Document_And_Entity_Informatio
Document And Entity Information (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Alta Mesa Holdings, LP |
Entity Central Index Key | 1518403 |
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 Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 0 |
Entity Public Float | $0 |
Entity Current Reporting Status | Yes |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
CURRENT ASSETS | ||
Cash and cash equivalents | $1,349 | $6,537 |
Restricted cash | 23,793 | |
Accounts receivable, net | 43,581 | 43,486 |
Other receivables | 33,738 | 2,552 |
Prepaid expenses and other current assets | 2,132 | 3,077 |
Derivative financial instruments | 59,803 | 5,572 |
TOTAL CURRENT ASSETS | 164,396 | 61,224 |
PROPERTY AND EQUIPMENT | ||
Oil and natural gas properties, successful efforts method, net | 686,176 | 691,770 |
Other property and equipment, net | 11,505 | 9,100 |
TOTAL PROPERTY AND EQUIPMENT, NET | 697,681 | 700,870 |
OTHER ASSETS | ||
Long-term restricted cash | 900 | |
Investment in LLC - cost | 9,000 | 9,000 |
Deferred financing costs, net | 8,100 | 10,943 |
Notes receivable | 8,500 | |
Advances to operators | 619 | 6,863 |
Deposits and other assets | 1,124 | 1,186 |
Derivative financial instruments | 27,271 | 3,405 |
TOTAL OTHER ASSETS | 55,514 | 31,397 |
TOTAL ASSETS | 917,591 | 793,491 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 117,560 | 96,095 |
Current portion, asset retirement obligations | 1,136 | 3,844 |
Derivative financial instruments | 4,483 | |
TOTAL CURRENT LIABILITIES | 118,696 | 104,422 |
LONG-TERM LIABILITIES | ||
Asset retirement obligations, net of current portion | 61,736 | 52,179 |
Long-term debt | 767,608 | 766,868 |
Notes payable to founder | 24,540 | 23,331 |
Derivative financial instruments | 4,486 | |
Other long-term liabilities | 6,457 | 2,312 |
TOTAL LONG-TERM LIABILITIES | 860,341 | 849,176 |
TOTAL LIABILITIES | 979,037 | 953,598 |
COMMITMENTS AND CONTINGENCIES (NOTE11) | ||
PARTNERS' CAPITAL (DEFICIT) | -61,446 | -160,107 |
TOTAL LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) | $917,591 | $793,491 |
Consolidated_Statements_Of_Ope
Consolidated Statements Of Operations (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
REVENUES | |||
Oil | $347,842 | $297,836 | $221,800 |
Natural gas | 65,002 | 61,350 | 57,575 |
Natural gas liquids | 18,281 | 15,264 | 15,606 |
Other revenues | 1,003 | 1,207 | 4,567 |
Total | 432,128 | 375,657 | 299,548 |
Gain (loss) on sale of assets | 87,520 | -2,715 | |
Gain (loss) - oil and natural gas derivative contracts | 96,559 | -17,150 | 19,751 |
TOTAL REVENUES | 616,207 | 355,792 | 319,299 |
EXPENSES | |||
Lease and plant operating expense | 73,820 | 70,450 | 69,047 |
Production and ad valorem taxes | 28,214 | 26,369 | 23,485 |
Workover expense | 8,961 | 13,679 | 12,740 |
Exploration expense | 61,912 | 33,065 | 21,912 |
Depreciation, depletion, and amortization expense | 141,804 | 118,558 | 109,252 |
Impairment expense | 74,927 | 143,166 | 96,227 |
Accretion expense | 2,198 | 2,133 | 1,813 |
General and administrative expense | 69,198 | 47,023 | 40,222 |
TOTAL EXPENSES | 461,034 | 454,443 | 374,698 |
INCOME (LOSS) FROM OPERATIONS | 155,173 | -98,651 | -55,399 |
OTHER INCOME (EXPENSE) | |||
Interest expense | -55,812 | -55,188 | -41,932 |
Interest income | 15 | 124 | 99 |
Litigation settlement | 1,250 | ||
TOTAL OTHER INCOME (EXPENSE) | -55,797 | -55,064 | -40,583 |
INCOME (LOSS) BEFORE STATE INCOME TAXES | 99,376 | -153,715 | -95,982 |
BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES | -176 | 107 | |
NET INCOME (LOSS) | $99,200 | ($153,715) | ($95,875) |
Consolidated_Statements_Of_Cha
Consolidated Statements Of Changes In Partners' Capital (Deficit) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract] | |||
Balance, Beginning | ($160,107) | ($6,368) | $89,672 |
Distributions | -539 | -24 | -165 |
Net income (loss) | 99,200 | -153,715 | -95,875 |
Balance, Ending | ($61,446) | ($160,107) | ($6,368) |
Consolidated_Statements_Of_Cas
Consolidated Statements Of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $99,200 | ($153,715) | ($95,875) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, and amortization expense | 141,804 | 118,558 | 109,252 |
Impairment expense | 74,927 | 143,166 | 96,227 |
Accretion expense | 2,198 | 2,133 | 1,813 |
Amortization of loan costs | 2,885 | 2,839 | 2,424 |
Amortization of debt discount | 510 | 510 | 322 |
Dry hole expense | 30,294 | 15,295 | 8,454 |
Expired leases | 4,319 | 3,289 | |
(Gain) loss - derivative contracts | -96,559 | 17,150 | -19,714 |
Settlements on derivative contracts | 9,493 | 18,177 | 35,848 |
Interest converted into debt | 1,209 | 1,208 | 1,212 |
(Gain) loss on sale of assets | -87,520 | 2,715 | |
Changes in assets and liabilities: | |||
Restricted cash unrelated to property divestiture | -106 | 2,305 | -2,305 |
Accounts receivable | -95 | -2,771 | 92 |
Other receivables | -5,686 | 1,863 | -1,609 |
Prepaid expenses and other non-current assets | 7,251 | 4,477 | -5,558 |
Settlement of asset retirement obligation | -3,942 | -1,548 | -3,562 |
Accounts payable, accrued liabilities, and other long-term liabilities | 4,702 | -3,132 | 20,172 |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 184,884 | 172,519 | 147,193 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures for property and equipment | -366,090 | -311,438 | -224,719 |
Acquisitions of property and equipment | -18,110 | -51,377 | -30,346 |
Proceeds from sale of property | 177,476 | 26,668 | |
Proceeds from property divesture classified as restricted cash | 41,590 | ||
Investment in restricted cash related to property divestitures | -24,587 | ||
NET CASH USED IN INVESTING ACTIVITIES | -189,721 | -336,147 | -255,065 |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from long-term debt | 169,500 | 214,500 | 270,000 |
Repayments of long-term debt | -169,270 | -50,000 | -155,500 |
Additions to deferred financing costs | -42 | -97 | -3,307 |
Capital distributions | -539 | -24 | -165 |
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES | -351 | 164,379 | 111,028 |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | -5,188 | 751 | 3,156 |
CASH AND CASH EQUIVALENTS, beginning of period | 6,537 | 5,786 | 2,630 |
CASH AND CASH EQUIVALENTS, end of period | 1,349 | 6,537 | 5,786 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | |||
Cash paid during the period for interest | 51,219 | 50,731 | 36,853 |
Cash paid (received) during the period for state taxes | -123 | 18 | 124 |
Change in asset retirement obligations | 2,643 | 854 | 1,661 |
Asset retirement obligations assumed, purchased properties | 3,002 | 5,480 | 1,476 |
Change in accruals or liabilities for capital expenditures | 23,858 | -14,085 | 22,061 |
Non-cash divestiture of oil and gas properties | ($34,000) |
Nature_Of_Operations
Nature Of Operations | 12 Months Ended |
Dec. 31, 2014 | |
Nature Of Operations [Abstract] | |
Nature Of Operations | NOTE 1 — NATURE OF OPERATIONS |
Nature of Operations. Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our core properties are located in Oklahoma, Louisiana and Texas. | |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2014 | |
Summary Of Significant Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”). As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB. “SEC” means the Securities and Exchange Commission. | |
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. | |
Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. | |
Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. | |
Reclassifications. Certain amounts in the 2013 and 2012 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit). | |
Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. | |
Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2014, the Company had $24.6 million of proceeds from the sale of our Hilltop field Deep Bossier properties in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As December 31, 2014, the Company has utilized or plans to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. The remaining $23.7 million of restricted cash was returned to us in March 2015 and, as such, is classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures. | |
Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $10.3 million and $13.8 million at December 31, 2014 and 2013, respectively. Trade receivables for the sale of oil and natural gas were $35.1 million and $37.8 million at December 31, 2014 and 2013, respectively. See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC. Accounts receivable from ARM Energy Management, LLC were $16.6 million and $7.5 million as of December 31, 2014 and 2013, respectively. | |
Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Accounts receivable are shown net of allowance for doubtful accounts of $1.4 million for the years ended December 31, 2014 and 2013, respectively. | |
Deferred Financing Costs. Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the years ended December 31, 2014, 2013, and 2012, amortization of deferred financing costs included in interest expense amounted to $2.9 million, $2.8 million, and $2.4 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $15.6 million and $12.8 million at December 31, 2014 and 2013, respectively. | |
Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized. | |
Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties. | |
Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. | |
Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized. | |
Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. | |
Our evaluation of the Company’s proved properties resulted in impairment expense of $72.9 million, $135.2 million and $90.3 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |
Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2014, 2013 and 2012, impairment expense of unproved properties was $2.0 million, $8.0 million, and $5.9 million, respectively. | |
Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment. | |
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2014, 2013, and 2012, respectively, the Company did not record any impairment expense related to other long-lived assets. | |
Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. | |
DD&A expense for the years ended December 31, 2014, 2013, and 2012 related to oil and natural gas properties was $139.0 million, $115.5 million, and $106.6 million, respectively. | |
Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2014, 2013, and 2012 was $2.8 million, $3.1 million, and $2.7 million respectively. | |
Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. | |
Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment. | |
Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value). | |
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.” Cash flows from settlements of derivative contracts are classified as operating cash flows. All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows. | |
Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements. | |
The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax. | |
We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. | |
We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2014 and 2013. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2014, 2013, or 2012. | |
The Company’s tax returns for the years ended December 31, 2010 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities. | |
Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed. | |
Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The estimated of fair value of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $380.3 million on December 31, 2014. Derivative financial instruments are carried at fair value. See Note 5 for further information on fair values of financial instruments. See Note 9 for information on long-term debt. | |
Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition. | |
Recent Accounting Pronouncements | |
In April 2014, the Financial Accounting Standards Board issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results. The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations. In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented. ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.” We early adopted ASU 2014-08 as of January 1, 2014 and have provided disclosures in accordance with this new guidance in Note 3. | |
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach. | |
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard requires management to assess the company’s ability to continue as a going concern. Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements. The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements. | |
In January 2015, the FASB issued ASU 2015-01, Extraordinary and Unusual Items. The new standard eliminates the concept of “extraordinary items,” which prior guidance required to be presented separately from income from continuing operations. Items that are infrequent and unusual in nature are to be disclosed either on the face of the financial statements as a component of income from continuing operations or in the notes to the financial statements. ASU 2015-01 is effective for years beginning after December 15, 2015, with early adoption permitted. We adopted the guidance on January 1, 2015. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements. | |
Significant_Acquisitions_And_D
Significant Acquisitions And Divestitures | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Significant Acquisitions And Divestitures [Abstract] | ||||||
Significant Acquisitions And Divestitures | NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES | |||||
Eagleville Divestiture | ||||||
On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”). The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014. We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017. Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014. The initial cash purchase price was $173 million, subsequently adjusted to approximately $171 million for settlement adjustments through December 31, 2014. The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date. As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE. We recorded a preliminary gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on a preliminary allocation of basis between the properties sold and properties retained. | ||||||
The sold portion of Eagleville field contributed approximately $11.1 million in the first quarter of 2014, prior to its sale. The sold portion of Eagleville field contributed approximately $47.0 million and $22.1 million in net pre-tax profit for the years ended December 31, 2013 and 2012. | ||||||
Hilltop Divestiture | ||||||
On October 2, 2013, we closed the sale of certain of our properties in East Texas, comprising a portion of our Hilltop field (“Hilltop divestiture”). The properties sold were primarily producers of dry natural gas located in Leon County, Texas. As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2 BCFE. The cash purchase price was approximately $19 million (net of costs of the sale). There was no material gain on the sale. | ||||||
On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a preliminary gain on the sale of $15.9 million. As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE. | ||||||
The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014 and $6.9 million and $53.2 million in net pre-tax loss during the years ended December 31, 2013 and 2012, respectively. | ||||||
Weeks Island Acquisition | ||||||
On October 1, 2013, we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $42 million plus related abandonment costs. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 million BOE as of the effective date of July 1, 2013. | ||||||
A summary of the consideration paid and the preliminary allocation of the purchase prices are as follows: | ||||||
October 1, | ||||||
2013 | ||||||
(dollars in thousands) | ||||||
Summary of Consideration | ||||||
Cash | $ | 41,841 | ||||
Fair value of asset retirement obligations assumed | 5,311 | |||||
Total | $ | 47,152 | ||||
Summary of Purchase Price Allocation | ||||||
Proved oil and natural gas properties | $ | 30,279 | ||||
Unproved oil and natural gas properties | 16,873 | |||||
Total | $ | 47,152 | ||||
The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2012, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods. | ||||||
Total | Income | |||||
Revenue | (Loss) | |||||
(dollars in thousands) | ||||||
Actual results of Weeks Island included in our statement of operations for the period October 1, 2013 | ||||||
through December 31, 2013 | $ | 10,509 | $ | 8,575 | ||
Pro forma results for the combined entity for the year ended December 31, 2012 | $ | 340,103 | $ | -85,985 | ||
Pro forma results for the combined entity for the year ended December 31, 2013 | $ | 376,063 | $ | -146,866 | ||
Other | ||||||
During 2013, we sold our drilling rig for a cash purchase price of approximately $7.0 million and recorded a loss on sale of approximately $1.2 million. | ||||||
Property_And_Equipment
Property And Equipment | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property And Equipment [Abstract] | |||||||||
Property And Equipment | NOTE 4 — PROPERTY AND EQUIPMENT | ||||||||
Property and equipment consists of the following: | |||||||||
December 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
(dollars in thousands) | |||||||||
OIL AND NATURAL GAS PROPERTIES | |||||||||
Unproved properties | $ | 84,620 | $ | 86,721 | |||||
Accumulated impairment | -3,749 | -7,356 | |||||||
Unproved properties, net | 80,871 | 79,365 | |||||||
Proved oil and natural gas properties | 1,417,785 | 1,405,658 | |||||||
Accumulated depreciation, depletion, amortization and impairment | -812,480 | -793,253 | |||||||
Proved oil and natural gas properties, net | 605,305 | 612,405 | |||||||
TOTAL OIL AND NATURAL GAS PROPERTIES, net | 686,176 | 691,770 | |||||||
LAND | 2,820 | 1,418 | |||||||
OTHER PROPERTY AND EQUIPMENT | |||||||||
Office furniture and equipment, vehicles | 17,302 | 13,802 | |||||||
Accumulated depreciation | -8,617 | -6,120 | |||||||
OTHER PROPERTY AND EQUIPMENT, net | 8,685 | 7,682 | |||||||
TOTAL PROPERTY AND EQUIPMENT, net | $ | 697,681 | $ | 700,870 | |||||
Capitalized Exploratory Well Costs | |||||||||
The following table reflects the net changes in deferred capitalized exploratory well costs during 2014, 2013, and 2012. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year. | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
(dollars in thousands) | |||||||||
Balance, beginning of year | $ | 18,364 | $ | 4,627 | $ | — | |||
Additions to capitalized well costs pending determination of proved reserves | 2,889 | 21,693 | 4,627 | ||||||
Capitalized exploratory well costs charged to expense | -16,706 | -7,956 | — | ||||||
Balance, end of year | $ | 4,547 | $ | 18,364 | $ | 4,627 | |||
The ending balance in deferred capitalized exploratory well costs includes the costs of five wells in two different prospects. We have capitalized $2.2 million and $0 of exploratory well costs covering periods greater than one year at December 31, 2014 and 2013. | |||||||||
Fair_Value_Disclosures
Fair Value Disclosures | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||
Fair Value Disclosures | NOTE 5 — FAIR VALUE DISCLOSURES | |||||||||||
The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances. | ||||||||||||
We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (NYMEX) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2. | ||||||||||||
The fair value of our interest rate derivative contracts, which expired in 2012, was calculated using the Black-Scholes option pricing model and is also considered a Level 2 fair value. | ||||||||||||
Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification. | ||||||||||||
Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. Oil and natural gas properties with a carrying amount of $237.2 million were written down to their fair value of $94.0 million, resulting in an impairment charge of $143.2 million for the year ended December 31, 2013. Oil and natural gas properties with a carrying amount of $363.7 million were written down to their fair value of $267.5 million, resulting in an impairment charge of $96.2 million for the year ended December 31, 2012. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data. | ||||||||||||
In connection with the Stone acquisition in 2013 we recorded oil and natural gas properties with a fair value of $47.2 million. Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties. | ||||||||||||
New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $4.1 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2014. We recorded a total of $6.5 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2013. | ||||||||||||
The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value: | ||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||
(dollars in thousands) | ||||||||||||
At December 31, 2014: | ||||||||||||
Financial Assets: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 140,652 | — | $ | 140,652 | ||||||
Financial Liabilities: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 53,578 | — | $ | 53,578 | ||||||
At December 31, 2013: | ||||||||||||
Financial Assets: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 27,850 | — | $ | 27,850 | ||||||
Financial Liabilities: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 27,842 | — | $ | 27,842 | ||||||
The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. | ||||||||||||
For additional information on derivative contracts, see Note 6. | ||||||||||||
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Financial Instruments [Abstract] | ||||||||||||
Derivative Financial Instruments | NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS | |||||||||||
We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. From time to time we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMBtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes. | ||||||||||||
From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates. | ||||||||||||
We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date. | ||||||||||||
Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account. | ||||||||||||
The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815: | ||||||||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Assets | ||||||||||
31-Dec-14 | Fair Value | offset against assets | presented in | |||||||||
Balance sheet location | of Assets | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 91,341 | $ | -31,538 | $ | 59,803 | ||||||
Derivative financial instruments, long-term assets | 55,325 | -28,054 | 27,271 | |||||||||
Total | $ | 146,666 | $ | -59,592 | $ | 87,074 | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Liabilities | ||||||||||
31-Dec-14 | Fair Value | offset against liabilities | presented in | |||||||||
Balance sheet location | of Liabilities | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 31,538 | $ | -31,538 | $ | — | ||||||
Derivative financial instruments, long-term liabilities | 28,054 | -28,054 | — | |||||||||
Total | $ | 59,592 | $ | -59,592 | $ | — | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Assets | ||||||||||
31-Dec-13 | Fair Value | offset against assets | presented in | |||||||||
Balance sheet location | of Assets | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 13,218 | $ | -7,646 | $ | 5,572 | ||||||
Derivative financial instruments, long-term assets | 14,632 | -11,227 | 3,405 | |||||||||
Total | $ | 27,850 | $ | -18,873 | $ | 8,977 | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Liabilities | ||||||||||
31-Dec-13 | Fair Value | offset against liabilities | presented in | |||||||||
Balance sheet location | of Liabilities | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 12,129 | $ | -7,646 | $ | 4,483 | ||||||
Derivative financial instruments, long-term liabilities | 15,713 | -11,227 | 4,486 | |||||||||
Total | $ | 27,842 | $ | -18,873 | $ | 8,969 | ||||||
The following table summarizes the effect of our derivative instruments in the consolidated statements of operations (dollars in thousands): | ||||||||||||
Derivatives not | ||||||||||||
designated as hedging | Location of | Year Ended December 31, | ||||||||||
instruments under ASC 815 | Gain (Loss) | 2014 | 2013 | 2012 | ||||||||
Oil commodity contracts | Gain (loss) — | |||||||||||
oil and natural gas | ||||||||||||
derivative contracts | $ | 82,510 | $ | -17,715 | $ | 3,720 | ||||||
Natural gas commodity contracts | Gain (loss) — | |||||||||||
oil and natural gas | ||||||||||||
derivative contracts | 14,049 | 565 | 16,031 | |||||||||
Total gains (losses) from oil and | 96,559 | -17,150 | 19,751 | |||||||||
natural gas commodity contracts | ||||||||||||
Interest rate contracts | Interest expense | — | — | -37 | ||||||||
Total gains (losses) from | ||||||||||||
derivatives not designated as hedges | $ | 96,559 | $ | -17,150 | $ | 19,714 | ||||||
Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted. | ||||||||||||
We had the following open derivative contracts for crude oil at December 31, 2014: | ||||||||||||
OIL DERIVATIVE CONTRACTS | ||||||||||||
Volume | Weighted | Range | ||||||||||
Period and Type of Contract | in Bbls | Average | High | Low | ||||||||
2015 | ||||||||||||
Price Swap Contracts | 1,587,000 | 91.39 | 95.02 | 86.45 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 392,350 | 114.10 | 135.98 | 95.50 | ||||||||
Long Put Options | 1,049,350 | 85.78 | 90.00 | 85.00 | ||||||||
Short Put Options | 1,998,350 | 70.05 | 75.00 | 60.00 | ||||||||
2016 | ||||||||||||
Price Swap Contracts | 366,000 | 93.00 | 94.92 | 85.35 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 859,700 | 107.97 | 130.00 | 103.87 | ||||||||
Long Put Options | 859,700 | 85.99 | 95.00 | 80.00 | ||||||||
Short Put Options | 1,225,700 | 68.67 | 75.00 | 60.00 | ||||||||
2017 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 744,950 | 107.99 | 113.83 | 104.15 | ||||||||
Long Put Options | 744,950 | 83.26 | 90.00 | 80.00 | ||||||||
Short Put Options | 744,950 | 63.26 | 70.00 | 60.00 | ||||||||
2018 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 307,400 | 104.39 | 104.65 | 104.15 | ||||||||
Long Put Options | 307,400 | 80.00 | 80.00 | 80.00 | ||||||||
Short Put Options | 307,400 | 60.00 | 60.00 | 60.00 | ||||||||
We had the following open derivative contracts for natural gas at December 31, 2014: | ||||||||||||
NATURAL GAS DERIVATIVE CONTRACTS | ||||||||||||
Volume in | Weighted | Range | ||||||||||
Period and Type of Contract | MMBtu | Average | High | Low | ||||||||
2015 | ||||||||||||
Price Swap Contracts | 3,832,500 | 5.07 | 5.91 | 4.31 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 7,750,000 | 4.59 | 5.75 | 4.51 | ||||||||
Long Put Options | 8,113,500 | 4.01 | 5.00 | 3.50 | ||||||||
Long Call Options | 495,000 | 4.31 | 4.31 | 4.31 | ||||||||
Short Put Options | 9,116,000 | 3.34 | 4.45 | 3.25 | ||||||||
2016 | ||||||||||||
Price Swap Contracts | 8,418,000 | 4.22 | 4.23 | 4.22 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 455,000 | 7.50 | 7.50 | 7.50 | ||||||||
Long Put Options | 455,000 | 5.50 | 5.50 | 5.50 | ||||||||
Short Put Options | 1,681,100 | 3.64 | 4.00 | 3.50 | ||||||||
2017 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 6,570,000 | 5.00 | 5.00 | 4.98 | ||||||||
Long Put Options | 6,570,000 | 4.50 | 4.50 | 4.50 | ||||||||
Short Put Options | 6,570,000 | 4.00 | 4.00 | 4.00 | ||||||||
2018 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 5,475,000 | 5.50 | 5.53 | 5.48 | ||||||||
Long Put Options | 5,475,000 | 4.50 | 4.50 | 4.50 | ||||||||
Short Put Options | 5,475,000 | 4.00 | 4.00 | 4.00 | ||||||||
In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks. | ||||||||||||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Asset Retirement Obligations [Abstract] | |||||||||
Asset Retirement Obligations | NOTE 7 — ASSET RETIREMENT OBLIGATIONS | ||||||||
A summary of the changes in our asset retirement obligations is included in the table below: | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
(dollars in thousands) | |||||||||
Balance, beginning of year | $ | 56,023 | $ | 48,593 | $ | 46,096 | |||
Liabilities incurred | 1,129 | 1,052 | 787 | ||||||
Liabilities assumed with acquired producing properties | 3,002 | 5,480 | 1,476 | ||||||
Liabilities settled | -3,942 | -1,548 | -3,562 | ||||||
Liabilities transferred in sales of properties | -1,886 | -606 | — | ||||||
Revisions to estimates | 6,348 | 919 | 1,983 | ||||||
Accretion expense | 2,198 | 2,133 | 1,813 | ||||||
Balance, end of year | 62,872 | 56,023 | 48,593 | ||||||
Less: Current portion | 1,136 | 3,844 | 64 | ||||||
Long term portion | $ | 61,736 | $ | 52,179 | $ | 48,529 | |||
The total revisions included $2.9 million, $0.4 million, and $0.9 million related to additions to property, plant and equipment for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | NOTE 8 — RELATED PARTY TRANSACTIONS |
We have notes payable to our founder which bear interest at 10% with a balance of $24.5 million and $23.3 million at December 31, 2014 and 2013, respectively. See further information at Note 9. | |
During 2014 and 2013 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received capital distributions from us of $516,500 and $17,500, respectively. | |
David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2014, 2013 and 2012 were approximately $150,000, $175,000 and $116,000. The contract may be terminated by either party without penalty upon 30 days’ notice. | |
David McClure, our Vice President, Louisiana Operations, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $450,000, $390,000 and $327,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. | |
David Pepper, one of our Landmen, and the nephew of our Vice President, Land and Business Development, David Murrell, received total compensation of $260,000, $125,000 and $105,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. | |
On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B unitholder, High Mesa. We recorded $25.5 million in other receivable and $8.5 million in long term note receivable, while recording no gain or loss on the sale at December 31, 2014. On January 2, 2015, the receivable of $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from NWGP to HMS, a subsidiary of the Parent company High Mesa. The Company believes the note to be fully collectible and accordingly has not recorded a reserve. | |
Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 12. | |
Long_Term_Debt
Long Term Debt | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Long Term Debt [Abstract] | ||||||
Long Term Debt | NOTE 9 — LONG TERM DEBT | |||||
Long-term debt consists of the following: | ||||||
December 31, | December 31, | |||||
2014 | 2013 | |||||
(dollars in thousands) | ||||||
Credit Facility | $ | 319,520 | $ | 319,290 | ||
Senior Notes | 448,088 | 447,578 | ||||
Total long-term debt | $ | 767,608 | $ | 766,868 | ||
Notes payable to founder | $ | 24,540 | $ | 23,331 | ||
Credit Facility. On May 13, 2010, we entered into a Sixth Amended and Restated Credit Agreement (as amended, the “credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and natural gas properties. The credit facility borrowing base is redetermined periodically and, as of December 31, 2014, the borrowing base under the facility was $375.0 million. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 2.89% as of December 31, 2014 and 2.75% as of December 31, 2013. The letters of credit outstanding as of December 31, 2014 and 2013 were $0.9 million and $65,000, respectively. | ||||||
The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expenses of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00. The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months. | ||||||
As of December 31, 2014, we were in compliance with all covenants. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility when it is next redetermined in May 2015. | ||||||
Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%. Interest is payable semi-annually each April 15th and October 15th. The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.9 million and $2.4 million at December 31, 2014 and December 31, 2013, respectively. | ||||||
The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%. Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016, respectively. | ||||||
Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $24.5 million and $23.3 million at December 31, 2014 and December 31, 2013, respectively. The maturity date was extended on March 25, 2014, from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity. The notes are convertible into shares of our Class B partner, High Mesa, common stock upon certain conditions in the event of an initial public offering. | ||||||
These founder notes are unsecured and are subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 15, the founder notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner. The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments. | ||||||
Interest on the notes payable to our founder amounted to $1.2 million during each of 2014, 2013, and 2012. Such amounts have been added to the balance of the founder notes. | ||||||
Future maturities of long-term debt, including the notes payable to our founder and unamortized discount, at December 31, 2014 are as follows (dollars in thousands): | ||||||
Year ending December 31, | ||||||
2015 | $ | — | ||||
2016 | 319,520 | |||||
2017 | — | |||||
2018 | 450,000 | |||||
2019 | — | |||||
Thereafter | 24,540 | |||||
$ | 794,060 | |||||
The credit facility and senior notes include covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At December 31, 2014, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments. | ||||||
Accounts_Payable_And_Accrued_L
Accounts Payable And Accrued Liabilities | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Accounts Payable And Accrued Liabilities [Abstract] | ||||||
Accounts Payable And Accrued Liabilities | NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES | |||||
The following provides the detail of accounts payable and accrued liabilities: | ||||||
December 31, | December 31, | |||||
2014 | 2013 | |||||
(dollars in thousands) | ||||||
Capital expenditures | $ | 32,990 | $ | 18,629 | ||
Revenues and royalties payable | 7,302 | 9,699 | ||||
Operating expenses/taxes | 20,716 | 17,071 | ||||
Interest | 9,136 | 9,146 | ||||
Compensation | 10,586 | 8,862 | ||||
Other | 2,605 | 2,711 | ||||
Total accrued liabilities | 83,335 | 66,118 | ||||
Accounts payable | 34,225 | 29,977 | ||||
Accounts payable and accrued liabilities | $ | 117,560 | $ | 96,095 | ||
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Commitments And Contingencies [Abstract] | ||||
Commitments And Contingencies | NOTE 11 — COMMITMENTS AND CONTINGENCIES | |||
Contingencies | ||||
Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East: On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana. Case No. 2013-6911 was filed in state court and subsequently remanded to federal court. The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects. The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry. Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines. Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance. Our wholly-owned subsidiary The Meridian Resource Company, LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area. Almost all of these wells are inactive. In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit. However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party. | ||||
On February 13, 2015, the case was dismissed by the U.S. District Judge. As of December 31, we have not provided any amount for this matter in our consolidated financial statements. | ||||
Environmental claims: Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our consolidated financial statements at December 31, 2014. | ||||
Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management has established a liability for soil contamination in Florida of $1.1 million at December 31, 2014 and $1.1 million at December 31, 2013, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets. | ||||
Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made. | ||||
Performance appreciation rights: In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial value. The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During 2014, we granted 271,500 PARs at a weighted average initial value of $33.19. Subsequently to year end, 27,500 PARs with present value of $40 were terminated, resulting in 244,000 PARs issued at a weighted average value of $32.42. We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2014. | ||||
Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. | ||||
We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met. | ||||
Commitments | ||||
Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for four years or less. Rent expense, including office space and compressors, for the years ended December 31, 2014, 2013, and 2012 amounted to approximately $5.7 million, $5.3 million, and $4.5 million, respectively. | ||||
At December 31, 2014, future base rentals for non-cancelable operating leases are as follows (dollars in thousands): | ||||
Year Ending December 31, | ||||
2015 | $ | 2,004 | ||
2016 | 1,562 | |||
2017 | 1,552 | |||
2018 | 1,529 | |||
2019 | 1,580 | |||
Thereafter | 4,420 | |||
$ | 12,647 | |||
Additionally, at December 31, 2014, the Company had posted bonds in the aggregate amount of $24.2 million, primarily to cover future abandonment costs. | ||||
Major_Customers
Major Customers | 12 Months Ended |
Dec. 31, 2014 | |
Major Customers [Abstract] | |
Major Customers | NOTE 12 — MAJOR CUSTOMERS |
We sell our oil and natural gas primarily under a contract with ARM Energy Management, LLC (“AEM”). Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee. Sales to AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015. During the second half of 2013 and throughout 2014, we sold the majority of our production from operated fields to AEM. Production from non-operated fields, the most significant of which were our Eagleville oil field in South Texas and our Hilltop natural gas field in East Texas, was marketed on our behalf by the operators of those properties. Production from the Eagleville field was sold by Murphy Oil Corporation (“Murphy”), the operator of that property. Production from the Hilltop field was sold primarily by EnCana Oil & Gas (USA), Inc. (“EnCana”), the operator of a substantial portion of the wells in that field. | |
For the year ended December 31, 2014, revenues from AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, one other major customer, Murphy accounted for 10% or more of revenues, with revenues excluding hedging activities of $61.2 million. For the year ended December 31, 2013, revenues from AEM were $61.3 million, or 16% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, three other major customers accounted for 10% or more of those revenues individually, with contributions of $119.3 million (Murphy), $53.9 million (Shell Trading (US) Company), and $42.0 million (Plains Marketing and Transportation, Inc.) On the same basis, for the year ended December 31, 2012, three major customers accounted for 10% or more of those revenues individually, with contributions of $63.3 million (Shell Trading (US) Company), $50.1 million (Murphy), and $44.8 million (EnCana). We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available. | |
401k_Savings_Plan
401(k) Savings Plan | 12 Months Ended |
Dec. 31, 2014 | |
Savings Plan [Abstract] | |
401(k) Savings Plan | NOTE 13 — 401(k) SAVINGS PLAN |
Employees of Alta Mesa Services and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 50% of an employee’s salary deferral contribution up to a maximum of 8% of an employee’s salary. Matching contributions to the plan were approximately $683,000, $585,000, and $422,000 for the years ended December 31, 2014, 2013, and 2012, respectively. | |
Significant_Risks_And_Uncertai
Significant Risks And Uncertainties | 12 Months Ended |
Dec. 31, 2014 | |
Significant Risks And Uncertainties [Abstract] | |
Significant Risks And Uncertainties | NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES |
Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of the year. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6. | |
Partners_Capital_Deficit
Partners' Capital (Deficit) | 12 Months Ended |
Dec. 31, 2014 | |
Partners' Capital (Deficit) [Abstract] | |
Partners' Capital (Deficit) | NOTE 15 — PARTNERS’ CAPITAL (DEFICIT) |
Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our Class B partner was Alta Mesa Investment Holdings, Inc. (“AMIH”). AMIH has subsequently changed its name to High Mesa, Inc. (“High Mesa”). Prior to March 25, 2014, AMIH was an affiliate of Denham Capital Management LP, a private equity firm focused on energy and commodities. | |
On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”). Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our Board of Directors includes one member nominated by Highbridge and four members nominated by the Class A partners. High Mesa is our sole Class B partner. | |
Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Partnership Agreement. The Class B limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture. | |
Ownership of High Mesa is distributed among two classes of equity. Highbridge owns all of the convertible PIK preferred stock of High Mesa. The common stock of High Mesa is owned by our Class A partners. Highbridge also holds senior PIK notes issued by High Mesa. | |
Distribution and Income Allocation: In connection with the recapitalization, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until all principal and interest has been extinguished under the senior PIK notes issued by High Mesa to Highbridge. After such extinguishment of the senior PIK notes, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement | |
The Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes. | |
Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B Partners according to a variable formula as defined in the Partnership Agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. The Class B Partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties. | |
Subsequent_Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 16 — SUBSEQUENT EVENTS |
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements. | |
Subsidiary_Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2014 | |
Subsidiary Guarantors [Abstract] | |
Subsidiary Guarantors | NOTE 17 — SUBSIDIARY GUARANTORS |
All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior notes and our credit facility. | |
Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company. | |
Supplemental_Quarterly_Informa
Supplemental Quarterly Information | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Supplemental Quarterly Information [Abstract] | ||||||||||||
Supplemental Quarterly Information | ||||||||||||
NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) | ||||||||||||
Results of operations by quarter for the year ended December 31, 2014 were: | ||||||||||||
Quarter Ended | ||||||||||||
2014 | 31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||
(dollars in thousands) | ||||||||||||
Revenues (1) | $ | 165,891 | $ | 86,254 | $ | 184,111 | $ | 179,951 | ||||
Income (loss) from operations (2) | 71,461 | -25,186 | 73,025 | 35,873 | ||||||||
Net income (loss) | $ | 56,893 | $ | -38,812 | $ | 59,326 | $ | 21,793 | ||||
-1 | Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively. | |||||||||||
-2 | Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively. | |||||||||||
Results of operations by quarter for the year ended December 31, 2013 were: | ||||||||||||
Quarter Ended | ||||||||||||
2013 | 31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||
(dollars in thousands) | ||||||||||||
Revenues | $ | 68,578 | $ | 123,531 | $ | 77,759 | $ | 85,924 | ||||
Income (loss) from operations (3) | -1,066 | 29,799 | -11,915 | -115,469 | ||||||||
Net income (loss) | $ | -14,286 | $ | 16,168 | $ | -25,737 | $ | -129,860 | ||||
-3 | Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively. | |||||||||||
Supplemental_Oil_And_Natural_G
Supplemental Oil And Natural Gas Disclosures | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract] | |||||||||||
Supplemental Oil And Natural Gas Disclosures (Unaudited) | NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) | ||||||||||
The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. | |||||||||||
Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. | |||||||||||
Estimated Quantities of Proved Reserves | |||||||||||
The following table sets forth our net proved reserves as of December 31, 2014, 2013, and 2012, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. | |||||||||||
Oil | Gas | NGL's | BOE | ||||||||
(MBbls) | (MMcf) | (MBbls) | (MBbls) | ||||||||
Total Proved Reserves: | |||||||||||
Balance at December 31, 2011 | 16,933 | 217,266 | 4,845 | 57,989 | |||||||
Production | -2,138 | -21,372 | -365 | -6,065 | |||||||
Purchases in place | 335 | 6,619 | 8 | 1,446 | |||||||
Discoveries and extensions | 10,173 | 18,870 | 1,187 | 14,505 | |||||||
Revisions of previous quantity estimates and other | -4,683 | -68,894 | 20 | -16,144 | |||||||
Balance at December 31, 2012 | 20,620 | 152,489 | 5,695 | 51,731 | |||||||
Production | -2,897 | -16,664 | -398 | -6,072 | |||||||
Purchases in place | 1,462 | 1,265 | — | 1,673 | |||||||
Discoveries and extensions | 14,541 | 29,012 | 1,969 | 21,345 | |||||||
Sales of reserves in place | -13 | -10,912 | — | -1,832 | |||||||
Revisions of previous quantity estimates and other | -1,196 | -22,925 | -1,531 | -6,549 | |||||||
Balance at December 31, 2013 | 32,517 | 132,265 | 5,735 | 60,296 | |||||||
Production | -3,770 | -14,449 | -537 | -6,715 | |||||||
Purchases in place | 610 | 327 | — | 665 | |||||||
Discoveries and extensions | 13,281 | 28,822 | 4,119 | 22,204 | |||||||
Sales of reserves in place | -6,298 | -35,857 | -949 | -13,223 | |||||||
Revisions of previous quantity estimates and other | -4,996 | -7,960 | 20 | -6,304 | |||||||
Balance at December 31, 2014 | 31,344 | 103,148 | 8,388 | 56,923 | |||||||
Proved Developed Reserves: | |||||||||||
Balance at December 31, 2012 | 10,467 | 111,206 | 4,209 | 33,211 | |||||||
Balance at December 31, 2013 | 16,335 | 92,640 | 3,138 | 34,913 | |||||||
Balance at December 31, 2014 | 15,182 | 63,334 | 4,028 | 29,765 | |||||||
Proved Undeveloped Reserves: | |||||||||||
Balance at December 31, 2012 | 10,153 | 41,283 | 1,486 | 18,520 | |||||||
Balance at December 31, 2013 | 16,182 | 39,625 | 2,597 | 25,383 | |||||||
Balance at December 31, 2014 | 16,162 | 39,814 | 4,360 | 27,158 | |||||||
Capitalized Costs Relating to Oil and Natural Gas Producing Activities | |||||||||||
December 31, | |||||||||||
2014 | 2013 | ||||||||||
(dollars in thousands) | |||||||||||
Capitalized costs: | |||||||||||
Proved properties | $ | 1,417,785 | $ | 1,405,658 | |||||||
Unproved properties | 84,620 | 86,721 | |||||||||
Total | 1,502,405 | 1,492,379 | |||||||||
Accumulated depreciation, depletion, amortization and impairment | -816,229 | -800,609 | |||||||||
Net capitalized costs | $ | 686,176 | $ | 691,770 | |||||||
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | |||||||||||
Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress. | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Costs incurred during the year: | |||||||||||
Property acquisition costs | |||||||||||
Unproved | $ | 33,787 | $ | 34,884 | $ | 31,695 | |||||
Proved (1) | 7,462 | 35,954 | 12,192 | ||||||||
Exploration | 59,201 | 55,300 | 46,559 | ||||||||
Development (2) | 341,594 | 242,912 | 200,974 | ||||||||
$ | 442,044 | $ | 369,050 | $ | 291,420 | ||||||
-1 | Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million). | ||||||||||
(2) Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||||
Standardized Measure of Discounted Future Net Cash Flows | |||||||||||
The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. | |||||||||||
Future cash inflows as of December 31, 2014 and 2013 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. | |||||||||||
Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. | |||||||||||
The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2014, 2013, and 2012: | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Future cash flows | $ | 3,737,412 | $ | 3,959,938 | $ | 2,742,588 | |||||
Future production costs | -991,149 | -1,146,123 | -928,398 | ||||||||
Future development costs | -450,659 | -474,191 | -348,042 | ||||||||
Future taxes on income | — | — | — | ||||||||
Future net cash flows | 2,295,604 | 2,339,624 | 1,466,148 | ||||||||
Discount to present value at 10 percent per annum | -877,558 | -933,350 | -551,727 | ||||||||
Standardized measure of discounted future net cash flows | $ | 1,418,046 | $ | 1,406,274 | $ | 914,421 | |||||
Base price for crude oil, per Bbl, in the above computation was: | $ | 94.99 | $ | 96.78 | $ | 94.71 | |||||
Base price for natural gas, per Mcf, in the above computation was: | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||
No consideration was given to the Company’s hedged transactions. | |||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows | |||||||||||
The following table sets forth the changes in standardized measure of discounted future net cash flows: | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Balance at beginning of year | $ | 1,406,274 | $ | 914,421 | $ | 1,070,196 | |||||
Sales of oil and natural gas, net of production costs | -320,130 | -263,952 | -189,709 | ||||||||
Changes in sales and transfer prices, net of production costs | -153,770 | 69,609 | -291,285 | ||||||||
Revisions of previous quantity estimates | -477,377 | -150,634 | -250,424 | ||||||||
Purchases of reserves-in-place | 21,633 | 93,877 | 10,283 | ||||||||
Sales of reserves-in-place | -107,414 | -11,193 | — | ||||||||
Current year discoveries and extensions | 701,820 | 621,832 | 420,496 | ||||||||
Changes in estimated future development costs | 2,591 | 11,623 | 54,493 | ||||||||
Development costs incurred during the year | 161,357 | 75,973 | 49,834 | ||||||||
Accretion of discount | 140,627 | 91,442 | 107,020 | ||||||||
Net change in income taxes | — | — | — | ||||||||
Change in production rate (timing) and other | 42,435 | -46,724 | -66,483 | ||||||||
Net change | 11,772 | 491,853 | -155,775 | ||||||||
Balance at end of year | $ | 1,418,046 | $ | 1,406,274 | $ | 914,421 | |||||
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2014 | |
Summary Of Significant Accounting Policies [Abstract] | |
Principles Of Consolidation | Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. |
Use Of Estimates | Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. |
Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. | |
Reclassifications | Reclassifications. Certain amounts in the 2013 and 2012 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit). |
Cash And Cash Equivalents | Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. |
Restricted Cash | Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2014, the Company had $24.6 million of proceeds from the sale of our Hilltop field Deep Bossier properties in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As December 31, 2014, the Company has utilized or plans to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. The remaining $23.7 million of restricted cash was returned to us in March 2015 and, as such, is classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures. |
Accounts Receivable | Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized. Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $10.3 million and $13.8 million at December 31, 2014 and 2013, respectively. Trade receivables for the sale of oil and natural gas were $35.1 million and $37.8 million at December 31, 2014 and 2013, respectively. See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC. Accounts receivable from ARM Energy Management, LLC were $16.6 million and $7.5 million as of December 31, 2014 and 2013, respectively. |
Allowance For Doubtful Accounts | Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Accounts receivable are shown net of allowance for doubtful accounts of $1.4 million for the years ended December 31, 2014 and 2013, respectively. |
Deferred Financing Costs | Deferred Financing Costs. Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the years ended December 31, 2014, 2013, and 2012, amortization of deferred financing costs included in interest expense amounted to $2.9 million, $2.8 million, and $2.4 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $15.6 million and $12.8 million at December 31, 2014 and 2013, respectively. |
Property And Equipment | Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized. |
Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties. | |
Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly. | |
Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized. | |
Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. | |
Our evaluation of the Company’s proved properties resulted in impairment expense of $72.9 million, $135.2 million and $90.3 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |
Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2014, 2013 and 2012, impairment expense of unproved properties was $2.0 million, $8.0 million, and $5.9 million, respectively. | |
Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment. | |
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2014, 2013, and 2012, respectively, the Company did not record any impairment expense related to other long-lived assets. | |
Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. | |
DD&A expense for the years ended December 31, 2014, 2013, and 2012 related to oil and natural gas properties was $139.0 million, $115.5 million, and $106.6 million, respectively. | |
Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2014, 2013, and 2012 was $2.8 million, $3.1 million, and $2.7 million respectively. | |
Investment | Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. |
Asset Retirement Obligations | Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset. The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. Accretion expense is recognized as the discounted liability is accreted to its expected settlement value. Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment. |
Derivative Financial Instruments | Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value). |
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.” Cash flows from settlements of derivative contracts are classified as operating cash flows. All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows. | |
Income Taxes | Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements. |
The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax. | |
We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. | |
We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2014 and 2013. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2014, 2013, or 2012. | |
The Company’s tax returns for the years ended December 31, 2010 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities. | |
Revenue Recognition | Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed. |
Fair Value Of Financial Instruments | Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The estimated of fair value of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $380.3 million on December 31, 2014. Derivative financial instruments are carried at fair value. See Note 5 for further information on fair values of financial instruments. See Note 9 for information on long-term debt. |
Acquisitions | Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements |
In April 2014, the Financial Accounting Standards Board issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results. The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations. In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented. ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.” We early adopted ASU 2014-08 as of January 1, 2014 and have provided disclosures in accordance with this new guidance in Note 3. | |
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach. | |
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard requires management to assess the company’s ability to continue as a going concern. Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements. The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements. | |
In January 2015, the FASB issued ASU 2015-01, Extraordinary and Unusual Items. The new standard eliminates the concept of “extraordinary items,” which prior guidance required to be presented separately from income from continuing operations. Items that are infrequent and unusual in nature are to be disclosed either on the face of the financial statements as a component of income from continuing operations or in the notes to the financial statements. ASU 2015-01 is effective for years beginning after December 15, 2015, with early adoption permitted. We adopted the guidance on January 1, 2015. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements. | |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Policy) | 12 Months Ended |
Dec. 31, 2014 | |
Derivative Financial Instruments [Line Items] | |
Derivatives And Hedging | Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value). |
Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.” Cash flows from settlements of derivative contracts are classified as operating cash flows. All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows. | |
Commodity Contract [Member] | |
Derivative Financial Instruments [Line Items] | |
Derivatives, Use of Derivatives | We account for our derivative contracts under the provisions of ASC 815, "Derivatives and Hedging." We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. From time to time we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMBtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. |
Interest Rate Contracts [Member] | |
Derivative Financial Instruments [Line Items] | |
Derivatives, Use of Derivatives | From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates. |
Netting Presentation for Derivatives Policy [Member] | |
Derivative Financial Instruments [Line Items] | |
Derivatives And Hedging | Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account. |
Significant_Acquisitions_And_D1
Significant Acquisitions And Divestitures (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Significant Acquisitions And Divestitures [Abstract] | ||||||
Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices | ||||||
October 1, | ||||||
2013 | ||||||
(dollars in thousands) | ||||||
Summary of Consideration | ||||||
Cash | $ | 41,841 | ||||
Fair value of asset retirement obligations assumed | 5,311 | |||||
Total | $ | 47,152 | ||||
Summary of Purchase Price Allocation | ||||||
Proved oil and natural gas properties | $ | 30,279 | ||||
Unproved oil and natural gas properties | 16,873 | |||||
Total | $ | 47,152 | ||||
Summary Of Pro Forma Information | ||||||
Total | Income | |||||
Revenue | (Loss) | |||||
(dollars in thousands) | ||||||
Actual results of Weeks Island included in our statement of operations for the period October 1, 2013 | ||||||
through December 31, 2013 | $ | 10,509 | $ | 8,575 | ||
Pro forma results for the combined entity for the year ended December 31, 2012 | $ | 340,103 | $ | -85,985 | ||
Pro forma results for the combined entity for the year ended December 31, 2013 | $ | 376,063 | $ | -146,866 | ||
Property_And_Equipment_Tables
Property And Equipment (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property And Equipment [Abstract] | |||||||||
Property And Equipment | |||||||||
December 31, | December 31, | ||||||||
2014 | 2013 | ||||||||
(dollars in thousands) | |||||||||
OIL AND NATURAL GAS PROPERTIES | |||||||||
Unproved properties | $ | 84,620 | $ | 86,721 | |||||
Accumulated impairment | -3,749 | -7,356 | |||||||
Unproved properties, net | 80,871 | 79,365 | |||||||
Proved oil and natural gas properties | 1,417,785 | 1,405,658 | |||||||
Accumulated depreciation, depletion, amortization and impairment | -812,480 | -793,253 | |||||||
Proved oil and natural gas properties, net | 605,305 | 612,405 | |||||||
TOTAL OIL AND NATURAL GAS PROPERTIES, net | 686,176 | 691,770 | |||||||
LAND | 2,820 | 1,418 | |||||||
OTHER PROPERTY AND EQUIPMENT | |||||||||
Office furniture and equipment, vehicles | 17,302 | 13,802 | |||||||
Accumulated depreciation | -8,617 | -6,120 | |||||||
OTHER PROPERTY AND EQUIPMENT, net | 8,685 | 7,682 | |||||||
TOTAL PROPERTY AND EQUIPMENT, net | $ | 697,681 | $ | 700,870 | |||||
Capitalized Exploratory Well Costs Roll Forward Table | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
(dollars in thousands) | |||||||||
Balance, beginning of year | $ | 18,364 | $ | 4,627 | $ | — | |||
Additions to capitalized well costs pending determination of proved reserves | 2,889 | 21,693 | 4,627 | ||||||
Capitalized exploratory well costs charged to expense | -16,706 | -7,956 | — | ||||||
Balance, end of year | $ | 4,547 | $ | 18,364 | $ | 4,627 | |||
Fair_Value_Disclosures_Tables
Fair Value Disclosures (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||
Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis | ||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||
(dollars in thousands) | ||||||||||||
At December 31, 2014: | ||||||||||||
Financial Assets: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 140,652 | — | $ | 140,652 | ||||||
Financial Liabilities: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 53,578 | — | $ | 53,578 | ||||||
At December 31, 2013: | ||||||||||||
Financial Assets: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 27,850 | — | $ | 27,850 | ||||||
Financial Liabilities: | ||||||||||||
Derivative contracts for oil and natural gas | — | $ | 27,842 | — | $ | 27,842 | ||||||
Derivative_Financial_Instrumen2
Derivative Financial Instruments (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative [Line Items] | ||||||||||||
Fair Values Of Derivative Contracts | ||||||||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Assets | ||||||||||
31-Dec-14 | Fair Value | offset against assets | presented in | |||||||||
Balance sheet location | of Assets | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 91,341 | $ | -31,538 | $ | 59,803 | ||||||
Derivative financial instruments, long-term assets | 55,325 | -28,054 | 27,271 | |||||||||
Total | $ | 146,666 | $ | -59,592 | $ | 87,074 | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Liabilities | ||||||||||
31-Dec-14 | Fair Value | offset against liabilities | presented in | |||||||||
Balance sheet location | of Liabilities | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 31,538 | $ | -31,538 | $ | — | ||||||
Derivative financial instruments, long-term liabilities | 28,054 | -28,054 | — | |||||||||
Total | $ | 59,592 | $ | -59,592 | $ | — | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Assets | ||||||||||
31-Dec-13 | Fair Value | offset against assets | presented in | |||||||||
Balance sheet location | of Assets | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current assets | $ | 13,218 | $ | -7,646 | $ | 5,572 | ||||||
Derivative financial instruments, long-term assets | 14,632 | -11,227 | 3,405 | |||||||||
Total | $ | 27,850 | $ | -18,873 | $ | 8,977 | ||||||
Net Fair | ||||||||||||
Gross | Gross amounts | Value of Liabilities | ||||||||||
31-Dec-13 | Fair Value | offset against liabilities | presented in | |||||||||
Balance sheet location | of Liabilities | in the Balance Sheet | the Balance Sheet | |||||||||
(dollars in thousands) | ||||||||||||
Derivative financial instruments, current liabilities | $ | 12,129 | $ | -7,646 | $ | 4,483 | ||||||
Derivative financial instruments, long-term liabilities | 15,713 | -11,227 | 4,486 | |||||||||
Total | $ | 27,842 | $ | -18,873 | $ | 8,969 | ||||||
Effect Of Derivative Instruments In The Consolidated Statements Of Operations | ||||||||||||
Derivatives not | ||||||||||||
designated as hedging | Location of | Year Ended December 31, | ||||||||||
instruments under ASC 815 | Gain (Loss) | 2014 | 2013 | 2012 | ||||||||
Oil commodity contracts | Gain (loss) — | |||||||||||
oil and natural gas | ||||||||||||
derivative contracts | $ | 82,510 | $ | -17,715 | $ | 3,720 | ||||||
Natural gas commodity contracts | Gain (loss) — | |||||||||||
oil and natural gas | ||||||||||||
derivative contracts | 14,049 | 565 | 16,031 | |||||||||
Total gains (losses) from oil and | 96,559 | -17,150 | 19,751 | |||||||||
natural gas commodity contracts | ||||||||||||
Interest rate contracts | Interest expense | — | — | -37 | ||||||||
Total gains (losses) from | ||||||||||||
derivatives not designated as hedges | $ | 96,559 | $ | -17,150 | $ | 19,714 | ||||||
Oil [Member] | ||||||||||||
Derivative [Line Items] | ||||||||||||
Open Derivative Contracts | ||||||||||||
Volume | Weighted | Range | ||||||||||
Period and Type of Contract | in Bbls | Average | High | Low | ||||||||
2015 | ||||||||||||
Price Swap Contracts | 1,587,000 | 91.39 | 95.02 | 86.45 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 392,350 | 114.10 | 135.98 | 95.50 | ||||||||
Long Put Options | 1,049,350 | 85.78 | 90.00 | 85.00 | ||||||||
Short Put Options | 1,998,350 | 70.05 | 75.00 | 60.00 | ||||||||
2016 | ||||||||||||
Price Swap Contracts | 366,000 | 93.00 | 94.92 | 85.35 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 859,700 | 107.97 | 130.00 | 103.87 | ||||||||
Long Put Options | 859,700 | 85.99 | 95.00 | 80.00 | ||||||||
Short Put Options | 1,225,700 | 68.67 | 75.00 | 60.00 | ||||||||
2017 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 744,950 | 107.99 | 113.83 | 104.15 | ||||||||
Long Put Options | 744,950 | 83.26 | 90.00 | 80.00 | ||||||||
Short Put Options | 744,950 | 63.26 | 70.00 | 60.00 | ||||||||
2018 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 307,400 | 104.39 | 104.65 | 104.15 | ||||||||
Long Put Options | 307,400 | 80.00 | 80.00 | 80.00 | ||||||||
Short Put Options | 307,400 | 60.00 | 60.00 | 60.00 | ||||||||
Natural Gas [Member] | ||||||||||||
Derivative [Line Items] | ||||||||||||
Open Derivative Contracts | ||||||||||||
Volume in | Weighted | Range | ||||||||||
Period and Type of Contract | MMBtu | Average | High | Low | ||||||||
2015 | ||||||||||||
Price Swap Contracts | 3,832,500 | 5.07 | 5.91 | 4.31 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 7,750,000 | 4.59 | 5.75 | 4.51 | ||||||||
Long Put Options | 8,113,500 | 4.01 | 5.00 | 3.50 | ||||||||
Long Call Options | 495,000 | 4.31 | 4.31 | 4.31 | ||||||||
Short Put Options | 9,116,000 | 3.34 | 4.45 | 3.25 | ||||||||
2016 | ||||||||||||
Price Swap Contracts | 8,418,000 | 4.22 | 4.23 | 4.22 | ||||||||
Collar Contracts | ||||||||||||
Short Call Options | 455,000 | 7.50 | 7.50 | 7.50 | ||||||||
Long Put Options | 455,000 | 5.50 | 5.50 | 5.50 | ||||||||
Short Put Options | 1,681,100 | 3.64 | 4.00 | 3.50 | ||||||||
2017 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 6,570,000 | 5.00 | 5.00 | 4.98 | ||||||||
Long Put Options | 6,570,000 | 4.50 | 4.50 | 4.50 | ||||||||
Short Put Options | 6,570,000 | 4.00 | 4.00 | 4.00 | ||||||||
2018 | ||||||||||||
Collar Contracts | ||||||||||||
Short Call Options | 5,475,000 | 5.50 | 5.53 | 5.48 | ||||||||
Long Put Options | 5,475,000 | 4.50 | 4.50 | 4.50 | ||||||||
Short Put Options | 5,475,000 | 4.00 | 4.00 | 4.00 | ||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Asset Retirement Obligations [Abstract] | |||||||||
Summary Of Changes In Asset Retirement Obligations | |||||||||
Year Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
(dollars in thousands) | |||||||||
Balance, beginning of year | $ | 56,023 | $ | 48,593 | $ | 46,096 | |||
Liabilities incurred | 1,129 | 1,052 | 787 | ||||||
Liabilities assumed with acquired producing properties | 3,002 | 5,480 | 1,476 | ||||||
Liabilities settled | -3,942 | -1,548 | -3,562 | ||||||
Liabilities transferred in sales of properties | -1,886 | -606 | — | ||||||
Revisions to estimates | 6,348 | 919 | 1,983 | ||||||
Accretion expense | 2,198 | 2,133 | 1,813 | ||||||
Balance, end of year | 62,872 | 56,023 | 48,593 | ||||||
Less: Current portion | 1,136 | 3,844 | 64 | ||||||
Long term portion | $ | 61,736 | $ | 52,179 | $ | 48,529 | |||
Long_Term_Debt_Tables
Long Term Debt (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Long Term Debt [Abstract] | ||||||
Long-Term Debt | ||||||
December 31, | December 31, | |||||
2014 | 2013 | |||||
(dollars in thousands) | ||||||
Credit Facility | $ | 319,520 | $ | 319,290 | ||
Senior Notes | 448,088 | 447,578 | ||||
Total long-term debt | $ | 767,608 | $ | 766,868 | ||
Notes payable to founder | $ | 24,540 | $ | 23,331 | ||
Summary Of Future Maturities Of Long-Term Debt | ||||||
Year ending December 31, | ||||||
2015 | $ | — | ||||
2016 | 319,520 | |||||
2017 | — | |||||
2018 | 450,000 | |||||
2019 | — | |||||
Thereafter | 24,540 | |||||
$ | 794,060 | |||||
Accounts_Payable_And_Accrued_L1
Accounts Payable And Accrued Liabilities (Tables) | 12 Months Ended | |||||
Dec. 31, 2014 | ||||||
Accounts Payable And Accrued Liabilities [Abstract] | ||||||
Detail Of Accounts Payable And Accrued Liabilities | ||||||
December 31, | December 31, | |||||
2014 | 2013 | |||||
(dollars in thousands) | ||||||
Capital expenditures | $ | 32,990 | $ | 18,629 | ||
Revenues and royalties payable | 7,302 | 9,699 | ||||
Operating expenses/taxes | 20,716 | 17,071 | ||||
Interest | 9,136 | 9,146 | ||||
Compensation | 10,586 | 8,862 | ||||
Other | 2,605 | 2,711 | ||||
Total accrued liabilities | 83,335 | 66,118 | ||||
Accounts payable | 34,225 | 29,977 | ||||
Accounts payable and accrued liabilities | $ | 117,560 | $ | 96,095 | ||
Commitments_And_Contingencies_
Commitments And Contingencies (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Commitments And Contingencies [Abstract] | ||||
Future Base Rentals For Non-Cancelable Leases | ||||
Year Ending December 31, | ||||
2015 | $ | 2,004 | ||
2016 | 1,562 | |||
2017 | 1,552 | |||
2018 | 1,529 | |||
2019 | 1,580 | |||
Thereafter | 4,420 | |||
$ | 12,647 | |||
Supplemental_Quarterly_Informa1
Supplemental Quarterly Information (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Supplemental Quarterly Information [Abstract] | ||||||||||||
Summary Of Quarterly Results Of Operations | ||||||||||||
Quarter Ended | ||||||||||||
2014 | 31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||
(dollars in thousands) | ||||||||||||
Revenues (1) | $ | 165,891 | $ | 86,254 | $ | 184,111 | $ | 179,951 | ||||
Income (loss) from operations (2) | 71,461 | -25,186 | 73,025 | 35,873 | ||||||||
Net income (loss) | $ | 56,893 | $ | -38,812 | $ | 59,326 | $ | 21,793 | ||||
-1 | Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively. | |||||||||||
-2 | Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively. | |||||||||||
Results of operations by quarter for the year ended December 31, 2013 were: | ||||||||||||
Quarter Ended | ||||||||||||
2013 | 31-Mar | 30-Jun | 30-Sep | 31-Dec | ||||||||
(dollars in thousands) | ||||||||||||
Revenues | $ | 68,578 | $ | 123,531 | $ | 77,759 | $ | 85,924 | ||||
Income (loss) from operations (3) | -1,066 | 29,799 | -11,915 | -115,469 | ||||||||
Net income (loss) | $ | -14,286 | $ | 16,168 | $ | -25,737 | $ | -129,860 | ||||
-3 | Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively. | |||||||||||
Supplemental_Oil_And_Natural_G1
Supplemental Oil And Natural Gas Disclosures (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract] | |||||||||||
Estimated Quantities Of Proved Reserves | |||||||||||
Oil | Gas | NGL's | BOE | ||||||||
(MBbls) | (MMcf) | (MBbls) | (MBbls) | ||||||||
Total Proved Reserves: | |||||||||||
Balance at December 31, 2011 | 16,933 | 217,266 | 4,845 | 57,989 | |||||||
Production | -2,138 | -21,372 | -365 | -6,065 | |||||||
Purchases in place | 335 | 6,619 | 8 | 1,446 | |||||||
Discoveries and extensions | 10,173 | 18,870 | 1,187 | 14,505 | |||||||
Revisions of previous quantity estimates and other | -4,683 | -68,894 | 20 | -16,144 | |||||||
Balance at December 31, 2012 | 20,620 | 152,489 | 5,695 | 51,731 | |||||||
Production | -2,897 | -16,664 | -398 | -6,072 | |||||||
Purchases in place | 1,462 | 1,265 | — | 1,673 | |||||||
Discoveries and extensions | 14,541 | 29,012 | 1,969 | 21,345 | |||||||
Sales of reserves in place | -13 | -10,912 | — | -1,832 | |||||||
Revisions of previous quantity estimates and other | -1,196 | -22,925 | -1,531 | -6,549 | |||||||
Balance at December 31, 2013 | 32,517 | 132,265 | 5,735 | 60,296 | |||||||
Production | -3,770 | -14,449 | -537 | -6,715 | |||||||
Purchases in place | 610 | 327 | — | 665 | |||||||
Discoveries and extensions | 13,281 | 28,822 | 4,119 | 22,204 | |||||||
Sales of reserves in place | -6,298 | -35,857 | -949 | -13,223 | |||||||
Revisions of previous quantity estimates and other | -4,996 | -7,960 | 20 | -6,304 | |||||||
Balance at December 31, 2014 | 31,344 | 103,148 | 8,388 | 56,923 | |||||||
Proved Developed Reserves: | |||||||||||
Balance at December 31, 2012 | 10,467 | 111,206 | 4,209 | 33,211 | |||||||
Balance at December 31, 2013 | 16,335 | 92,640 | 3,138 | 34,913 | |||||||
Balance at December 31, 2014 | 15,182 | 63,334 | 4,028 | 29,765 | |||||||
Proved Undeveloped Reserves: | |||||||||||
Balance at December 31, 2012 | 10,153 | 41,283 | 1,486 | 18,520 | |||||||
Balance at December 31, 2013 | 16,182 | 39,625 | 2,597 | 25,383 | |||||||
Balance at December 31, 2014 | 16,162 | 39,814 | 4,360 | 27,158 | |||||||
Capitalized Costs Relating To Oil And Natural Gas Producing Activities | |||||||||||
December 31, | |||||||||||
2014 | 2013 | ||||||||||
(dollars in thousands) | |||||||||||
Capitalized costs: | |||||||||||
Proved properties | $ | 1,417,785 | $ | 1,405,658 | |||||||
Unproved properties | 84,620 | 86,721 | |||||||||
Total | 1,502,405 | 1,492,379 | |||||||||
Accumulated depreciation, depletion, amortization and impairment | -816,229 | -800,609 | |||||||||
Net capitalized costs | $ | 686,176 | $ | 691,770 | |||||||
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Costs incurred during the year: | |||||||||||
Property acquisition costs | |||||||||||
Unproved | $ | 33,787 | $ | 34,884 | $ | 31,695 | |||||
Proved (1) | 7,462 | 35,954 | 12,192 | ||||||||
Exploration | 59,201 | 55,300 | 46,559 | ||||||||
Development (2) | 341,594 | 242,912 | 200,974 | ||||||||
$ | 442,044 | $ | 369,050 | $ | 291,420 | ||||||
-1 | Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million). | ||||||||||
(2) Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||||
Components Of The Standardized Measure Of Discounted Future Net Cash Flows | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Future cash flows | $ | 3,737,412 | $ | 3,959,938 | $ | 2,742,588 | |||||
Future production costs | -991,149 | -1,146,123 | -928,398 | ||||||||
Future development costs | -450,659 | -474,191 | -348,042 | ||||||||
Future taxes on income | — | — | — | ||||||||
Future net cash flows | 2,295,604 | 2,339,624 | 1,466,148 | ||||||||
Discount to present value at 10 percent per annum | -877,558 | -933,350 | -551,727 | ||||||||
Standardized measure of discounted future net cash flows | $ | 1,418,046 | $ | 1,406,274 | $ | 914,421 | |||||
Base price for crude oil, per Bbl, in the above computation was: | $ | 94.99 | $ | 96.78 | $ | 94.71 | |||||
Base price for natural gas, per Mcf, in the above computation was: | $ | 4.35 | $ | 3.67 | $ | 2.76 | |||||
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | |||||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars in thousands) | |||||||||||
Balance at beginning of year | $ | 1,406,274 | $ | 914,421 | $ | 1,070,196 | |||||
Sales of oil and natural gas, net of production costs | -320,130 | -263,952 | -189,709 | ||||||||
Changes in sales and transfer prices, net of production costs | -153,770 | 69,609 | -291,285 | ||||||||
Revisions of previous quantity estimates | -477,377 | -150,634 | -250,424 | ||||||||
Purchases of reserves-in-place | 21,633 | 93,877 | 10,283 | ||||||||
Sales of reserves-in-place | -107,414 | -11,193 | — | ||||||||
Current year discoveries and extensions | 701,820 | 621,832 | 420,496 | ||||||||
Changes in estimated future development costs | 2,591 | 11,623 | 54,493 | ||||||||
Development costs incurred during the year | 161,357 | 75,973 | 49,834 | ||||||||
Accretion of discount | 140,627 | 91,442 | 107,020 | ||||||||
Net change in income taxes | — | — | — | ||||||||
Change in production rate (timing) and other | 42,435 | -46,724 | -66,483 | ||||||||
Net change | 11,772 | 491,853 | -155,775 | ||||||||
Balance at end of year | $ | 1,418,046 | $ | 1,406,274 | $ | 914,421 | |||||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Details) (USD $) | 12 Months Ended | 1 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 25, 2015 | |
Summary Of Significant Accounting Policies [Line Items] | ||||
FDIC insured maximum amount | $250,000 | |||
Proceeds from sale of property | 177,476,000 | 26,668,000 | ||
Amount expended or committed from the restricted account for purchase of qualifying properties | 900,000 | |||
Receivables from joint interest owners | 10,300,000 | 13,800,000 | ||
Trade receivables for the sale of oil and natural gas | 35,100,000 | 37,800,000 | ||
Allowance for doubtful accounts | 1,400,000 | 1,400,000 | ||
Amortization of loan costs | 2,885,000 | 2,839,000 | 2,424,000 | |
Accumulated amortization, deferred financing costs | 15,600,000 | 12,800,000 | ||
Impairment expense of proved properties | 72,900,000 | 135,200,000 | 90,300,000 | |
Impairment expense of unproved properties | 2,000,000 | 8,000,000 | 5,900,000 | |
Depreciation depletion and amortization related to oil and gas properties | 139,000,000 | 115,500,000 | 106,600,000 | |
Depreciation expense for other property and equipment | 2,800,000 | 3,100,000 | 2,700,000 | |
Ownership interest in a drilling company | 10.17% | |||
Liability for uncertain tax positions | 0 | 0 | ||
Income tax penalties and interest | 0 | 0 | 0 | |
Face value of senior notes issued | 450,000,000 | |||
Fair value of senior notes payable | 380,300,000 | |||
ARM Energy Management, LLC [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Accounts receivable | 16,600,000 | 7,500,000 | ||
Hilltop Field Deep Bossier Properties [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Proceeds from sale of property | 24,600,000 | |||
Drilling Rig [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Depreciable life of property and equipment | 15 years | |||
Subsequent Event [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Amount of restricted cash refunded from investment | $23,700,000 | |||
Minimum [Member] | Other Property And Equipment [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Depreciable life of property and equipment | 3 years | |||
Maximum [Member] | Other Property And Equipment [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Depreciable life of property and equipment | 7 years |
Significant_Acquisitions_And_D2
Significant Acquisitions And Divestitures (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | |||||
Sep. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 19, 2014 | Oct. 01, 2013 | Jul. 01, 2013 | |
MMcf | ||||||||
Business Acquisition [Line Items] | ||||||||
Loss on sale of drilling rig | ($18,300,000) | ($73,100,000) | ($87,520,000) | $2,715,000 | ||||
Drilling Rig [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Sale of drilling rig, cash purchase price | 7,000,000 | |||||||
Loss on sale of drilling rig | 1,200,000 | |||||||
Eagleville Divestiture [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Date of acquisition or sale of properties | 25-Mar-14 | |||||||
Percentage of original working interest net profits interest in wells is retained on, 2014 | 50.00% | |||||||
Percentage of original working interest net profits interest in wells is retained on, 2015 | 30.00% | |||||||
Percentage of original working interest net profits interest in wells is retained on, 2016 | 15.00% | |||||||
Percentage of original working interest net profits interest in wells is retained on, 2017 | 0.00% | |||||||
Percentage of undivided interest in mineral leases and interests included in sale | 30.00% | |||||||
Percentage of working interest in all wells in progress on December 31, 2013 or drilled after January 1, 2014 included in sale | 30.00% | |||||||
Initial cash purchase price for properties sold | 173,000,000 | |||||||
Cash purchase price, net of costs of transaction | 171,000,000 | |||||||
Gain on sale of oil and gas properties | 72,500,000 | |||||||
Operating income from sold oil and gas properties | 11,100,000 | 47,000,000 | 22,100,000 | |||||
Eagleville Divestiture [Member] | Barrels of Oil Equivalent [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Estimated proved reserves associated with sold property | 7,500,000 | |||||||
Hilltop Divestiture 2013 [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Date of acquisition or sale of properties | 2-Oct-13 | |||||||
Cash purchase price, net of costs of transaction | 19,000,000 | |||||||
Gain on sale of oil and gas properties | 0 | |||||||
Hilltop Divestiture 2013 [Member] | Natural Gas in MMcf [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Estimated proved reserves associated with sold property | 11,200 | |||||||
Hilltop Divestiture 2014 [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Date of acquisition or sale of properties | 19-Sep-14 | |||||||
Cash purchase price, net of costs of transaction | 38,900,000 | 41,600,000 | ||||||
Gain on sale of oil and gas properties | 15,000,000 | |||||||
Hilltop Divestiture 2014 [Member] | Natural Gas in MMcf [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Estimated proved reserves associated with sold property | 29,800 | |||||||
Hilltop Field [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Operating income from sold oil and gas properties | 7,700,000 | 6,900,000 | 53,200,000 | |||||
Stone [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Acquisition effective date | 1-Oct-13 | |||||||
Payment towards acquisition of all working interests | $41,841,000 | |||||||
Total estimated net proved reserves acquired | 1,800,000 | |||||||
Acquisition effective date | 1-Jul-13 |
Significant_Acquisitions_And_D3
Significant Acquisitions And Divestitures (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Details) (Stone [Member], USD $) | 0 Months Ended | |
In Thousands, unless otherwise specified | Oct. 01, 2013 | Oct. 01, 2013 |
Stone [Member] | ||
Business Acquisition [Line Items] | ||
Cash | $41,841 | |
Fair value of asset retirement obligations assumed | 5,311 | |
Total | 47,152 | |
Proved oil and natural gas properties | 30,279 | 30,279 |
Unproved oil and natural gas properties | 16,873 | 16,873 |
Total | $47,152 | $47,152 |
Significant_Acquisitions_And_D4
Significant Acquisitions And Divestitures (Summary Of Pro Forma Information) (Details) (Stone [Member], USD $) | 3 Months Ended | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 |
Scenario, Actual [Member] | |||
Business Acquisition [Line Items] | |||
Actual revenue since acquisition | $10,509 | ||
Actual income (loss) since acquisition | 8,575 | ||
Pro Forma [Member] | |||
Business Acquisition [Line Items] | |||
Pro Forma Revenue | 376,063 | 340,103 | |
Pro Forma Income (Loss) | ($146,866) | ($85,985) |
Property_And_Equipment_Propert
Property And Equipment (Property And Equipment) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property And Equipment [Abstract] | ||
Unproved properties | $84,620 | $86,721 |
Accumulated impairment | -3,749 | -7,356 |
Unproved properties, net | 80,871 | 79,365 |
Proved oil and natural gas properties | 1,417,785 | 1,405,658 |
Accumulated depreciation, depletion, amortization and impairment | -812,480 | -793,253 |
Proved oil and natural gas properties, net | 605,305 | 612,405 |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | 686,176 | 691,770 |
LAND | 2,820 | 1,418 |
Office furniture and equipment, vehicles | 17,302 | 13,802 |
Accumulated depreciation | -8,617 | -6,120 |
OTHER PROPERTY AND EQUIPMENT, net | 8,685 | 7,682 |
TOTAL PROPERTY AND EQUIPMENT, NET | $697,681 | $700,870 |
Property_And_Equipment_Capital
Property And Equipment (Capitalized Exploratory Well Costs) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
item | |||
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves | |||
Capitalized Exploratory Well Costs, Beginning Balance | $18,364,000 | $4,627,000 | |
Additions to capitalized well costs pending determination of proved reserves | 2,889,000 | 21,693,000 | 4,627,000 |
Capitalized exploratory well costs charged to expense | -16,706,000 | -7,956,000 | |
Capitalized Exploratory Well Costs, Ending Balance | 4,547,000 | 18,364,000 | 4,627,000 |
Number of wells included in ending balance in deferred capitalized exploratory well costs | 5 | ||
Number of prospects | 2 | ||
Capitalized exploratory well costs that have been capitalized for period greater than one year | $2,200,000 | $0 |
Fair_Value_Disclosures_Narrati
Fair Value Disclosures (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Fair Value Disclosures [Line Items] | ||||||||
Carrying value of oil and gas properties | $148,400,000 | $237,200,000 | $363,700,000 | |||||
Written down fair value of oil and gas properties | 73,500,000 | 94,000,000 | 267,500,000 | |||||
Impairment charges to oil and gas properties | 8,700,000 | 18,300,000 | 114,500,000 | 19,200,000 | 7,400,000 | 74,927,000 | 143,166,000 | 96,227,000 |
Asset retirement obligation measured at fair value | 4,100,000 | 6,500,000 | ||||||
Stone [Member] | ||||||||
Fair Value Disclosures [Line Items] | ||||||||
Fair value of oil and gas properties acquired | $47,200,000 | $47,200,000 |
Fair_Value_Disclosures_Measure
Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Financial Assets: | ||
Derivative contracts for oil and natural gas, gross | $140,652 | $27,850 |
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross | 53,578 | 27,842 |
Level 1 [Member] | ||
Financial Assets: | ||
Derivative contracts for oil and natural gas, gross | ||
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross | ||
Level 2 [Member] | ||
Financial Assets: | ||
Derivative contracts for oil and natural gas, gross | 140,652 | 27,850 |
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross | 53,578 | 27,842 |
Level 3 [Member] | ||
Financial Assets: | ||
Derivative contracts for oil and natural gas, gross | ||
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross |
Derivative_Financial_Instrumen3
Derivative Financial Instruments (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Derivative Financial Instruments [Abstract] | |
Derivative Asset, Setoff Rights, Description | Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted. |
Derivative_Financial_Instrumen4
Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | $146,666 | $27,850 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | -59,592 | -18,873 |
Derivative Assets, Current | 59,803 | 5,572 |
Derivative Assets, Noncurrent | 27,271 | 3,405 |
Derivative assets, net, total | 87,074 | 8,977 |
Derivative liabilities, Gross Fair Value of Liabilities | 59,592 | 27,842 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | -59,592 | -18,873 |
Derivative Liabilities, Current | 4,483 | |
Derivative Liabilities, Noncurrent | 4,486 | |
Derivative liabilities, net, total | 8,969 | |
Derivative Assets Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 91,341 | 13,218 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | -31,538 | -7,646 |
Derivative Assets, Current | 59,803 | 5,572 |
Derivative Asset Non-Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 55,325 | 14,632 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | -28,054 | -11,227 |
Derivative Assets, Noncurrent | 27,271 | 3,405 |
Derivative Liabilities Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 31,538 | 12,129 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | -31,538 | -7,646 |
Derivative Liabilities, Current | 4,483 | |
Derivative Liabilities Non Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 28,054 | 15,713 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | -28,054 | -11,227 |
Derivative Liabilities, Noncurrent | $4,486 |
Derivative_Financial_Instrumen5
Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | $96,559 | ($17,150) | $19,751 |
Total gains (losses) from oil and natural gas commodity contracts | 96,559 | -17,150 | 19,714 |
Oil Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 82,510 | -17,715 | 3,720 |
Natural Gas Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 14,049 | 565 | 16,031 |
Not Designated As Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 96,559 | -17,150 | 19,714 |
Not Designated As Hedging Instrument [Member] | Interest Rate Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | ($37) |
Derivative_Financial_Instrumen6
Derivative Financial Instruments (Oil Derivative Contracts) (Details) (Oil Derivative Contracts [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
bbl | |
Price Swap Contracts [Member] | 2015 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 1,587,000 |
Weighted Average Swap Price | 91.39 |
Price Swap Contracts [Member] | 2015 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 95.02 |
Price Swap Contracts [Member] | 2015 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 86.45 |
Price Swap Contracts [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 366,000 |
Weighted Average Swap Price | 93 |
Price Swap Contracts [Member] | 2016 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 94.92 |
Price Swap Contracts [Member] | 2016 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 85.35 |
Short Call Options [Member] | 2015 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 392,350 |
Weighted Average Option Price | 114.1 |
Short Call Options [Member] | 2015 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 135.98 |
Short Call Options [Member] | 2015 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 95.5 |
Short Call Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 859,700 |
Weighted Average Option Price | 107.97 |
Short Call Options [Member] | 2016 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 130 |
Short Call Options [Member] | 2016 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 103.87 |
Short Call Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 744,950 |
Weighted Average Option Price | 107.99 |
Short Call Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 113.83 |
Short Call Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 104.15 |
Short Call Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 307,400 |
Weighted Average Option Price | 104.39 |
Short Call Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 104.65 |
Short Call Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 104.15 |
Long Put Options [Member] | 2015 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 1,049,350 |
Weighted Average Option Price | 85.78 |
Long Put Options [Member] | 2015 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 90 |
Long Put Options [Member] | 2015 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 85 |
Long Put Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 859,700 |
Weighted Average Option Price | 85.99 |
Long Put Options [Member] | 2016 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 95 |
Long Put Options [Member] | 2016 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 80 |
Long Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 744,950 |
Weighted Average Option Price | 83.26 |
Long Put Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 90 |
Long Put Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 80 |
Long Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 307,400 |
Weighted Average Option Price | 80 |
Long Put Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 80 |
Long Put Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 80 |
Short Put Options [Member] | 2015 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 1,998,350 |
Weighted Average Option Price | 70.05 |
Short Put Options [Member] | 2015 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 75 |
Short Put Options [Member] | 2015 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 60 |
Short Put Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 1,225,700 |
Weighted Average Option Price | 68.67 |
Short Put Options [Member] | 2016 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 75 |
Short Put Options [Member] | 2016 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 60 |
Short Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 744,950 |
Weighted Average Option Price | 63.26 |
Short Put Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 70 |
Short Put Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 60 |
Short Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | 307,400 |
Weighted Average Option Price | 60 |
Short Put Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 60 |
Short Put Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 60 |
Derivative_Financial_Instrumen7
Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) (Natural Gas Derivative Contracts [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
MMBTU | |
2015 [Member] | Price Swap Contracts [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 3,832,500 |
Weighted Average Swap Price | 5.07 |
2015 [Member] | Price Swap Contracts [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 5.91 |
2015 [Member] | Price Swap Contracts [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 4.31 |
2015 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 7,750,000 |
Weighted Average Option Price | 4.59 |
2015 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 5.75 |
2015 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.51 |
2015 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 8,113,500 |
Weighted Average Option Price | 4.01 |
2015 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 5 |
2015 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3.5 |
2015 [Member] | Long Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 495,000 |
Weighted Average Option Price | 4.31 |
2015 [Member] | Long Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.31 |
2015 [Member] | Long Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.31 |
2015 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 9,116,000 |
Weighted Average Option Price | 3.34 |
2015 [Member] | Short Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.45 |
2015 [Member] | Short Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3.25 |
2016 [Member] | Price Swap Contracts [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 8,418,000 |
Weighted Average Swap Price | 4.22 |
2016 [Member] | Price Swap Contracts [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 4.23 |
2016 [Member] | Price Swap Contracts [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 4.22 |
2016 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 455,000 |
Weighted Average Option Price | 7.5 |
2016 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 7.5 |
2016 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 7.5 |
2016 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 455,000 |
Weighted Average Option Price | 5.5 |
2016 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 5.5 |
2016 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 5.5 |
2016 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 1,681,100 |
Weighted Average Option Price | 3.64 |
2016 [Member] | Short Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4 |
2016 [Member] | Short Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3.5 |
2017 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 6,570,000 |
Weighted Average Option Price | 5 |
2017 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 5 |
2017 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.98 |
2017 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 6,570,000 |
Weighted Average Option Price | 4.5 |
2017 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.5 |
2017 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.5 |
2017 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 6,570,000 |
Weighted Average Option Price | 4 |
2017 [Member] | Short Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4 |
2017 [Member] | Short Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4 |
2018 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 5,475,000 |
Weighted Average Option Price | 5.5 |
2018 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 5.53 |
2018 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 5.48 |
2018 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 5,475,000 |
Weighted Average Option Price | 4.5 |
2018 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.5 |
2018 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.5 |
2018 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 5,475,000 |
Weighted Average Option Price | 4 |
2018 [Member] | Short Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4 |
2018 [Member] | Short Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4 |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Asset Retirement Obligations [Abstract] | |||
Balance, beginning of year | $56,023,000 | $48,593,000 | $46,096,000 |
Liabilities incurred | 1,129,000 | 1,052,000 | 787,000 |
Liabilities assumed with acquired producing properties | 3,002,000 | 5,480,000 | 1,476,000 |
Liabilities settled | -3,942,000 | -1,548,000 | -3,562,000 |
Liabilities transferred in sales of properties | -1,886,000 | -606,000 | |
Revisions to estimates | 6,348,000 | 919,000 | 1,983,000 |
Accretion expense | 2,198,000 | 2,133,000 | 1,813,000 |
Balance, end of period | 62,872,000 | 56,023,000 | 48,593,000 |
Less: Current portion | 1,136,000 | 3,844,000 | 64,000 |
Long-term portion | 61,736,000 | 52,179,000 | 48,529,000 |
Additions To PPE Included In ARO Revisions | $2,900,000 | $400,000 | $900,000 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 02, 2015 | |
Related Party Transaction [Line Items] | ||||
Notes payable to founder | $24,500,000 | $23,300,000 | ||
Total expenditures for land consulting services | 150,000 | 175,000 | 116,000 | |
Contract termination period without penalty for either party | 30 days | |||
Interest rate on note receivable | 8.00% | |||
Other Receivable [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount recorded for sale of partially constructed pipeline and gas processing plant | 25,500,000 | |||
Long Term Note Receivable [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount recorded for sale of partially constructed pipeline and gas processing plant | 8,500,000 | |||
Subsequent Event [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of receivable paid | 25,500,000 | |||
Vice President, Louisiana Region [Member] | ||||
Related Party Transaction [Line Items] | ||||
Total compensation | 450,000 | 390,000 | 327,000 | |
Landman [Member] | ||||
Related Party Transaction [Line Items] | ||||
Total compensation | 260,000 | 125,000 | 105,000 | |
Founder [Member] | ||||
Related Party Transaction [Line Items] | ||||
Capital distributions | $516,500 | $17,500 | ||
Notes Payable To Founder [Member] | ||||
Related Party Transaction [Line Items] | ||||
Effective rate of interest on senior notes | 10.00% | 10.00% | ||
ARM Energy Management, LLC [Member] | ||||
Related Party Transaction [Line Items] | ||||
Marketing fee | 1.00% | |||
ARM Energy Management, LLC [Member] | Maximum [Member] | ||||
Related Party Transaction [Line Items] | ||||
Percentage of ownership interest | 10.00% |
Long_Term_Debt_Narrative_Detai
Long Term Debt (Narrative) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Debt Instrument [Line Items] | |||
Letter of credit outstanding | $900,000 | $65,000 | |
Face value of senior notes issued | 450,000,000 | ||
Notes payable to founder | 24,540,000 | 23,331,000 | |
Interest on notes payable to founder | 1,209,000 | 1,208,000 | 1,212,000 |
Debt covenants description | The credit facility and senior notes include covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. | ||
Debt covenant compliance description | At DecemberB 31, 2014, we were in compliance with the covenants. | ||
Debt restrictive covenants description | The terms of the credit facility also restrict our ability to make distributions and investments. | ||
Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Date of sixth amended and restated credit agreement | 13-May-10 | ||
Line of Credit Facility, Collateral | The credit facility matures on MayB 23, 2016 and is secured by substantially all of our oil and natural gas properties. | ||
Date of maturity of credit facility | 23-May-16 | ||
Credit facility borrowing base | 375,000,000 | ||
Credit facility interest rate | 2.89% | 2.75% | |
Minimum Working Capital Ratio | 1 | ||
Minimum Coverage of Interest Expense Ratio | 3 | ||
Maximum Leverage Ratio | 4 | ||
Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility applicable interest rate, description | LIBOR plus applicable margins between 2.00% and 2.75% | ||
Credit Facility [Member] | Prime Rate [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility applicable interest rate, description | prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75% | ||
Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Debt Instrument [Line Items] | |||
Margin interest rate | 2.00% | ||
Credit Facility [Member] | Minimum [Member] | Prime Rate [Member] | |||
Debt Instrument [Line Items] | |||
Margin interest rate | 1.00% | ||
Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Debt Instrument [Line Items] | |||
Margin interest rate | 2.75% | ||
Credit Facility [Member] | Maximum [Member] | Prime Rate [Member] | |||
Debt Instrument [Line Items] | |||
Margin interest rate | 1.75% | ||
Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Face value of senior notes issued | 450,000,000 | ||
Maturity Date of Debt | 15-Oct-18 | ||
Stated interest rate of senior notes | 9.63% | ||
Effective rate of interest on senior notes | 9.78% | ||
Senior notes interest payable date | Interest is payable semi-annually each AprilB 15th and OctoberB 15th. | ||
Debt instrument collateral | The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. | ||
Remaining unamortized discount | 1,900,000 | 2,400,000 | |
Senior Notes [Member] | Twelve Mos Beginning October 15, 2015 [Member] | |||
Debt Instrument [Line Items] | |||
Optional redemption price of Senior Notes | 102.41% | ||
Senior Notes [Member] | Twelve Mos Beginning October 15, 2016 [Member] | |||
Debt Instrument [Line Items] | |||
Optional redemption price of Senior Notes | 100.00% | ||
Notes Payable To Founder [Member] | |||
Debt Instrument [Line Items] | |||
Maturity Date of Debt | 31-Dec-21 | 31-Dec-18 | |
Effective rate of interest on senior notes | 10.00% | 10.00% | |
Debt instrument collateral | These founder notes are unsecured and are subordinate to all debt. | ||
Interest on notes payable to founder | $1,200,000 | $1,200,000 | $1,200,000 |
Long_Term_Debt_LongTerm_Debt_D
Long Term Debt (Long-Term Debt) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Long Term Debt [Abstract] | ||
Credit Facility | $319,520 | $319,290 |
Senior Notes, net of discount | 448,088 | 447,578 |
Total long-term debt | 767,608 | 766,868 |
Notes payable to founder | $24,540 | $23,331 |
Long_Term_Debt_Summary_Of_Futu
Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Summary of future maturities of long-term debt | |
2015 | |
2016 | 319,520 |
2017 | |
2018 | 450,000 |
2019 | |
Thereafter | 24,540 |
Total long-term debt | $794,060 |
Accounts_Payable_And_Accrued_L2
Accounts Payable And Accrued Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounts Payable And Accrued Liabilities [Abstract] | ||
Capital expenditures | $32,990 | $18,629 |
Revenues and royalties payable | 7,302 | 9,699 |
Operating expenses/taxes | 20,716 | 17,071 |
Interest | 9,136 | 9,146 |
Compensation | 10,586 | 8,862 |
Other | 2,605 | 2,711 |
Total accrued liabilities | 83,335 | 66,118 |
Accounts payable | 34,225 | 29,977 |
Accounts payable and accrued liabilities | $117,560 | $96,095 |
Recovered_Sheet1
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | 3 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 23, 2015 | Jul. 24, 2013 |
item | |||||
Commitment And Contingencies [Line Items] | |||||
Liability for soil contamination | $1.10 | $1.10 | |||
Vesting period, PARs | 5 years | ||||
Number of performance appreciation rights granted | 271,500 | ||||
Weighted average stipulated price of PARs granted | $33.19 | ||||
Payment under contingent commitment towards properties acquired | 2.2 | ||||
Rent expense | 5.7 | 5.3 | 4.5 | ||
Performance Bonds Outstanding | $24.20 | ||||
Subsequent Event [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Number of performance appreciation rights granted | 244,000 | ||||
Weighted average stipulated price of PARs granted | $32.42 | ||||
Number of performance appreciation rights terminated | 27,500 | ||||
Weighted average price of PARs terminated | $40 | ||||
Building [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Description of Lessee Leasing Arrangements, Operating Leases | The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. | ||||
Upstream Equipment [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Description of Lessee Leasing Arrangements, Operating Leases | Equipment leases are generally for four years or less | ||||
Upstream Equipment [Member] | Maximum [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Term of leases | 4 years | ||||
Meridian Resource Company, L L C [Member] | Board Of Commissioners Of Southeast Louisiana Flood Protection Authority - East [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Number of wells | 32 | ||||
Number of dredging permits | 2 | ||||
Number of right of way agreements | 4 |
Commitments_And_Contingencies_1
Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Future base rentals for non-cancelable leases | |
2015 | $2,004 |
2016 | 1,562 |
2017 | 1,552 |
2018 | 1,529 |
2019 | 1,580 |
Thereafter | 4,420 |
Total future base rental | $12,647 |
Major_Customers_Details
Major Customers (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 | ||||
customer | customer | customer | |||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Revenues | $179,951 | [1] | $184,111 | [1] | $86,254 | [1] | $165,891 | [1] | $85,924 | $77,759 | $123,531 | $68,578 | $616,207 | $355,792 | $319,299 |
Number of customers that accounted for 10% or more of revenues | 1 | 3 | 3 | ||||||||||||
Minimum percentage of contribution of customers to revenue | 10.00% | 10.00% | 10.00% | ||||||||||||
Benchmark for determining customer significance | revenues excluding hedging activities | ||||||||||||||
ARM Energy Management, LLC [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Marketing fee | 1.00% | ||||||||||||||
Term of agreement left until extensions may come into effect | 5 years | ||||||||||||||
Revenues | 220,900 | 61,300 | |||||||||||||
Concentration Risk, Percentage | 51.10% | 16.00% | |||||||||||||
ARM Energy Management, LLC [Member] | Maximum [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Percentage of ownership interest | 10.00% | 10.00% | |||||||||||||
Murphy [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Revenues | 61,200 | 119,300 | 50,100 | ||||||||||||
Shell Trading (US) Company [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Revenues | 53,900 | 63,300 | |||||||||||||
Plains Marketing And Transportation, Inc. [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Revenues | 42,000 | ||||||||||||||
EnCana [Member] | |||||||||||||||
Revenue, Major Customer [Line Items] | |||||||||||||||
Revenues | $44,800 | ||||||||||||||
[1] | Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively. |
401k_Savings_Plan_Details
401(k) Savings Plan (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Savings Plan [Abstract] | |||
Percentage of matching contribution by company | 50.00% | ||
Maximum percentage of employee's salary deferral contribution | 8.00% | ||
Matching contributions to the plan | $683,000 | $585,000 | $422,000 |
Significant_Risks_And_Uncertai1
Significant Risks And Uncertainties (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Significant Risks And Uncertainties [Abstract] | |
Risks and uncertainties inherent | Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of the year. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. |
Partners_Capital_Deficit_Detai
Partners' Capital (Deficit) (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
item | |
Partners' Capital (Deficit) [Abstract] | |
Number of classes of limited partners | 2 |
Amount of recapitalization | $350 |
Number of members added to Board of Directors, nominated by Highbridge | 1 |
Number of members added to Board of Directors, nominated by Class A partners | 4 |
Supplemental_Quarterly_Informa2
Supplemental Quarterly Information (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 | ||||||||
Supplemental Quarterly Information [Abstract] | |||||||||||||||||||
Revenues | $179,951 | [1] | $184,111 | [1] | $86,254 | [1] | $165,891 | [1] | $85,924 | $77,759 | $123,531 | $68,578 | $616,207 | $355,792 | $319,299 | ||||
Income (loss) from operations | 35,873 | [2] | 73,025 | [2] | -25,186 | [2] | 71,461 | [2] | -115,469 | [3] | -11,915 | [3] | 29,799 | [3] | -1,066 | [3] | 155,173 | -98,651 | -55,399 |
Net income (loss) | 21,793 | 59,326 | -38,812 | 56,893 | -129,860 | -25,737 | 16,168 | -14,286 | 99,200 | -153,715 | -95,875 | ||||||||
Gain on sale of asset | 18,300 | 73,100 | 87,520 | -2,715 | |||||||||||||||
Impairment expense | $8,700 | $18,300 | $114,500 | $19,200 | $7,400 | $74,927 | $143,166 | $96,227 | |||||||||||
[1] | Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively. | ||||||||||||||||||
[2] | Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively. | ||||||||||||||||||
[3] | Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively. |
Supplemental_Oil_And_Natural_G2
Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MBbls | MBbls | MBbls | |
Oil [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 32,517 | 20,620 | 16,933 |
Production | -3,770 | -2,897 | -2,138 |
Purchases in place | 610 | 1,462 | 335 |
Discoveries and extensions | 13,281 | 14,541 | 10,173 |
Sales of reserves in place | -6,298 | -13 | |
Revisions of previous quantity estimates and other | -4,996 | -1,196 | -4,683 |
Proved Reserves, Ending balance | 31,344 | 32,517 | 20,620 |
Developed Reserves | 15,182 | 16,335 | 10,467 |
Proved Undeveloped Reserves | 16,162 | 16,182 | 10,153 |
Natural Gas in MMcf [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 132,265 | 152,489 | 217,266 |
Production | -14,449 | -16,664 | -21,372 |
Purchases in place | 327 | 1,265 | 6,619 |
Discoveries and extensions | 28,822 | 29,012 | 18,870 |
Sales of reserves in place | -35,857 | -10,912 | |
Revisions of previous quantity estimates and other | -7,960 | -22,925 | -68,894 |
Proved Reserves, Ending balance | 103,148 | 132,265 | 152,489 |
Developed Reserves | 63,334 | 92,640 | 111,206 |
Proved Undeveloped Reserves | 39,814 | 39,625 | 41,283 |
Natural Gas Liquids [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 5,735 | 5,695 | 4,845 |
Production | -537 | -398 | -365 |
Purchases in place | 8 | ||
Discoveries and extensions | 4,119 | 1,969 | 1,187 |
Sales of reserves in place | -949 | ||
Revisions of previous quantity estimates and other | 20 | -1,531 | 20 |
Proved Reserves, Ending balance | 8,388 | 5,735 | 5,695 |
Developed Reserves | 4,028 | 3,138 | 4,209 |
Proved Undeveloped Reserves | 4,360 | 2,597 | 1,486 |
Barrels of Oil Equivalent [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 60,296 | 51,731 | 57,989 |
Production | -6,715 | -6,072 | -6,065 |
Purchases in place | 665 | 1,673 | 1,446 |
Discoveries and extensions | 22,204 | 21,345 | 14,505 |
Sales of reserves in place | -13,223 | -1,832 | |
Revisions of previous quantity estimates and other | -6,304 | -6,549 | -16,144 |
Proved Reserves, Ending balance | 56,923 | 60,296 | 51,731 |
Developed Reserves | 29,765 | 34,913 | 33,211 |
Proved Undeveloped Reserves | 27,158 | 25,383 | 18,520 |
Supplemental_Oil_And_Natural_G3
Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Capitalized costs: | ||
Proved properties | $1,417,785 | $1,405,658 |
Unproved properties | 84,620 | 86,721 |
Total | 1,502,405 | 1,492,379 |
Accumulated depreciation, depletion, amortization and impairment | -816,229 | -800,609 |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | $686,176 | $691,770 |
Supplemental_Oil_And_Natural_G4
Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | ||||||
Property acquisition costs, unproved properties | $33,787,000 | $34,884,000 | $31,695,000 | |||
Property acquisition costs, proved properties | 7,462,000 | [1] | 35,954,000 | [1] | 12,192,000 | [1] |
Costs incurred, exploration | 59,201,000 | 55,300,000 | 46,559,000 | |||
Costs incurred, development | 341,594,000 | [2] | 242,912,000 | [2] | 200,974,000 | [2] |
Costs Incurred, Total | 442,044,000 | 369,050,000 | 291,420,000 | |||
Costs Incurred, Additional Information [Abstract] | ||||||
Development Costs Incurred As Asset Retirement Obligations | 4,500,000 | 1,400,000 | 1,700,000 | |||
Stone [Member] | ||||||
Costs Incurred, Additional Information [Abstract] | ||||||
Total cost of Business Acquisition | $30,600,000 | |||||
[1] | Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million). | |||||
[2] | Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended DecemberB 31, 2014, 2013, and 2012, respectively. |
Supplemental_Oil_And_Natural_G5
Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Components of the standardized measure of discounted future net cash flows | ||||
Future cash flows | $3,737,412 | $3,959,938 | $2,742,588 | |
Future production costs | -991,149 | -1,146,123 | -928,398 | |
Future development costs | -450,659 | -474,191 | -348,042 | |
Future taxes on income | ||||
Future net cash flows | 2,295,604 | 2,339,624 | 1,466,148 | |
Discount to present value at 10 percent per annum | -877,558 | -933,350 | -551,727 | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | $1,418,046 | $1,406,274 | $914,421 | $1,070,196 |
Base price for crude oil, per Bbl, in the above computations was | 94.99 | 96.78 | 94.71 | |
Base price for natural gas, per Mcf, in the above computations was | 4.35 | 3.67 | 2.76 |
Supplemental_Oil_And_Natural_G6
Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Components of changes in standardized measure of discounted future net cash flows | |||
Balance at beginning of year | $1,406,274 | $914,421 | $1,070,196 |
Sales of oil and natural gas, net of production costs | -320,130 | -263,952 | -189,709 |
Changes in sales and transfer prices, net of production costs | -153,770 | 69,609 | -291,285 |
Revisions of previous quantity estimates | -477,377 | -150,634 | -250,424 |
Purchases of reserves-in-place | 21,633 | 93,877 | 10,283 |
Sales of reserves-in-place | -107,414 | -11,193 | |
Current year discoveries and extensions | 701,820 | 621,832 | 420,496 |
Changes in estimated future development costs | 2,591 | 11,623 | 54,493 |
Development costs incurred during the year | 161,357 | 75,973 | 49,834 |
Accretion of discount | 140,627 | 91,442 | 107,020 |
Net change in income taxes | |||
Change in production rate (timing) and other | 42,435 | -46,724 | -66,483 |
Net change | 11,772 | 491,853 | -155,775 |
Balance at end of year | $1,418,046 | $1,406,274 | $914,421 |