of $8.0 million was recorded at December 31, 2013 and was reflected as a reduction in income tax expense in the Consolidated Statements of Operations for the year ended December 31, 2013. The remaining U.S. federal tax net operating loss of $420.9 million will be carried forward to offset taxable income generated in future years, and if unutilized, will expire in 2033 and 2034. The Company has Pennsylvania state tax net operating loss carry forwards of $798.4 million which will expire between 2031 and 2034. The Company has immaterial state tax net operating loss carry forwards in other jurisdictions, none of which expire prior to 2020. | |||||||
The Company generated a Canada Federal and Provincial tax loss of $23.8 million for the year ended December 31, 2014. This loss will be carried back to offset taxable income generated in the prior three tax years. An income tax receivable of $6.2 million has been recorded at December 31, 2014 and is reflected as a reduction in 2014 income tax expense in the Consolidated Statement of Operations. As a result of this carryback, no Canada Federal and Provincial tax loss will be carried forward to offset taxable income generated in future years. | |||||||
The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2014. | |||||||
Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits. | |||||||
The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. With certain exceptions, the income tax years 2011 through 2014 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, 2014 | |
Compensation And Retirement Disclosure [Abstract] | |
EMPLOYEE BENEFITS | 10. EMPLOYEE BENEFITS: |
The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $2.0 million, $1.6 million and $1.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitements And Contingencies Disclosures [Abstract] | |
COMMITMENTS AND CONTINGENCIES | 11. COMMITMENTS AND CONTINGENCIES: |
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 ultimate terminus in eastern Ohio. The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas through November 2019, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. | |
Subsequently, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity provides the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S. | |
The Company currently projects that demand charges related to the remaining term of the contract will total approximately $469.0 million. | |
Operating lease. During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Lease Agreement”) relating to the use of the LGS. The 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 LGS at the sole discretion of the Company. Annual rent for the initial term under the 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 Lease Agreement will total approximately $268.0 million. | |
All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases. | |
Drilling contracts. As of December 31, 2014, the Company had committed to drilling obligations totaling $33.0 million ($31.6 million in 2015 and the remainder in 2016). The commitments expire in 2016 and were entered into to fulfill the Company’s drilling program initiatives. | |
Office space lease. The Company maintains office space in Colorado, Texas, Wyoming and Pennsylvania with total remaining commitments for office leases of $8.6 million at December 31, 2014 ($1.0 million in 2015; $1.3 million in 2016; $1.3 million in 2017; $1.2 million in 2018; and $1.1 million in 2019 with the remainder due beyond five years). | |
During the years ended December 31, 2014, 2013 and 2012, the Company recognized expense associated with its office leases in the amount of $1.0 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, 2015, the Company has long-term natural gas delivery commitments of 1.2 MMMBtu in 2015, 26.2 MMMBtu in 2016, and 7.9 MMMBtu in 2017 under existing agreements. As of February 9, 2015, the Company has long-term crude oil delivery commitments of 2.4 MMBbls in 2015, 2.4 MMBbls in 2016, 1.7 MMBbls in 2017, 0.7 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. | |
These committed volumes are below the Company’s forecasted 2015 and anticipated 2016 through 2019 production from its available reserves. 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”. The Company believes that its reserves are adequate to meet its commitments. If for some reason the Company’s production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments. | |
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 counsel, 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, 2014 | |
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 end-users in various industries. | |
Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time. | |
The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2014. | |
A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2014, the Company had no single customer that represented 10% or more of its total revenues. |
Completion_of_Acquisition_and_
Completion of Acquisition and Disposition of Assets | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Business Combination Description [Abstract] | ||||||
COMPLETION OF ACQUISITION AND DISPOSITION OF ASSETS | 13. COMPLETION OF ACQUISITION AND DISPOSITION OF ASSETS: | |||||
On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming (the “SWEPI Properties”) from SWEPI LP, an affiliate of Royal Dutch Shell, plc in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania (the “Pennsylvania Properties”) and a cash payment of $925.0 million (the “SWEPI Transaction”) pursuant to a Purchase and Sale Agreement dated August 13, 2014 (“PSA”). In connection with the transaction, the Company settled certain liabilities with SWEPI, LP that were incurred prior to the effective date. The effective date of the transaction is April 1, 2014. | ||||||
On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”) in order to finance a portion of the purchase price of the SWEPI Transaction. The remainder of the cash payment was funded through borrowings under the Company’s senior revolving credit facility. See Note 5. | ||||||
The costs related to the issuance of the 2024 Notes of $13.1 million are included with deferred financing costs and other on the Consolidated Balance Sheets and will be amortized over the term of the 2024 Notes. Additionally, the Company incurred $0.6 million of costs associated with the acquisition, which are included with general and administrative expenses in the Consolidated Statements of Operations. | ||||||
The SWEPI Properties that we acquired consist primarily of 19,600 net mineral acres in Wyoming and associated oil and gas production and wells and the Pennsylvania Properties that we sold consist primarily of 155,000 net acres in Pennsylvania and associated oil and gas production and wells. The transaction represents a strategic repositioning of the Company’s portfolio. The Company expects the acquisition will lead to improved returns, increased reserves, higher value markets in which to sell production, and increased control of capital allocation. | ||||||
The transaction was accounted for as a business combination and after customary effective-date adjustments and closing adjustments, the adjusted cash payment on the closing date of September 25, 2014 was $890.8 million and is subject to further post-closing adjustments. The adjusted cash payment was allocated to assets and liabilities based upon fair values at the closing date. There was no gain or loss recognized on the disposition of the Pennsylvania Properties since the relationship between capitalized costs and proved reserves of oil and natural gas was not significantly altered. | ||||||
The adjusted cash payment was allocated to assets and liabilities based upon fair values at the closing date as follows: | ||||||
Adjusted cash payment | $890,785 | |||||
Assets: | ||||||
Joint interest billing and other receivables - SWEPI Properties | -4,182 | |||||
Other current assets: | ||||||
Acquired condensate inventory - SWEPI Properties | 819 | |||||
Acquired yard inventory - SWEPI Properties | 3,515 | |||||
Subtotal - Other current assets | 4,334 | |||||
Proven oil and gas properties | 1,033,960 | |||||
Property, plant and equipment: | ||||||
Divested gathering system - Pennsylvania Properties | -98,580 | |||||
Acquired other fixed assets - SWEPI Properties | 869 | |||||
Divested other fixed assets - Pennsylvania Properties | -50 | |||||
Subtotal - Property, plant and equipment | -97,761 | |||||
Total assets acquired, net of divested assets | $936,351 | |||||
Liabilities: | ||||||
Current liabilities: | ||||||
Current liabilities - Pennsylvania Properties | 8,657 | |||||
Current liabilities - SWEPI Properties | -601 | |||||
Subtotal - Current liabilities | $8,056 | |||||
Other long-term obligations: | ||||||
Acquired asset retirement obligations - SWEPI Properties | 53,270 | |||||
Divested asset retirement obligations - Pennsylvania Properties | -15,760 | |||||
Subtotal - Other long-term obligations | 37,510 | |||||
Total liabilities, net | $45,566 | |||||
Contingent consideration | ||||||
In the PSA for the SWEPI Transaction, the Company agreed to attempt to extend or renew certain expiring leases in Pennsylvania at its expense. In satisfaction of this obligation, during January and February 2015 the Company made or will make a cash payment to SWEPI LP and to various landowners who agreed to extend their leases. | ||||||
Pro Forma Operating Results | ||||||
The following pro forma combined results for the years ended December 31, 2014 and 2013 reflect the consolidated results of operations of the Company as if the SWEPI Transaction and related financing had occurred on January 1, 2013. The pro forma information includes adjustments primarily for revenues and expenses from the acquired SWEPI Properties less revenues and expenses from the divested Pennsylvania Properties as well as depreciation, depletion, amortization and accretion, and interest expense associated with the financing related to the SWEPI Transaction. | ||||||
The unaudited pro forma combined financial statements give effect to the events described below: | ||||||
The acquisition and divestiture of oil and gas properties in the SWEPI Transaction completed on September 25, 2014 | ||||||
Issuance of $850.0 million of 6.125% senior notes due 2024 to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense | ||||||
Increase in borrowings under the Credit Agreement to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense | ||||||
Includes transportation charges of $74.6 million and $113.4 million for the years ended December 31, 2014 and 2013, respectively, incurred with respect to operation of the properties acquired in the SWEPI Transaction that will not be incurred by the Company. | ||||||
The pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the SWEPI Transaction and related financing been completed as of the date set forth in the pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the pro forma combined financial information and actual results. | ||||||
For the year ended December 31, | ||||||
2014 | 2013 | |||||
Revenues | $ | 1,421,537 | $ | 1,160,394 | ||
Net income | $ | 531,188 | $ | 164,303 | ||
Net income per common share - basic | $ | 3.47 | $ | 1.07 | ||
Net income per common share - fully diluted | $ | 3.43 | $ | 1.06 | ||
Post-Acquisition Operating Results | ||||||
The amounts of revenues and earnings included in the Company’s Consolidated Statements of Operations for the year ended December 31, 2014 related to the SWEPI Transaction represents activity from September 25, 2014 through December 31, 2014 and includes $74.7 million in revenues and $23.5 million in earnings. | ||||||
2013 Acquisition: | ||||||
On December 12, 2013 the Company, through its subsidiary, UPL Three Rivers Holdings, LLC, closed on the acquisition of crude oil assets (“the Assets”) located in Three Rivers Field in Uintah County, Utah. The Assets were acquired at a contract price of $652.0 million and consist of producing wells, undeveloped acreage and water and gas gathering assets. A purchase and sale agreement was executed between the parties on October 18, 2013 with an effective date of October 1, 2013. The acquisition was financed through the issuance of $450.0 million of senior notes and the remainder under the Company’s credit facility. |
Subsequent_Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | 14. SUBSEQUENT EVENTS: |
The Company has evaluated the period subsequent to December 31, 2014 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading. |
Summarized_Quarterly_Financial
Summarized Quarterly Financial Information | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Summarized Quarterly Financial Information Disclosure [Abstract] | |||||||||||
SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 15. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): | ||||||||||
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 | |
2013 | |||||||||||
1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Total | |||||||
Revenues from continuing operations | $ | 225,626 | $ | 261,376 | $ | 221,205 | $ | 225,197 | $ | 933,404 | |
Gain (loss) on commodity derivatives | -44,715 | 22,091 | 2,074 | -26,204 | -46,754 | ||||||
Expenses from continuing operations | 139,994 | 143,002 | 136,389 | 141,753 | 561,138 | ||||||
Interest expense | 25,764 | 25,238 | 25,174 | 25,310 | 101,486 | ||||||
Other income (expense), net | 2,648 | 2,641 | 2,575 | 2,332 | 10,196 | ||||||
Income before income tax provision (benefit) | 17,801 | 117,868 | 64,291 | 34,262 | 234,222 | ||||||
Income tax provision (benefit) | 1,368 | 1,491 | 381 | -6,856 | -3,616 | ||||||
Net income | $ | 16,433 | $ | 116,377 | $ | 63,910 | $ | 41,118 | $ | 237,838 | |
Net income per common share - basic | $ | 0.11 | $ | 0.76 | $ | 0.42 | $ | 0.27 | $ | 1.55 | |
Net income per common share - fully diluted | $ | 0.11 | $ | 0.75 | $ | 0.41 | $ | 0.27 | $ | 1.54 |
Disclosure_About_Oil_and_Gas_P
Disclosure About Oil and Gas Producing Activities | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | ||||||||
DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 16. 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 Professional Engineer with over 13 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. | ||||||||
The estimates of proved reserves and future net revenue as of December 31, 2014, are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment. | ||||||||
The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years. | ||||||||
The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2014 in this annual report. For the year ended December 31, 2013, the Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets in Wyoming and Pennsylvania in this annual report. Due to the timing of the closing of the acquisition in Utah in December 2013 relative to the timing of preparing annual corporate reserves, the Company’s Reservoir Engineering Department prepared the proved reserve estimates for its Utah assets for the year ended December 31, 2013, which were prepared in accordance with the Company’s internal controls and SEC regulations and represented less than 2% of estimated proved reserves as of December 31, 2013. The Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2012 in this annual report. | ||||||||
Our internal professional staff works closely with our independent engineers, NSAI, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report. | ||||||||
The reserves estimates shown herein have been independently evaluated by 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, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. | ||||||||
Since January 1, 2014, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA. | ||||||||
The following unaudited tables as of December 31, 2014, 2013, and 2012 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2014, 2013 and 2012. 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, 2011 | 33,081 | 4,778,554 | - | |||||
Extensions, discoveries and additions | 5,435 | 819,896 | - | |||||
Production | -1,282 | -249,310 | - | |||||
Revisions | -19,097 | -2,382,695 | - | |||||
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 | |||||
United States | ||||||||
Oil | Natural Gas | NGLs | ||||||
(MBbls) | (MMcf) | (MBbls) | ||||||
Proved: | ||||||||
Developed | 11,794 | 1,973,391 | - | |||||
Undeveloped | 21,287 | 2,805,163 | - | |||||
Total Proved - 2011 | 33,081 | 4,778,554 | - | |||||
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 | |||||
Changes in proved developed reserves: During 2014, substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2014. Proved developed reserves increased associated with reserves acquired in the SWEPI Transaction (see Note 13) and partially offset by the Pennsylvania Properties divested in the SWEPI Transaction. | ||||||||
Changes in proved undeveloped reserves: The changes to the Company’s proved undeveloped reserves (PUDs) during 2014 include updates to prior PUDs, the addition of new PUDs associated with current development plans, the transfer of PUDs to unproved categories due to development plan changes, and the impact of changes in economic conditions, including changes in commodity prices. The Company’s year-end development plans and associated PUDs are consistent with SEC guidelines for PUD development within five years. The Company annually reviews all PUDs to ensure an appropriate plan for development exists. Additionally, proved undeveloped reserves increased associated with reserves acquired in the SWEPI Transaction (see Note 13). | ||||||||
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. | ||||||||
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, 2014, 2013 and 2012 was $4.32, $3.51 and $2.63 per Mcf, respectively, for natural gas, and $80.62, $84.97 and $87.85 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 2014, the average sales price utilized for purposes of estimating the Company’s proved reserves and future net revenues associated with NGLs was $46.27 per barrel. The prices utilized in the reserve report are based upon the average of prices in effect on the first day of the month for the preceding twelve month period. | ||||||||
The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers. | ||||||||
As of December 31, | ||||||||
2014 | 2013 | 2012 | ||||||
Future cash inflows | $ | 27,331,391 | $ | 14,861,131 | $ | 9,380,970 | ||
Future production costs | -8,627,657 | -4,540,209 | -3,217,771 | |||||
Future development costs | -3,859,385 | -2,014,751 | -1,661,394 | |||||
Future income taxes | -3,898,355 | -1,897,340 | -733,855 | |||||
Future net cash flows | 10,945,994 | 6,408,831 | 3,767,950 | |||||
Discount at 10% | -5,712,511 | -3,220,862 | -1,873,633 | |||||
Standardized measure of discounted | ||||||||
future net cash flows | $ | 5,233,483 | $ | 3,187,969 | $ | 1,894,317 | ||
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, | ||||||||
2014 | 2013 | 2012 | ||||||
Standardized measure, beginning | $ | 3,187,969 | $ | 1,894,317 | $ | 3,796,056 | ||
Net revisions of previous quantity estimates | -603,795 | -1,089,316 | -2,516,159 | |||||
Extensions, discoveries and other changes | 1,787,643 | 2,098,644 | 858,951 | |||||
Sales of reserves in place | -398,506 | - | - | |||||
Acquisition of reserves | 2,552,491 | 86,196 | - | |||||
Changes in future development costs | -1,013,652 | -252,992 | 952,067 | |||||
Sales of oil and gas, net of production costs | -949,389 | -720,826 | -625,745 | |||||
Net change in prices and production costs | 1,010,052 | 1,204,041 | -2,912,698 | |||||
Development costs incurred during the | ||||||||
period that reduce future development costs | 342,987 | 171,149 | 316,394 | |||||
Accretion of discount | 413,177 | 226,326 | 529,696 | |||||
Net changes in production rates and other | -175,419 | 145,289 | 363,788 | |||||
Net change in income taxes | -920,075 | -574,859 | 1,131,967 | |||||
Aggregate changes | 2,045,514 | 1,293,652 | -1,901,739 | |||||
Standardized measure, ending | $ | 5,233,483 | $ | 3,187,969 | $ | 1,894,317 | ||
There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely. | ||||||||
E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES: | ||||||||
Years Ended December 31, | ||||||||
2014 | 2013 | 2012 | ||||||
United States | ||||||||
Property Acquisitions: | ||||||||
Unproved | $ | 26,106 | $ | 424,540 | $ | 47,979 | ||
Proved | 895,179 | 224,410 | - | |||||
Exploration* | 197,664 | 184,007 | 199,569 | |||||
Development | 382,984 | 186,755 | 587,618 | |||||
Total | $ | 1,501,933 | $ | 1,019,712 | $ | 835,166 | ||
* 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, | ||||||||
2014 | 2013 | 2012 | ||||||
United States | ||||||||
Oil and gas revenue | $ | 1,230,020 | $ | 933,404 | $ | 809,974 | ||
Production expenses | -280,631 | -212,578 | -184,229 | |||||
Depletion and depreciation | -292,951 | -243,390 | -388,985 | |||||
Ceiling test and other impairments | - | - | -2,972,464 | |||||
Income tax benefit (expense) | 3,736 | -2,821 | 662,698 | |||||
Total | $ | 660,174 | $ | 474,615 | $ | -2,073,006 | ||
G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: | ||||||||
December 31, | ||||||||
2014 | 2013 | |||||||
Proven Properties: | ||||||||
Acquisition, equipment, exploration, drilling and | ||||||||
environmental costs | $ | 9,731,407 | $ | 7,817,374 | ||||
Less: accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||
3,636,643 | 2,008,538 | |||||||
Unproven Properties: | ||||||||
Acquisition and exploration costs not being amortized | 242,294 | 413,073 | ||||||
$ | 3,878,937 | $ | 2,421,611 | |||||
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Accounting Policies [Abstract] | |||||||||
Basis of presentation | (a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its 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 consolidation. | ||||||||
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 production 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 instruments. The Company routinely assesses the collectability of all material trade and other receivables. | ||||||||
Property, plant and equipment | (e) Property, plant and equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. 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 (See Note 13), 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 was transferred 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”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Separate cost centers are maintained for each country in which the Company incurs costs. 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 activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between 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 proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion. | |||||||||
Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized. For the years ended December 31, 2014 and 2013, the Company did not determine any impairment related to unevaluated properties or major development projects excluded from capitalized costs being amortized. | |||||||||
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. | |||||||||
During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials. 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, 2014 and 2013, inventory of $10.2 million and $5.2 million primarily includes the cost of pipe and production equipment that will be utilized during the 2015 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 and 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 Company 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). | ||||||||
Income Taxes Policy | (i) Income taxes: Income taxes 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 be 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 likely 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 position following an audit. | ||||||||
The Company has recorded a valuation allowance against certain deferred tax assets of $161.5 million as of December 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income. | |||||||||
Earnings per share | (j) 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 income (loss) per common share: | |||||||||
December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Net income (loss) | $ | 542,851 | $ | 237,838 | $ | -2,176,898 | |||
Weighted average common shares outstanding | |||||||||
during the period | 153,136 | 152,963 | 152,845 | ||||||
Effect of dilutive instruments | 1,558 | 1,463 | - | -1 | |||||
Weighted average common shares outstanding during | |||||||||
the period including the effects of dilutive instruments | 154,694 | 154,426 | 152,845 | ||||||
Net income (loss) per common share - basic | $ | 3.54 | $ | 1.55 | $ | -14.24 | |||
Net income (loss) per common share - fully diluted | $ | 3.51 | $ | 1.54 | $ | -14.24 | |||
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 | 1,377 | 1,406 | - | -1 | |||||
(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share. | |||||||||
Use of estimates | (k) 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 | (l) Accounting for share-based compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation. | ||||||||
Fair value accounting | (m) Fair value accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information. | ||||||||
Asset retirement obligation | (n) Asset retirement obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets. | ||||||||
Revenue recognition | (o) 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 natural 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, 2014 and 2013, the Company had a net natural gas imbalance liability of $3.0 million and $3.3 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 allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. | |||||||||
Capitalized interest | (p) 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 work in process relating to gathering systems that are not currently in service. | ||||||||
(1) 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 work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service. | |||||||||
Capital Cost Accrual | (q) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period. | ||||||||
Reclassifications | (r) Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation. | ||||||||
Recent accounting pronouncements | (s) Recent accounting pronouncements: In August 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require 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 an interim and annual basis. Management will be 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. | ||||||||
In June 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which supersedes 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. ASU No. 2014-09 becomes effective at the beginning of 2017. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations. | |||||||||
In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on our financial position or results of operations. | |||||||||
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 Company 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 | (p) 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 work in process relating to gathering systems that are not currently in service. | ||||||||
(1) 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 work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2014 and 2013, total interest on outstanding debt was $146.6 million and $103.5 million, respectively, of which $20.4 million and $2.0 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service. |
Significant_Accounting_Policie2
Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Significant Accounting Tables Policies [Abstract] | |||||||||
Schedule Of Earnings Per Share | The following table provides a reconciliation of components of basic and diluted net income (loss) per common share: | ||||||||
December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Net income (loss) | $ | 542,851 | $ | 237,838 | $ | -2,176,898 | |||
Weighted average common shares outstanding | |||||||||
during the period | 153,136 | 152,963 | 152,845 | ||||||
Effect of dilutive instruments | 1,558 | 1,463 | - | -1 | |||||
Weighted average common shares outstanding during | |||||||||
the period including the effects of dilutive instruments | 154,694 | 154,426 | 152,845 | ||||||
Net income (loss) per common share - basic | $ | 3.54 | $ | 1.55 | $ | -14.24 | |||
Net income (loss) per common share - fully diluted | $ | 3.51 | $ | 1.54 | $ | -14.24 | |||
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 | 1,377 | 1,406 | - | -1 | |||||
(1) Due to the net loss for the year ended December 31, 2012, 1.9 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, 2014 | |||||||
Asset Retirement Obligation [Abstract] | |||||||
Schedule Of Asset Retirement Obligations | December 31, | ||||||
2014 | 2013 | ||||||
Asset retirement obligations at beginning of period | $ | 72,807 | $ | 60,814 | |||
Accretion expense | 6,571 | 5,171 | |||||
Liabilities incurred | 10,242 | 7,730 | |||||
Liabilities acquired(1) | 53,270 | - | |||||
Liabilities divested(1) | -15,760 | - | |||||
Liabilities settled | -336 | -2,334 | |||||
Revisions of estimated liabilities | 446 | 1,426 | |||||
Asset retirement obligations at end of period | 127,240 | 72,807 | |||||
Less: current asset retirement obligations | -417 | -96 | |||||
Long-term asset retirement obligations | $ | 126,823 | $ | 72,711 |
Oil_and_Gas_Properties_Tables
Oil and Gas Properties (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Oil and Gas Properties And Equipment Tables [Abstract] | ||||||||||||
Capitalized Costs Relating to Oil and Gas Producing Activities | December 31, | December 31, | ||||||||||
2014 | 2013 | |||||||||||
Proven Properties: | ||||||||||||
Acquisition, equipment, exploration, drilling and environmental costs(2), (3) | $ | 9,731,407 | $ | 7,817,374 | ||||||||
Less: Accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||||||
3,636,643 | 2,008,538 | |||||||||||
Unproven Properties: | ||||||||||||
Acquisition and exploration costs not being amortized (1), (2) | 242,294 | 413,073 | ||||||||||
Net capitalized costs - oil and gas properties | $ | 3,878,937 | $ | 2,421,611 | ||||||||
G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Proven Properties: | ||||||||||||
Acquisition, equipment, exploration, drilling and | ||||||||||||
environmental costs | $ | 9,731,407 | $ | 7,817,374 | ||||||||
Less: accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||||||
3,636,643 | 2,008,538 | |||||||||||
Unproven Properties: | ||||||||||||
Acquisition and exploration costs not being amortized | 242,294 | 413,073 | ||||||||||
$ | 3,878,937 | $ | 2,421,611 | |||||||||
Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization Text Block | Total | 2014 | 2013 | 2012 | Prior | |||||||
Acquisition costs | $ | 228,516 | $ | -191,184 | $ | 419,700 | $ | -481,689 | $ | 481,689 | ||
Exploration costs | -7,708 | 173 | -7,881 | -9,962 | 9,962 | |||||||
Capitalized interest | 21,486 | 20,232 | 1,254 | -45,875 | 45,875 | |||||||
Unproven properties | $ | 242,294 | $ | -170,779 | $ | 413,073 | $ | -537,526 | $ | 537,526 |
Property_Plant_and_Equipment_T
Property, Plant and Equipment (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property, Plant and Equipment [Abstract] | |||||||||
Schedule of Property, Plant and Equipment | December 31, | ||||||||
2014 | 2013 | ||||||||
Cost | Accumulated Depreciation | Net Book Value | Net Book Value | ||||||
Gathering systems(1)(2) | $ | - | $ | - | $ | - | $ | 189,110 | |
Computer equipment | 2,967 | -2,050 | 917 | 892 | |||||
Office equipment | 467 | -410 | 57 | 41 | |||||
Leasehold improvements | 471 | -360 | 111 | 136 | |||||
Land(3) | 5,778 | - | 5,778 | 22,359 | |||||
Other | 13,656 | -8,333 | 5,323 | 4,371 | |||||
Property, plant and equipment, net | $ | 23,339 | $ | -11,153 | $ | 12,186 | $ | 216,909 |
Long_Term_Liabilities_Tables
Long Term Liabilities (Tables) | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Long Term Liabilities Tables [Abstract] | |||||||||||||||
Schedule of Long-term Liabilities | December 31, | December 31, | |||||||||||||
2014 | 2013 | ||||||||||||||
Short-term debt: | |||||||||||||||
Senior Notes due March 2015 | $ | 100,000 | $ | - | |||||||||||
Long-term debt and other long-term liabilities: | |||||||||||||||
Bank indebtedness | 518,000 | 460,000 | |||||||||||||
Senior notes | 2,760,000 | 2,010,000 | |||||||||||||
Other long-term obligations | 152,472 | 91,932 | |||||||||||||
$ | 3,530,472 | $ | 2,561,932 | ||||||||||||
Maturity Schedule | Aggregate maturities of debt at December 31, 2014: | ||||||||||||||
Beyond | |||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 5 years | Total | |||||||||
$ | 100,000 | $ | 580,000 | $ | 116,000 | $ | 650,000 | $ | 173,000 | $ | 1,759,000 | $ | 3,378,000 |
Share_Based_Compensation_Table
Share Based Compensation (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Share Based Compensation Tables [Abstract] | ||||||||||||
Valuation and Expense Information | Valuation and Expense Information | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Total cost of share-based payment plans | $ | 8,640 | $ | 13,957 | $ | 15,835 | ||||||
Amounts capitalized in oil and gas properties and equipment | $ | 3,173 | $ | 4,190 | $ | 5,079 | ||||||
Amounts charged against income, before | ||||||||||||
income tax benefit | $ | 5,467 | $ | 9,767 | $ | 10,756 | ||||||
Amount of related income tax benefit recognized | ||||||||||||
in income before valuation allowances | $ | 2,285 | $ | 4,083 | $ | 4,463 | ||||||
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 | 690 | $56.58 | 2,608 | |||||||||
Equity compensation plans not approved | ||||||||||||
by security holders | n/a | n/a | n/a | |||||||||
Total | 690 | $56.58 | 2,608 | |||||||||
Changes in Stock Options Outstanding | Weighted | |||||||||||
Average | ||||||||||||
Number of | Exercise Price | |||||||||||
Options | (US$) | |||||||||||
(000's) | ||||||||||||
Balance, December 31, 2011 | 1,459 | $16.97 | to | $98.87 | ||||||||
Forfeited | -68 | $25.08 | to | $75.18 | ||||||||
Exercised | -34 | $16.97 | to | $19.18 | ||||||||
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 | ||||||||
Share Based Compensation by Exercise Price Table | The following table summarizes information about the stock options outstanding and exercisable at December 31, 2014: | |||||||||||
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) | |||||||||||
$ | 25.68 | - | $ | 53.39 | 126 | 0.64 | $44.25 | $- | ||||
$ | 50.15 | - | $ | 65.04 | 125 | 1.55 | $57.00 | $- | ||||
$ | 49.05 | - | $ | 62.23 | 281 | 2.28 | $53.85 | $- | ||||
$ | 51.6 | - | $ | 98.87 | 158 | 3.43 | $70.92 | $- | ||||
Weighted Average Grant Date Fair Value of Stock Options | 2014 | 2013 | 2012 | |||||||||
Options forfeited during the year | $ | 24.4 | $ | 25.44 | $ | 27.05 |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Financial Instruments Tables [Abstract] | ||||||||||||
Detail Schedule of Realized and Unrealized Gains and Losses | Commodity Derivative Contracts: At December 31, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties | |||||||||||
Natural Gas: | ||||||||||||
Type | Commodity Reference Price | Remaining Contract Period | Volume - MMBTU/Day | Average Price/MMBTU | Fair Value - December 31, 2014 | |||||||
Asset | ||||||||||||
Swap | NYMEX-Henry Hub | Jan - Mar 2015 | 210,000 | $4.54 | $ | 29,201 | ||||||
Swap | NYMEX-Henry Hub | Apr - Oct 2015 | 522,500 | $3.65 | $ | 74,989 | ||||||
Subsequent to December 31, 2014 and through February 11, 2015, the Company has entered into the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price: | ||||||||||||
Natural Gas: | ||||||||||||
Type | Commodity Reference Price | Remaining Contract Period | Volume - MMBTU/Day | Average Price/MMBTU | ||||||||
Swap | NYMEX-Henry Hub | Apr - Oct 2015 | 150,000 | $2.98 | ||||||||
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, 2014, 2013 and 2012: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
Commodity Derivatives: | 2014 | 2013 | 2012 | |||||||||
Realized (loss) gain on commodity derivatives-natural gas (1) | $ | -48,170 | $ | -20,552 | $ | 303,966 | ||||||
Realized gain (loss) on commodity derivatives-crude oil (1) | 506 | -326 | - | |||||||||
Unrealized gain (loss) on commodity derivatives (1) | 130,066 | -25,876 | -230,385 | |||||||||
Total gain (loss) on commodity derivatives | $ | 82,402 | $ | -46,754 | $ | 73,581 | ||||||
(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, 2014 | ||||||||||
Fair Value Measurements Tables [Abstract] | ||||||||||
Fair Value of Long-Term Debt | Level 1 | Level 2 | Level 3 | Total | ||||||
Assets: | ||||||||||
Current derivative asset | $ | - | $ | 104,190 | $ | - | $ | 104,190 | ||
31-Dec-14 | 31-Dec-13 | |||||||||
Carrying | Estimated | Carrying | Estimated | |||||||
Amount | Fair Value | Amount | Fair Value | |||||||
5.45% Notes due March 2015, issued 2008 | $ | 100,000 | $ | 101,931 | $ | 100,000 | $ | 105,913 | ||
7.31% Notes due March 2016, issued 2009 | 62,000 | 65,027 | 62,000 | 70,228 | ||||||
4.98% Notes due January 2017, issued 2010 | 116,000 | 116,240 | 116,000 | 126,342 | ||||||
5.92% Notes due March 2018, issued 2008 | 200,000 | 203,738 | 200,000 | 226,127 | ||||||
5.75% Notes due December 2018, issued 2013 | 450,000 | 414,505 | 450,000 | 466,946 | ||||||
7.77% Notes due March 2019, issued 2009 | 173,000 | 187,105 | 173,000 | 211,877 | ||||||
5.50% Notes due January 2020, issued 2010 | 207,000 | 201,371 | 207,000 | 229,068 | ||||||
4.51% Notes due October 2020, issued 2010 | 315,000 | 283,335 | 315,000 | 323,732 | ||||||
5.60% Notes due January 2022, issued 2010 | 87,000 | 82,581 | 87,000 | 95,736 | ||||||
4.66% Notes due October 2022, issued 2010 | 35,000 | 30,476 | 35,000 | 35,494 | ||||||
6.125% Notes due October 2024, issued 2014 | 850,000 | 754,485 | - | - | ||||||
5.85% Notes due January 2025, issued 2010 | 90,000 | 83,876 | 90,000 | 99,142 | ||||||
4.91% Notes due October 2025, issued 2010 | 175,000 | 147,649 | 175,000 | 175,744 | ||||||
Credit Facility due October 2016 | 518,000 | 518,000 | 460,000 | 460,000 | ||||||
$ | 3,378,000 | $ | 3,190,319 | $ | 2,470,000 | $ | 2,626,349 |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Income Taxes [Abstract] | |||||||
Consoldiated income tax provision table | Income (loss) before income tax benefit is as follows: | ||||||
Year Ended December 31, | |||||||
2014 | 2013 | 2012 | |||||
United States | $ | 505,689 | $ | 210,580 | $ | -2,892,207 | |
Foreign | 31,338 | 23,642 | 15,096 | ||||
Total | $ | 537,027 | $ | 234,222 | $ | -2,877,111 | |
The consolidated income tax (benefit) provision is comprised of the following: | |||||||
Year Ended December 31, | |||||||
2014 | 2013 | 2012 | |||||
Current tax: | |||||||
U.S. federal, state and local | $ | -110 | $ | -8,491 | $ | 9,037 | |
Foreign | -6,709 | 4,881 | 3,326 | ||||
(Reduction in) current tax benefit on stock based compensation: | |||||||
U.S. federal, state and local | - | - | -4,427 | ||||
Total current tax expense (benefit) | -6,819 | -3,610 | 7,936 | ||||
Deferred tax: | |||||||
U.S. federal, state and local | - | - | -708,160 | ||||
Foreign | 995 | -6 | 11 | ||||
Total deferred tax expense (benefit) | 995 | -6 | -708,149 | ||||
Total income tax (benefit) provision | $ | -5,824 | $ | -3,616 | $ | -700,213 | |
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, | |||||||
2014 | 2013 | 2012 | |||||
Income tax provision (benefit) computed at the U.S. statutory rate | $ | 187,959 | $ | 81,978 | $ | -1,006,989 | |
State income tax provision (benefit) net of federal benefit | 8,023 | 1,329 | -136,112 | ||||
Valuation allowance | -199,038 | -81,923 | 446,148 | ||||
Tax effect of rate change | 15,457 | -2,871 | 1,358 | ||||
Foreign rate differential | -16,314 | -3,508 | -5,531 | ||||
Other, net | -1,911 | 1,379 | 913 | ||||
Total income tax (benefit) provision | $ | -5,824 | $ | -3,616 | $ | -700,213 | |
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, | |||||||
2014 | 2013 | ||||||
Deferred tax assets - current: | |||||||
Derivative instruments, net | $ | - | $ | 9,636 | |||
Incentive compensation/other, net | 6,150 | 7,641 | |||||
6,150 | 17,277 | ||||||
Valuation allowance | - | -16,778 | |||||
Net deferred tax assets - current | $ | 6,150 | $ | 499 | |||
Deferred tax liabilities - current: | |||||||
Derivative instruments, net | $ | 36,788 | $ | 499 | |||
Net deferred tax liabilities - current | $ | 36,788 | $ | 499 | |||
Net deferred tax liability - current | $ | 30,638 | $ | - | |||
Deferred tax assets - non-current: | |||||||
Property and equipment | - | 131,340 | |||||
Deferred gain | 48,319 | 52,045 | |||||
U.S. federal tax credit carryforwards | 16,144 | 16,254 | |||||
U.S. net operating loss carryforwards | 147,336 | 71,843 | |||||
U.S. state net operating loss carryforwards | 53,654 | 36,205 | |||||
Asset retirement obligations | 45,039 | 26,876 | |||||
Incentive compensation/other, net | 19,142 | 13,007 | |||||
329,634 | 347,570 | ||||||
Valuation allowance | -161,480 | -346,596 | |||||
Net deferred tax assets - non-current | $ | 168,154 | $ | 974 | |||
Deferred tax liabilities - non-current: | |||||||
Property and equipment | 137,514 | - | |||||
Other | - | 968 | |||||
Net non-current tax liabilities | $ | 137,514 | $ | 968 | |||
Net non-current tax asset | $ | 30,640 | $ | 6 | |||
Deferred tax liabilities - non-current: | |||||||
Other - non-US | 992 | - | |||||
Completion_of_Acquisition_and_1
Completion of Acquisition and Dispositon of Assets (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Business Combination Tables [Abstract] | ||||||
Pro Forma Financial Information Table Table [Text Block] | For the year ended December 31, | |||||
2014 | 2013 | |||||
Revenues | $ | 1,421,537 | $ | 1,160,394 | ||
Net income | $ | 531,188 | $ | 164,303 | ||
Net income per common share - basic | $ | 3.47 | $ | 1.07 | ||
Net income per common share - fully diluted | $ | 3.43 | $ | 1.06 | ||
Adjusted Cash Payment Allocation Table Table [Text Block] | Adjusted cash payment | $890,785 | ||||
Assets: | ||||||
Joint interest billing and other receivables - SWEPI Properties | -4,182 | |||||
Other current assets: | ||||||
Acquired condensate inventory - SWEPI Properties | 819 | |||||
Acquired yard inventory - SWEPI Properties | 3,515 | |||||
Subtotal - Other current assets | 4,334 | |||||
Proven oil and gas properties | 1,033,960 | |||||
Property, plant and equipment: | ||||||
Divested gathering system - Pennsylvania Properties | -98,580 | |||||
Acquired other fixed assets - SWEPI Properties | 869 | |||||
Divested other fixed assets - Pennsylvania Properties | -50 | |||||
Subtotal - Property, plant and equipment | -97,761 | |||||
Total assets acquired, net of divested assets | $936,351 | |||||
Liabilities: | ||||||
Current liabilities: | ||||||
Current liabilities - Pennsylvania Properties | 8,657 | |||||
Current liabilities - SWEPI Properties | -601 | |||||
Subtotal - Current liabilities | $8,056 | |||||
Other long-term obligations: | ||||||
Acquired asset retirement obligations - SWEPI Properties | 53,270 | |||||
Divested asset retirement obligations - Pennsylvania Properties | -15,760 | |||||
Subtotal - Other long-term obligations | 37,510 | |||||
Total liabilities, net | $45,566 |
Summarized_Quarterly_Financial1
Summarized Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Summarized Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Schedule Of Quarterly Financial Information Table Text Block | 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 | |
2013 | |||||||||||
1st Quarter | 2nd Quarter | 3rd Quarter | 4th Quarter | Total | |||||||
Revenues from continuing operations | $ | 225,626 | $ | 261,376 | $ | 221,205 | $ | 225,197 | $ | 933,404 | |
Gain (loss) on commodity derivatives | -44,715 | 22,091 | 2,074 | -26,204 | -46,754 | ||||||
Expenses from continuing operations | 139,994 | 143,002 | 136,389 | 141,753 | 561,138 | ||||||
Interest expense | 25,764 | 25,238 | 25,174 | 25,310 | 101,486 | ||||||
Other income (expense), net | 2,648 | 2,641 | 2,575 | 2,332 | 10,196 | ||||||
Income before income tax provision (benefit) | 17,801 | 117,868 | 64,291 | 34,262 | 234,222 | ||||||
Income tax provision (benefit) | 1,368 | 1,491 | 381 | -6,856 | -3,616 | ||||||
Net income | $ | 16,433 | $ | 116,377 | $ | 63,910 | $ | 41,118 | $ | 237,838 | |
Net income per common share - basic | $ | 0.11 | $ | 0.76 | $ | 0.42 | $ | 0.27 | $ | 1.55 | |
Net income per common share - fully diluted | $ | 0.11 | $ | 0.75 | $ | 0.41 | $ | 0.27 | $ | 1.54 |
Disclosures_About_Oil_and_Gas_
Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
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, 2011 | 33,081 | 4,778,554 | - | |||||
Extensions, discoveries and additions | 5,435 | 819,896 | - | |||||
Production | -1,282 | -249,310 | - | |||||
Revisions | -19,097 | -2,382,695 | - | |||||
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 | |||||
United States | ||||||||
Oil | Natural Gas | NGLs | ||||||
(MBbls) | (MMcf) | (MBbls) | ||||||
Proved: | ||||||||
Developed | 11,794 | 1,973,391 | - | |||||
Undeveloped | 21,287 | 2,805,163 | - | |||||
Total Proved - 2011 | 33,081 | 4,778,554 | - | |||||
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 | |||||
Standardized measure | As of December 31, | |||||||
2014 | 2013 | 2012 | ||||||
Future cash inflows | $ | 27,331,391 | $ | 14,861,131 | $ | 9,380,970 | ||
Future production costs | -8,627,657 | -4,540,209 | -3,217,771 | |||||
Future development costs | -3,859,385 | -2,014,751 | -1,661,394 | |||||
Future income taxes | -3,898,355 | -1,897,340 | -733,855 | |||||
Future net cash flows | 10,945,994 | 6,408,831 | 3,767,950 | |||||
Discount at 10% | -5,712,511 | -3,220,862 | -1,873,633 | |||||
Standardized measure of discounted | ||||||||
future net cash flows | $ | 5,233,483 | $ | 3,187,969 | $ | 1,894,317 | ||
Summary of changes in the standardized measure of discounted future net cash flows | December 31, | |||||||
2014 | 2013 | 2012 | ||||||
Standardized measure, beginning | $ | 3,187,969 | $ | 1,894,317 | $ | 3,796,056 | ||
Net revisions of previous quantity estimates | -603,795 | -1,089,316 | -2,516,159 | |||||
Extensions, discoveries and other changes | 1,787,643 | 2,098,644 | 858,951 | |||||
Sales of reserves in place | -398,506 | - | - | |||||
Acquisition of reserves | 2,552,491 | 86,196 | - | |||||
Changes in future development costs | -1,013,652 | -252,992 | 952,067 | |||||
Sales of oil and gas, net of production costs | -949,389 | -720,826 | -625,745 | |||||
Net change in prices and production costs | 1,010,052 | 1,204,041 | -2,912,698 | |||||
Development costs incurred during the | ||||||||
period that reduce future development costs | 342,987 | 171,149 | 316,394 | |||||
Accretion of discount | 413,177 | 226,326 | 529,696 | |||||
Net changes in production rates and other | -175,419 | 145,289 | 363,788 | |||||
Net change in income taxes | -920,075 | -574,859 | 1,131,967 | |||||
Aggregate changes | 2,045,514 | 1,293,652 | -1,901,739 | |||||
Standardized measure, ending | $ | 5,233,483 | $ | 3,187,969 | $ | 1,894,317 | ||
Costs incurred in oil and gas exploration and development activities | ||||||||
Years Ended December 31, | ||||||||
2014 | 2013 | 2012 | ||||||
United States | ||||||||
Property Acquisitions: | ||||||||
Unproved | $ | 26,106 | $ | 424,540 | $ | 47,979 | ||
Proved | 895,179 | 224,410 | - | |||||
Exploration* | 197,664 | 184,007 | 199,569 | |||||
Development | 382,984 | 186,755 | 587,618 | |||||
Total | $ | 1,501,933 | $ | 1,019,712 | $ | 835,166 | ||
* 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, | ||||||||
2014 | 2013 | 2012 | ||||||
United States | ||||||||
Oil and gas revenue | $ | 1,230,020 | $ | 933,404 | $ | 809,974 | ||
Production expenses | -280,631 | -212,578 | -184,229 | |||||
Depletion and depreciation | -292,951 | -243,390 | -388,985 | |||||
Ceiling test and other impairments | - | - | -2,972,464 | |||||
Income tax benefit (expense) | 3,736 | -2,821 | 662,698 | |||||
Total | $ | 660,174 | $ | 474,615 | $ | -2,073,006 | ||
Capitalized Costs Relating to Oil and Gas Producing Activities | December 31, | December 31, | ||||||
2014 | 2013 | |||||||
Proven Properties: | ||||||||
Acquisition, equipment, exploration, drilling and environmental costs(2), (3) | $ | 9,731,407 | $ | 7,817,374 | ||||
Less: Accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||
3,636,643 | 2,008,538 | |||||||
Unproven Properties: | ||||||||
Acquisition and exploration costs not being amortized (1), (2) | 242,294 | 413,073 | ||||||
Net capitalized costs - oil and gas properties | $ | 3,878,937 | $ | 2,421,611 | ||||
G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES: | ||||||||
December 31, | ||||||||
2014 | 2013 | |||||||
Proven Properties: | ||||||||
Acquisition, equipment, exploration, drilling and | ||||||||
environmental costs | $ | 9,731,407 | $ | 7,817,374 | ||||
Less: accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 | ||||||
3,636,643 | 2,008,538 | |||||||
Unproven Properties: | ||||||||
Acquisition and exploration costs not being amortized | 242,294 | 413,073 | ||||||
$ | 3,878,937 | $ | 2,421,611 | |||||
Significant_Accounting_Policie3
Significant Accounting Policies (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share Reconciliation | |||||||||||
Net earnings (loss) | $209,730 | $125,357 | $106,049 | $101,715 | $41,118 | $63,910 | $116,377 | $16,433 | $542,851 | $237,838 | ($2,176,898) |
Weighted average common shares outstanding - basic | 153,136,000 | 152,963,000 | 152,845,000 | ||||||||
Effect of dilutive instruments | 1,558,000 | 1,463,000 | 0 | ||||||||
Weighted average common shares outstanding - fully diluted | 154,694,000 | 154,426,000 | 152,845,000 | ||||||||
Net (income (loss) per common share - basic | $1.37 | $0.82 | $0.69 | $0.66 | $0.27 | $0.42 | $0.76 | $0.11 | $3.54 | $1.55 | ($14.24) |
Net income (loss) per common share - fully diluted | $1.36 | $0.81 | $0.68 | $0.66 | $0.27 | $0.41 | $0.75 | $0.11 | $3.51 | $1.54 | ($14.24) |
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount | 1,377,000 | 1,406,000 | 1,900,000 |
Significant_Accounting_Policie4
Significant Accounting Policies (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | |
Significant Accounting Policies Details [Abstract] | |||
Gathering system transferred to proven properties | $91,800,000 | ||
Discount Rate Future Net Revenues | 10.00% | ||
Ceiling test limitation | 2,900,000,000 | ||
Inventory | 10,200,000 | 5,200,000 | |
Valuation allowance | 161,500,000 | 363,400,000 | |
Natural gas imbalance liability | $3,000,000 | $3,300,000 |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Asset Retirement Obligation [Abstract] | ||
Asset retirement obligations at beginning of period | $72,807 | $60,814 |
Accretion expense | 6,571 | 5,171 |
Liabilities incurred | 10,242 | 7,730 |
Liabilities acquired | 53,270 | 0 |
Liabilities divested | -15,760 | 0 |
Liabilities settled | -336 | -2,334 |
Asset Retirement Obligation, Revision of Estimate | 446 | 1,426 |
Asset retirement obligations at end of period | 127,240 | 72,807 |
Less: current asset requirement obligations | -417 | -96 |
Long-term asset retirement obligations | $126,823 | $72,711 |
Oil_and_Gas_Properties_Details
Oil and Gas Properties (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Proven Properties [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $9,731,407 | $7,817,374 |
Less: Accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 |
Proved | 3,636,643 | 2,008,538 |
Unproven Properties: | ||
Unproven properties not being amortized | 242,294 | 413,073 |
Net capitalized costs - oil and gas properties | $3,878,937 | $2,421,611 |
Oil_and_Gas_Properties_Details1
Oil and Gas Properties (Details 1) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Unproven Properties: | ||||
Net Acquisition Costs | $228,516 | |||
Interest Costs Capitalized | 21,486 | |||
Exploration costs | -7,708 | |||
Total | 242,294 | 413,073 | ||
Acquisition costs | -191,184 | 419,700 | -481,689 | 481,689 |
Interest Costs Capitalized | 20,232 | 1,254 | -45,875 | 45,875 |
Exploration costs | 173 | -7,881 | -9,962 | 9,962 |
Total | ($170,779) | $413,073 | ($537,526) | $537,526 |
Oil_and_Gas_Properties_Details2
Oil and Gas Properties (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil And Gas Property [Abstract] | |||
DD&A per Mcfe | 1.18 | 1.05 | 1.51 |
Ceiling test limitation | $2,900,000,000 | ||
Total interest on outstanding debt | 146,600,000 | 103,500,000 | |
Capitalized interest detail | $20,400,000 | $2,000,000 |
Property_Plant_Equipment_Detai
Property, Plant & Equipment (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | $23,339 | |
Accumulated Depreciation | -11,153 | |
Property, plant and equipment | 12,186 | 216,909 |
Gas Gathering Equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 0 | |
Accumulated Depreciation | 0 | |
Property, plant and equipment | 0 | 189,110 |
Computer equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 2,967 | |
Accumulated Depreciation | -2,050 | |
Property, plant and equipment | 917 | 892 |
Office equipment [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 467 | |
Accumulated Depreciation | -410 | |
Property, plant and equipment | 57 | 41 |
Leasehold improvements [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 471 | |
Accumulated Depreciation | -360 | |
Property, plant and equipment | 111 | 136 |
Land [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 5,778 | |
Accumulated Depreciation | 0 | |
Property, plant and equipment | 5,778 | 22,359 |
Other [Member] | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Cost | 13,656 | |
Accumulated Depreciation | -8,333 | |
Property, plant and equipment | $5,323 | $4,371 |
Property_Plant_Equipment_Detai1
Property, Plant & Equipment (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Property, Plant and Equipment [Abstract] | |||
Proceeds from sale of oil and gas properties | $27,944,000 | $0 | $0 |
Gathering system transferred to proven properties | $91,800,000 |
Debt_and_Other_Long_Term_Liabi
Debt and Other Long Term Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Long Term Liabilities [Abstract] | ||
Bank indebtedness | $518,000 | $460,000 |
Senior notes | 2,760,000 | 2,010,000 |
Other long-term obligations | 152,472 | 91,932 |
Total Debt And Long Term Liabilities | 3,530,472 | 2,561,932 |
Short-term Debt [Abstract] | ||
Senior Notes due March 2015 | $100,000 | $0 |
Debt_and_Other_Long_Term_Liabi1
Debt and Other Long Term Liabilities (Details 1) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Long Term Debt Maturities | $3,378,000 |
Maturities Of Long Term Debt One Year [Member] | |
Long Term Debt Maturities | 100,000 |
Maturities Of Long Term Debt 2016 [Member] | |
Long Term Debt Maturities | 580,000 |
Maturities Of Long Term Debt 2017 [Member] | |
Long Term Debt Maturities | 116,000 |
Maturities Of Long Term Debt 2018 [Member] | |
Long Term Debt Maturities | 650,000 |
Maturities of Long Term Debt 2019 [Member] | |
Long Term Debt Maturities | 173,000 |
Maturities Of Long Term Debt Beyond Five Years [Member] | |
Long Term Debt Maturities | $1,759,000 |
Debt_and_Other_Long_Term_Liabi2
Debt and Other Long Term Liabilities (Details Textuals) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
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 | |
Bank indebtedness | 518,000,000 | 460,000,000 |
Credit Facility Lender Consent Requirement | 50.00% | |
Available borrowing capacity | 482,000,000 | |
Debt Instrument Interest Rate Terms Prime | 100 | |
Debt Instrument Interest Rate Terms Libor | 200 | |
Commitment fees incurred in current year | 2,000,000 | |
Ultra Resources Inc Senior Notes | ||
Senior Notes Ultra Resources Inc | 1,560,000,000 | |
Ultra Petroleum Corp Senior Notes | ||
Senior Notes Ultra Petroleum Corp Due 2024 | 850,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate | 6.13% | |
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 b 103.063%; 2020 b 102.042%; 2021 b 101.021%; and 2022 and thereafter b 100.000%). | |
Senior Notes Ultra Petroleum Corp Due 2018 | $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 b 102.875%; 2016 b 101.438%; and 2017 and thereafter b 100.000%). |
Share_Based_Compensation_Detai
Share Based Compensation (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Valuation And Expense Information [Abstract] | |||
Total Cost Of Share Based Payment Plans | $8,640 | $13,957 | $15,835 |
Amounts capitalized in fixed costs | 3,173 | 4,190 | 5,079 |
Amounts charged against income, before income tax benefit | 5,467 | 9,767 | 10,756 |
Amount of related income tax benefit recognized in income | $2,285 | $4,083 | $4,463 |
Share_Based_Compensation_Detai1
Share Based Compensation (Details 1) (USD $) | Dec. 31, 2014 |
Share Based Compensation Details [Abstract] | |
Number of Securities to be Issued Upon Exercise of Outstanding Options | 690,000 |
Weighted Averaged Exercise Price of Outstanding Options | $56.58 |
Number Of Securities Remaining Available For Future Issuance Under Equity Compenstation Plans Excluding Securities Reflected In The First Column | 2,608,000 |
Share_Based_Compensation_Detai2
Share Based Compensation (Details 2) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Stock Options Outstanding Summary [Line Items] | ||||
Balance, | 690,000 | |||
Number Of Options [Member] | ||||
Stock Options Outstanding Summary [Line Items] | ||||
Balance, | 1,246,000 | 1,357,000 | 1,459,000 | |
Forfeited | -513,000 | -110,000 | -68,000 | |
Exercised | -43,000 | -1,000 | -34,000 | |
Balance, | 690,000 | 1,246,000 | 1,357,000 | |
Weighted Average Exercise Price [Member] | ||||
Stock Options Outstanding Summary [Line Items] | ||||
Exercise Price, Lower Range Limit | $25.68 | $16.97 | $16.97 | $16.97 |
Exercise Price, Upper Range Limit | $98.87 | $98.87 | $98.87 | $98.87 |
Exercise Price, Lower Range Limit Forfeited | $33.57 | $25.68 | $25.08 | |
Exercise Price, Upper Range Limit Forfeited | $75.18 | $75.18 | $75.18 | |
Exercise Price, Lower Range Limit Exercised | $16.97 | $16.97 | $16.97 | |
Exercise Price, Upper Range Limit Exercised | $25.68 | $16.97 | $19.18 |
Share_Based_Compensation_Detai3
Share Based Compensation (Details 3) (USD $) | 12 Months Ended |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 |
Range 4 [Member] | |
Stock Options Outstanding Summary [Line Items] | |
Exercise Price, Lower Range Limit | $25.68 |
Exercise Price, Upper Range Limit | $53.39 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
Number Outstanding | 126,000 |
Weighted Average Remaining Contractual Life | 0 years 7 months 20 days |
Weighted Average Exercise Price | $44.25 |
Aggregate Intrinsic Value | $0 |
Range 5 [Member] | |
Stock Options Outstanding Summary [Line Items] | |
Exercise Price, Lower Range Limit | $50.15 |
Exercise Price, Upper Range Limit | $65.04 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
Number Outstanding | 125,000 |
Weighted Average Remaining Contractual Life | 1 year 6 months 18 days |
Weighted Average Exercise Price | $57 |
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 | 281,000 |
Weighted Average Remaining Contractual Life | 2 years 3 months 11 days |
Weighted Average Exercise Price | $53.85 |
Aggregate Intrinsic Value | 0 |
Range 7 [Member] | |
Stock Options Outstanding Summary [Line Items] | |
Exercise Price, Lower Range Limit | $51.60 |
Exercise Price, Upper Range Limit | $98.87 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract] | |
Number Outstanding | 158,000 |
Weighted Average Remaining Contractual Life | 3 years 5 months 5 days |
Weighted Average Exercise Price | $70.92 |
Aggregate Intrinsic Value | $0 |
Share_Based_Compensation_Detai4
Share Based Compensation (Details 4) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | |||
Options forfeited during the year | $24.40 | $25.44 | $27.05 |
Share_Based_Compensation_Detai5
Share Based Compensation (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share Based Compensation Details [Abstract] | |||
Companys Closing Stock Price Last Day Of Year | $13.16 | ||
Number Of In The Money Options Exercisable | 0 | ||
Fair Value Of Options Vesting In The Period | 0 | 0 | 0 |
Total intrinsic value of stock options excercised | 400,000 | 0 | 300,000 |
Long Term Incentive Program Period | 6,300,000 | 6,900,000 | 7,900,000 |
Long Term Incentive Program Total 2012 Program | 10,200,000 | ||
Long Term Incentive Program Total 2013 Program | 12,600,000 | ||
Long Term Incentive Program Total 2014 Program | 13,000,000 | ||
Long Term Incentive Program Total 2011 Program | $8,400,000 | ||
Long Term Incentive Program Total 2011 Program Shares | 106,437 |
Derivative_Financial_Instrumen2
Derivative Financial Instruments (Details) (Nymex Henry Hub [Member], USD $) | Feb. 24, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | MMBTU | MMBTU |
January To March 2015 [Member] | ||
Schedule Of Derivative Instruments [Line Items] | ||
Volume | 210,000 | |
Average Price | 4.54 | |
Fair Value | $29,201 | |
Summer 2015 [Member] | ||
Schedule Of Derivative Instruments [Line Items] | ||
Volume | 150,000 | 522,500 |
Average Price | 2.98 | 3.65 |
Fair Value | $74,989 |
Derivative_Financial_Instrumen3
Derivative Financial Instruments (Details 1) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commodity Derivatives [Abstract] | |||||||||||
Realized (loss) gain on commodity derivatives - natural gas | ($48,170) | ($20,552) | $303,966 | ||||||||
Realized (loss) gain on commodity derivatives - crude oil | 506 | -326 | 0 | ||||||||
Unrealized loss (gain) on commodity derivatives | 130,066 | -25,876 | -230,385 | ||||||||
Gain loss on commodity derivatives | $110,725 | $32,052 | ($15,102) | ($45,273) | ($26,204) | $2,074 | $22,091 | ($44,715) | $82,402 | ($46,754) | $73,581 |
Derivative_Financial_Instrumen4
Derivative Financial Instruments (Details Textuals) | 12 Months Ended |
Dec. 31, 2014 | |
Commodity Derivatives Authorization [Abstract] | |
Commodity Derivatives Board Authorization | 50.00% |
Fair_Value_Measurments_Details
Fair Value Measurments (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Assets Abstract | ||
Derivative assets | $104,190 | $1,415 |
Derivative Liabilities Abstract | ||
Derivative liabilities | 0 | 27,291 |
Fair Value Inputs Level 2 [Member] | ||
Derivative Assets Abstract | ||
Derivative assets | $104,190 |
Fair_Value_Measurments_Details1
Fair Value Measurments (Details 1) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Debt Instrument [Line Items] | ||
Debt carrying value | $3,378,000 | $2,470,000 |
Estimated Fair Value | 3,190,319 | 2,626,349 |
Notes Due 2015 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 100,000 | 100,000 |
Estimated Fair Value | 101,931 | 105,913 |
Debt Instruments Interst Rates | 5.45% | |
Notes Due 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 62,000 | 62,000 |
Estimated Fair Value | 65,027 | 70,228 |
Debt Instruments Interst Rates | 7.31% | |
Notes Due 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 116,000 | 116,000 |
Estimated Fair Value | 116,240 | 126,342 |
Debt Instruments Interst Rates | 4.98% | |
Notes Due 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 200,000 | 200,000 |
Estimated Fair Value | 203,738 | 226,127 |
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 | 414,505 | 466,946 |
Debt Instruments Interst Rates | 5.75% | |
Notes Due 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 173,000 | 173,000 |
Estimated Fair Value | 187,105 | 211,877 |
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 | 201,371 | 229,068 |
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 | 283,335 | 323,732 |
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 | 82,581 | 95,736 |
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 | 30,476 | 35,494 |
Debt Instruments Interst Rates | 4.66% | |
Notes Due October 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 850,000 | 0 |
Estimated Fair Value | 754,485 | 0 |
Debt Instruments Interst Rates | 6.13% | |
Notes Due January 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 90,000 | 90,000 |
Estimated Fair Value | 83,876 | 99,142 |
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 | 147,649 | 175,744 |
Debt Instruments Interst Rates | 4.91% | |
Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt carrying value | 518,000 | 460,000 |
Estimated Fair Value | $518,000 | $460,000 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Loss From Continuing Operations [Abstract] | |||||||||||
United States | $505,689 | $210,580 | ($2,892,207) | ||||||||
Foreign | 31,338 | 23,642 | 15,096 | ||||||||
Income (loss) before income tax (benefit) | $205,829 | $123,974 | $105,505 | $101,719 | $34,262 | $64,291 | $117,868 | $17,801 | $537,027 | $234,222 | ($2,877,111) |
Income_Taxes_Details_1
Income Taxes (Details 1) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current: | |||||||||||
U.S. federal, state and local - current | ($110) | ($8,491) | $9,037 | ||||||||
Foreign - current | -6,709 | 4,881 | 3,326 | ||||||||
(Reduction in) tax benefit on stock based compensation - federal, state and local | 0 | 0 | -4,427 | ||||||||
Total current tax expense (benefit) | -6,819 | -3,610 | 7,936 | ||||||||
Deferred: | |||||||||||
U.S. federal, state and local - deferred | 0 | 0 | -708,160 | ||||||||
Foreign - deferred | 995 | -6 | 11 | ||||||||
Total deferred tax expense (benefit) | 995 | -6 | -708,149 | ||||||||
Total income tax (benefit) | ($3,901) | ($1,383) | ($544) | $4 | ($6,856) | $381 | $1,491 | $1,368 | ($5,824) | ($3,616) | ($700,213) |
Income_Taxes_Details_2
Income Taxes (Details 2) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation Abstract | |||||||||||
Income tax provision (benefit) computed at the U.S. statutory rate | $187,959 | $81,978 | ($1,006,989) | ||||||||
State income tax provision net of federal benefit | 8,023 | 1,329 | -136,112 | ||||||||
Valuation allowance | -199,038 | -81,923 | 446,148 | ||||||||
Tax Effect Of Rate Change | 15,457 | -2,871 | 1,358 | ||||||||
Foreign tax rate differential | -16,314 | -3,508 | -5,531 | ||||||||
Other, net | -1,911 | 1,379 | 913 | ||||||||
Total income tax (benefit) | ($3,901) | ($1,383) | ($544) | $4 | ($6,856) | $381 | $1,491 | $1,368 | ($5,824) | ($3,616) | ($700,213) |
Income_Taxes_Details_3
Income Taxes (Details 3) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred tax assets - current: | ||
Derivative instruments current, net | $0 | $9,636 |
Incentive compensation-other, net | 6,150 | 7,641 |
Deferred Tax Assets Valuation Allowance Net Current | 0 | -16,778 |
Net deferred tax assets - current | 6,150 | 499 |
Deferred Tax Liabilities Current [Abstract] | ||
Derivative instruments, net | 36,788 | 499 |
Deferred Tax Assets Liabilities Net Current | 30,638 | 0 |
Deferred tax assets - non - current [Abstract] | ||
Property and equipment | 0 | 131,340 |
Deferred gain on sale | 48,319 | 52,045 |
U.S. federal tax credit carryforwards | 16,144 | 16,254 |
Net operating loss carryforwards | 147,336 | 71,843 |
US state net operating loss carryforward | 53,654 | 36,205 |
Asset retirement obligations | 45,039 | 26,876 |
Incentive compensation/other, net | 19,142 | 13,007 |
Deferred tax assets noncurrent before valuation allowances | 329,634 | 347,570 |
Valuation allowance | -161,480 | -346,596 |
Net deferred tax assets - non-current | 168,154 | 974 |
Deferred Tax Liabilities - non current [Abstract] | ||
Property and equipment | 137,514 | 0 |
Other | 0 | 968 |
Net non-current tax liabilities | 137,514 | 968 |
Net non-current tax asset | 30,640 | 6 |
Non-US Deferred tax liabilities - non-current | ||
Other - Non US | $992 | $0 |
Income_Taxes_Details_Textuals
Income Taxes (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Statement Income Taxes Details [Abstract] | |||
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate | 35.00% | ||
Deferred Tax Assets, Valuation Allowance | $161,500,000 | $363,400,000 | |
Total change in valuation allowance | 201,900,000 | ||
Change in valuation allowance - earnings | 199,038,000 | 81,923,000 | -446,148,000 |
Change in valuation allowance - equity | 2,900,000 | ||
U.S. federal alternative minimum tax credits | 14,100,000 | ||
Deferred Tax Assets Tax Credit Carryforwards General Business | 500,000 | ||
Foreign tax credit carryforward | 1,700,000 | ||
Deferred Tax Assets Operating Loss Carryforwards Domestic Total | 214,900,000 | 260,100,000 | |
Deferred Tax Assets Operating Loss Carryback Domestic | 54,500,000 | ||
Income Tax Receivable | 8,000,000 | ||
Deferred Tax Assets Operating Loss Carryforwards Domestic | 420,900,000 | ||
State tax net operating loss carryforwards | 798,400,000 | ||
Canadian Operating Loss | 23,800,000 | ||
Income taxes receivable - Canada | $6,200,000 |
Employee_Benefits_Details
Employee Benefits (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
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 | $1.60 | $1.80 |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
MMBTU | |||
Commitements And Contingencies Disclosure [Abstract] | |||
Commitment capacity per day of natural gas | 200 | ||
Increased commitment capacity per day of natural gas | 50 | ||
Demand charges related to remaining contract | $469 | ||
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 | 268 | ||
Committed drilling obligations with rig contractors, total | 33 | ||
Committed drilling obligations with rig contractors, due in one year | 31.6 | ||
Office Space Operating Lease Total Future Minimum Payments | 8.6 | ||
Commitment to office leases, current | 1 | ||
Commitment to office leases, due in two years | 1.3 | ||
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 | 1.1 | ||
Office leases expense | $1 | $1 | $1 |
Oil and gas delivery commitments details | Delivery Commitments. With respect to the Companybs 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, 2015, the Company has long-term natural gas delivery commitments of 1.2 MMMBtu in 2015, 26.2 MMMBtu in 2016, and 7.9 MMMBtu in 2017 under existing agreements. As of February 9, 2015, the Company has long-term crude oil delivery commitments of 2.4 MMBbls in 2015, 2.4 MMBbls in 2016, 1.7 MMBbls in 2017, 0.7 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 Companybs properties, and all of these commitments are priced on a floating basis with reference to an index price. These committed volumes are below the Companybs forecasted 2015 and anticipated 2016 through 2019 production from its available reserves. In addition, none of the Companybs 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 Companybs control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. bRisk Factorsb. The Company believes that its reserves are adequate to meet its commitments. If for some reason the Companybs production is not sufficient to satisfy its commitments, the Company expects to be able to purchase volumes in the market or make other arrangements to satisfy its commitments. |
Credit_Risk_Details
Credit Risk (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Schedule Of Significant Customers [Line Items] | |
Percentage of revenue | 10.00% |
Completion_of_Acquisition_and_2
Completion of Acquisition and Disposition of Assets (Details) (USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Business Acquisition Pro Forma Information [Abstract] | ||
Revenues | $1,421,537 | $1,160,394 |
Net income | $531,188 | $164,303 |
Net income per common share - basic | $3.47 | $1.07 |
Net income per common share - fully diluted | $3.43 | $1.06 |
Completion_of_Acquisition_and_3
Completion of Acquisition and Disposition of Assets (Details 1) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Business Combination Consideration Transferred [Abstract] | |
Adjusted Cash Payment | $890,800,000 |
Assets [Abstract] | |
Joint Interest Billing and Other Receivables SWEPI Properties | -4,182,000 |
Other Current Assets [Abstract] | |
Acquired Condensate Inventory | 819,000 |
Acquired Yard Inventory | 3,515,000 |
Subtotal Other current assets | 4,334,000 |
Proven oil and gas properties | 1,033,960,000 |
Property Plant And Equipment [Abstract] | |
Divested Gathering Systems Pennsylvania Properties | -98,580,000 |
Acquired Other Fixed Assets SWEPI Properties | 869,000 |
Divested Other Fixed Assets Pennsylvania Properties | -50,000 |
Subtotal Property Plant And Equipment | -97,761,000 |
Total assets acquired, net of divest assets | 936,351,000 |
Current Liabilities [Abstract] | |
Current Liabilities Pennsylvania Properties | 8,657,000 |
Current Liabilities SWEPI Properties | -601,000 |
Subtotal Current liabilities | 8,056,000 |
Other long term obligations [Abstract] | |
Acquired Asset Retirement Obligation SWEPI Properties | 53,270,000 |
Divested Asset Retirement Obligation Pennsylvania Properties | -15,760,000 |
Subtotal Other Long Term Obligations | 37,510,000 |
Total Liabilities Net | $45,566,000 |
Completion_of_Acquisition_and_4
Completion of Acquisition and Disposition of Assets (Details Textuals) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
acre | ||
Business Combination Details [Abstract] | ||
Business Combination Gross Purchase Price | $925,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2024 | 850,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2024 Interest Rate | 6.13% | |
Senior Notes Ultra Petroleum Corp Due 2024 Deferred Financing Costs | 13,100,000 | |
Business Combination Integration Related Costs | 600,000 | |
Gas And Oil Developed Acreage Acquired Net | 19,600 | |
Gas And Oil Developed And Undeveloped Acreage Divested Net | 155,000 | |
Adjusted Cash Payment | 890,800,000 | |
Business Combination Non Recurring Transportation Charges | 74,600,000 | 113,400,000 |
Post-Acquisiton Operating Results Revenues | 74,691,000 | |
Post-Acquisition Operating Results Earnings | 23,515,000 | |
Uinta Gross Acquisition Cost | 652,000,000 | |
Senior Notes Ultra Petroleum Corp Due 2018 | $450,000,000 |
Summarized_Quarterly_Financial2
Summarized Quarterly Financial Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Selected Quarterly Financial Information [Abstract] | |||||||||||
Revenues from continuing operations | $319,050 | $288,608 | $296,063 | $326,299 | $225,197 | $221,205 | $261,376 | $225,626 | $1,230,020 | $933,404 | $809,974 |
Gain (loss) on commodity derivatives | 110,725 | 32,052 | -15,102 | -45,273 | -26,204 | 2,074 | 22,091 | -44,715 | 82,402 | -46,754 | 73,581 |
Expenses from continuing operations | 195,083 | 169,669 | 150,850 | 154,829 | 141,753 | 136,389 | 143,002 | 139,994 | 670,431 | 561,138 | |
Ceiling test and other impairments | 0 | 0 | 0 | 0 | 0 | 0 | 2,972,464 | ||||
Interest expense | 42,196 | 29,599 | 27,294 | 27,068 | 25,310 | 25,174 | 25,238 | 25,764 | 126,157 | 101,486 | 88,180 |
Gain on sale of property | 8,022 | 0 | 0 | 0 | 8,022 | 0 | 0 | ||||
Contract Cancellation Fees | 0 | 0 | 0 | 0 | 0 | 0 | 15,469 | ||||
Other (expense) income, net | 5,311 | 2,582 | 2,688 | 2,590 | 2,332 | 2,575 | 2,641 | 2,648 | 13,171 | 10,196 | |
Income (loss) from continuing operations | 205,829 | 123,974 | 105,505 | 101,719 | 34,262 | 64,291 | 117,868 | 17,801 | 537,027 | 234,222 | -2,877,111 |
Income tax (benefit) | -3,901 | -1,383 | -544 | 4 | -6,856 | 381 | 1,491 | 1,368 | -5,824 | -3,616 | -700,213 |
Net income (loss) | $209,730 | $125,357 | $106,049 | $101,715 | $41,118 | $63,910 | $116,377 | $16,433 | $542,851 | $237,838 | ($2,176,898) |
Net (income (loss) per common share - basic | $1.37 | $0.82 | $0.69 | $0.66 | $0.27 | $0.42 | $0.76 | $0.11 | $3.54 | $1.55 | ($14.24) |
Net income (loss) per common share - fully diluted | $1.36 | $0.81 | $0.68 | $0.66 | $0.27 | $0.41 | $0.75 | $0.11 | $3.51 | $1.54 | ($14.24) |
Disclosure_About_Oil_and_Gas_P1
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
bbl | bbl | bbl | |
Oil Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | 34,119,000 | 18,137,000 | 33,081,000 |
Extensions, discoveries and additions | 34,275,000 | 11,329,000 | 5,435,000 |
Sales | 0 | 0 | 0 |
Acquisitions | 9,381,000 | 10,114,000 | 0 |
Production | -3,409,000 | -1,196,000 | -1,282,000 |
Revisions | -6,600,000 | -4,265,000 | -19,097,000 |
Reserves, Ending Balance | 67,766,000 | 34,119,000 | 18,137,000 |
Natural Gas Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | 3,409,742,000 | 2,966,445,000 | 4,778,554,000 |
Extensions, discoveries and additions | 866,513,000 | 1,409,528,000 | 819,896,000 |
Sales | -239,290,000 | 0 | 0 |
Acquisitions | 1,345,964,000 | 0 | 0 |
Production | -228,517,000 | -224,912,000 | -249,310,000 |
Revisions | -323,218,000 | -741,319,000 | -2,382,695,000 |
Reserves, Ending Balance | 4,831,194,000 | 3,409,742,000 | 2,966,445,000 |
Natural Gas Liquids Reserves [Member] | |||
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Reserves, Beginning Balance | 0 | 0 | 0 |
Extensions, discoveries and additions | 210,000 | 0 | 0 |
Sales | 0 | 0 | 0 |
Acquisitions | 21,740,000 | 0 | 0 |
Production | 0 | 0 | 0 |
Revisions | 43,000 | 0 | 0 |
Reserves, Ending Balance | 21,993,000 | 0 | 0 |
Disclosure_About_Oil_and_Gas_P2
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 1) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
bbl | bbl | bbl | bbl | |
Oil Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | 28,481,000 | 20,566,000 | 10,531,000 | 11,794,000 |
Undeveloped | 39,285,000 | 13,553,000 | 7,606,000 | 21,287,000 |
Total Proved | 67,766,000 | 34,119,000 | 18,137,000 | 33,081,000 |
Natural Gas Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | 2,245,004,000 | 1,777,267,000 | 1,820,994,000 | 1,973,391,000 |
Undeveloped | 2,586,190,000 | 1,632,475,000 | 1,145,451,000 | 2,805,163,000 |
Total Proved | 4,831,194,000 | 3,409,742,000 | 2,966,445,000 | 4,778,554,000 |
Natural Gas Liquids Reserves [Member] | ||||
Reserve Quantities [Line Items] | ||||
Developed | 9,118,000 | 0 | 0 | 0 |
Undeveloped | 12,875,000 | 0 | 0 | 0 |
Total Proved | 21,993,000 | 0 | 0 | 0 |
Disclosure_About_Oil_and_Gas_P3
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 2) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | 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 | $27,331,391 | $14,861,131 | $9,380,970 |
Future Production Costs | -8,627,657 | -4,540,209 | -3,217,771 |
Future Development Costs | -3,859,385 | -2,014,751 | -1,661,394 |
Future Income Taxes | -3,898,355 | -1,897,340 | -733,855 |
Future Net Cash Flows | 10,945,994 | 6,408,831 | 3,767,950 |
Discount at 10% | -5,712,511 | -3,220,862 | -1,873,633 |
Standardized measure of discounted future net cash flows | $5,233,483 | $3,187,969 | $1,894,317 |
Disclosure_About_Oil_and_Gas_P4
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized Measure, beginning | $3,187,969,000 | $1,894,317,000 | $3,796,056,000 |
Net revisions of previous quantity estimates | -603,795,000 | -1,089,316,000 | -2,516,159,000 |
Extensions, discoveries and other changes | 1,787,643,000 | 2,098,644,000 | 858,951,000 |
Sales of reserves in place | -398,506,000 | 0 | 0 |
Acquistion of reserves | 2,552,491,000 | 86,196,000 | 0 |
Changes in future development costs | -1,013,652,000 | -252,992,000 | 952,067,000 |
Sales of oil and gas, net of production costs | -949,389,000 | -720,826,000 | -625,745,000 |
Net change in prices and production costs | 1,010,052,000 | 1,204,041,000 | -2,912,698,000 |
Development costs incurred during the period that reduce future development costs | 342,987,000 | 171,149,000 | 316,394,000 |
Accretion of discount | 413,177,000 | 226,326,000 | 529,696,000 |
Net changes in production rates and other | -175,419,000 | 145,289,000 | 363,788,000 |
Net change in income taxes | -920,075,000 | -574,859,000 | 1,131,967,000 |
Aggregrate changes | 2,045,514,000 | 1,293,652,000 | -1,901,739,000 |
Standardized Measure, ending | $5,233,483,000 | $3,187,969,000 | $1,894,317,000 |
Disclosure_About_Oil_and_Gas_P5
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 4) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||
Acquisition costs - unproved properties | $26,106 | $424,540 | $47,979 |
Acquisition costs - proved properties | 895,179 | 224,410 | 0 |
Exploration | 197,664 | 184,007 | 199,569 |
Development | 382,984 | 186,755 | 587,618 |
Total | $1,501,933 | $1,019,712 | $835,166 |
Disclosure_About_Oil_and_Gas_P6
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 5) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract] | |||
Oil and gas revenue | $1,230,020 | $933,404 | $809,974 |
Production expenses | -280,631 | -212,578 | -184,229 |
Depletion and depreciation expense | -292,951 | -243,390 | -388,985 |
Write-downs of proved oil and gas properties | 0 | 0 | -2,972,464 |
Income taxes | 3,736 | -2,821 | 662,698 |
Total | $660,174 | $474,615 | ($2,073,006) |
Disclosure_About_Oil_and_Gas_P7
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Proven Properties [Abstract] | ||
Acquisition, equipment, exploration, drilling and evnironmental costs | $9,731,407 | $7,817,374 |
Less: Accumulated depletion, depreciation and amortization | -6,094,764 | -5,808,836 |
Proved | 3,636,643 | 2,008,538 |
Unproven Properties: | ||
Oil Gas Properties Using Full Cost Method Accounting Unproved | 242,294 | 413,073 |
Net capitalized costs - oil and gas properties | $3,878,937 | $2,421,611 |
Disclosure_About_Oil_and_Gas_P8
Disclosure About Oil and Gas Producing Activities (Unaudited) (Details Textuals) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||
Internal Engineer Experience | 13 | ||
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. B NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. B 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. B Mr. Barg, a Licensed Professional Engineer in the State of Texas (No. 71658), has been practicing consulting petroleum engineering at NSAI since 1989B and has over 6 years of prior industry experience. B He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. B Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998B and has over 14 years of prior industry experience. B 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. B 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. | ||
Reserves Prepared Internally | 2.00% | ||
Weighted Average Sales Price For Proved Reserves Textuals [Abstract] | |||
Weighted Average Sales Price For Proved Reserves Natural Gas | $4.32 | $3.51 | $2.63 |
Weighted Average Sales Price For Proved Reserves Condensate | 80.62 | 84.97 | 87.85 |
Weighted Average Sales Price For Proved Reserves Natural Gas Liquids | $46.27 | $0 | $0 |