Document And Entity Information
Document And Entity Information | 12 Months Ended |
Dec. 31, 2015USD ($)shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Alta Mesa Holdings, LP |
Entity Central Index Key | 1,518,403 |
Document Type | 10-K |
Document Period End Date | Dec. 31, 2015 |
Amendment Flag | false |
Document Fiscal Year Focus | 2,015 |
Document Fiscal Period Focus | FY |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | shares | 0 |
Entity Public Float | $ | $ 0 |
Entity Current Reporting Status | No |
Entity Voluntary Filers | Yes |
Entity Well-known Seasoned Issuer | No |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 8,869 | $ 1,349 |
Restricted cash | 105 | 23,793 |
Accounts receivable, net of allowance of $1,402 and $1,449, respectively | 27,111 | 43,581 |
Other receivables | 18,526 | 8,238 |
Receivable due from affiliate | 1,053 | 25,500 |
Prepaid expenses and other current assets | 4,774 | 2,132 |
Derivative financial instruments | 62,631 | 59,803 |
Total current assets | 123,069 | 164,396 |
PROPERTY AND EQUIPMENT | ||
Oil and natural gas properties, successful efforts method, net | 525,942 | 686,176 |
Other property and equipment, net | 11,097 | 11,505 |
Total property and equipment, net | 537,039 | 697,681 |
OTHER ASSETS | ||
Long-term restricted cash | 900 | |
Investment in LLC - cost | 9,000 | 9,000 |
Deferred financing costs, net | 1,199 | 1,634 |
Notes receivable due from affiliate | 9,213 | 8,500 |
Advances to operators | 37 | 619 |
Deposits and other assets | 1,333 | 1,124 |
Derivative financial instruments | 41,635 | 27,271 |
Total other assets | 62,417 | 49,048 |
TOTAL ASSETS | 722,525 | 911,125 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 84,002 | 117,560 |
Current portion, asset retirement obligations | 729 | 1,136 |
Total current liabilities | 84,731 | 118,696 |
LONG-TERM LIABILITIES | ||
Asset retirement obligations, net of current portion | 60,491 | 61,736 |
Long-term debt | 717,775 | 761,142 |
Notes payable to founder | 25,748 | 24,540 |
Other long-term liabilities | 10,829 | 6,457 |
Total long-term liabilities | 814,843 | 853,875 |
TOTAL LIABILITIES | $ 899,574 | $ 972,571 |
Commitments and Contingencies (Note 11) | ||
PARTNERS' DEFICIT | $ (177,049) | $ (61,446) |
TOTAL LIABILITIES AND PARTNERS' DEFICIT | $ 722,525 | $ 911,125 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Consolidated Balance Sheets [Abstract] | ||
Allowance for doubtful accounts | $ 1,402 | $ 1,449 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
OPERATING REVENUES AND OTHER | |||
Oil | $ 199,799 | $ 347,842 | $ 297,836 |
Natural gas | 30,621 | 65,002 | 61,350 |
Natural gas liquids | 10,864 | 18,281 | 15,264 |
Other revenues | 682 | 1,003 | 1,207 |
Total operating revenues | 241,966 | 432,128 | 375,657 |
Gain (loss) on sale of assets | 67,781 | 87,520 | (2,715) |
Gain (loss) on derivative contracts | 124,141 | 96,559 | (17,150) |
Total operating revenues and other | 433,888 | 616,207 | 355,792 |
OPERATING EXPENSES | |||
Lease and plant operating expense | 71,736 | 73,820 | 70,450 |
Production and ad valorem taxes | 15,131 | 28,214 | 26,369 |
Workover expense | 6,511 | 8,961 | 13,679 |
Exploration expense | 42,718 | 61,912 | 33,065 |
Depreciation, depletion, and amortization expense | 143,969 | 141,804 | 118,558 |
Impairment expense | 176,774 | 74,927 | 143,166 |
Accretion expense | 2,076 | 2,198 | 2,133 |
General and administrative expense | 44,454 | 69,198 | 47,023 |
Total operating expenses | 503,369 | 461,034 | 454,443 |
INCOME (LOSS) FROM OPERATIONS | (69,481) | 155,173 | (98,651) |
OTHER INCOME (EXPENSE) | |||
Interest expense | (62,473) | (55,812) | (55,188) |
Interest income | 723 | 15 | 124 |
Total other income (expense) | (61,750) | (55,797) | (55,064) |
INCOME (LOSS) BEFORE STATE INCOME TAXES | (131,231) | 99,376 | (153,715) |
(Provision) for state income taxes | (562) | (176) | |
NET INCOME (LOSS) | $ (131,793) | $ 99,200 | $ (153,715) |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Partners' Capital (Deficit) $ in Thousands | USD ($) |
Balance, Beginning at Dec. 31, 2012 | $ (6,368) |
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract] | |
Distributions | (24) |
Net income (loss) | (153,715) |
Balance, Ending at Dec. 31, 2013 | (160,107) |
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract] | |
Distributions | (539) |
Net income (loss) | 99,200 |
Balance, Ending at Dec. 31, 2014 | (61,446) |
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract] | |
Contributions | 20,000 |
Distributions | (3,810) |
Net income (loss) | (131,793) |
Balance, Ending at Dec. 31, 2015 | $ (177,049) |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ (131,793) | $ 99,200 | $ (153,715) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, and amortization expense | 143,969 | 141,804 | 118,558 |
Impairment expense | 176,774 | 74,927 | 143,166 |
Accretion expense | 2,076 | 2,198 | 2,133 |
Amortization of loan costs | 3,392 | 2,885 | 2,839 |
Amortization of debt discount | 510 | 510 | 510 |
Dry hole expense | 22,708 | 30,294 | 15,295 |
Expired leases | 6,526 | 4,319 | 3,289 |
(Gain) loss on derivative contracts | (124,141) | (96,559) | 17,150 |
Settlements of derivative contracts | 106,949 | 9,493 | 18,177 |
Interest converted into debt | 1,208 | 1,209 | 1,208 |
Interest on notes receivable due from affiliate | (713) | ||
(Gain) loss on sale of assets | (67,781) | (87,520) | 2,715 |
Changes in assets and liabilities: | |||
Restricted cash unrelated to property divestiture | (106) | 2,305 | |
Accounts receivable | 16,470 | (95) | (2,771) |
Other receivables | (10,288) | (5,686) | 1,863 |
Receivable due from affiliate | (1,725) | ||
Prepaid expenses and other non-current assets | (2,269) | 7,251 | 4,477 |
Settlement of asset retirement obligation | (1,794) | (3,942) | (1,548) |
Accounts payable, accrued liabilities, and other long-term liabilities | 3,900 | 4,702 | (3,132) |
NET CASH PROVIDED BY OPERATING ACTIVITIES | 143,978 | 184,884 | 172,519 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures for property and equipment | (223,604) | (366,090) | (311,438) |
Acquisitions | (48,202) | (18,110) | (51,377) |
Proceeds from sale of property | 141,404 | 177,476 | 26,668 |
Proceeds from property divesture classified as restricted cash | 41,590 | ||
Investment in restricted cash related to property divestitures | 24,587 | (24,587) | |
NET CASH USED IN INVESTING ACTIVITIES | (105,815) | (189,721) | (336,147) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from long-term debt | 252,500 | 169,500 | 214,500 |
Repayments of long-term debt | (295,020) | (169,270) | (50,000) |
Additions to deferred financing costs | (4,313) | (42) | (97) |
Capital distributions | (3,810) | (539) | (24) |
Capital contributions | 20,000 | ||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | (30,643) | (351) | 164,379 |
NET INCREASE IN CASH AND CASH EQUIVALENTS | 7,520 | (5,188) | 751 |
CASH AND CASH EQUIVALENTS, beginning of period | 1,349 | 6,537 | 5,786 |
CASH AND CASH EQUIVALENTS, end of period | 8,869 | 1,349 | 6,537 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | |||
Cash paid during the period for interest | 56,579 | 51,219 | 50,731 |
Cash paid (received) during the period for state taxes | 751 | (123) | 18 |
Change in asset retirement obligations | 487 | 2,643 | 854 |
Asset retirement obligations assumed, purchased properties | 3,002 | 5,480 | |
Change in accruals or liabilities for capital expenditures | (34,160) | 23,858 | $ (14,085) |
Non-cash divestiture of oil and gas properties | $ (34,000) | ||
Non-cash acquisition of property and land | $ 2,473 |
Nature Of Operations
Nature Of Operations | 12 Months Ended |
Dec. 31, 2015 | |
Description Of Business [Abstract] | |
Description Of Business | 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 and Louisiana. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
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”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ deficit. Principles of Consolidation . The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). 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. 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. R estricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2015, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute. As of December 31, 2014 , the Company had $24.6 million of proceeds remaining 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 from the sale of our Hilltop field Deep Bossier properties. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions, and in March 2015, the remaining $23.7 million of restricted cash was returned to us to be used for general corporate purposes and, as such, was classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. T he Company planned 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 . 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 $ 9.8 million and $ 10.3 million at December 31, 2015 and 2014, respectively. Trade receivables from the sale of oil and natural gas were $17.9 million and $35.1 million at December 31, 2015 and 2014, respectively. See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC (“AEM”). Accounts receivable from AEM were $12.6 million and $16.6 million as of December 31, 2015 and 2014, 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. Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations. In the fourth quarter of 2015, the Company adopted Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs. In accordance with the new guidance, deferred financing costs related to the Company’s senior unsecured notes and Term Loan Facility (as defined in Note 9), which had been included in deferred financing costs, net under other assets on the consolidated balance sheets prior to the adoption of ASU 2015-03, are now included in long-term debt on the consolidated balance sheets, resulting in decreases in both deferred financing costs, net and long-term debt of $7.8 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual period presented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the consolidated balance sheet as of December 31, 2014 included a deduction for deferred financing costs of $6.5 million in long-term debt, which had previously been presented in deferred financing costs, net under other assets. Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”). 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, or “suspended” on the balance sheet 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 $ 172.0 million, $ 72.9 million and $ 135.2 million for the years ended December 31, 2015, 2014, and 2013, respectively, primarily due to lower forecasted commodity prices. 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, 2015, 2014 and 2013, impairment expense of unproved properties was $ 4.8 million, $ 2.0 million, and $ 8.0 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, 201 5, 201 4, and 201 3, 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, 2015, 2014, and 2013 related to oil and natural gas properties was $ 140.9 million, $139.0 million, and $115.5 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, 2015, 2014, and 2013 was $ 3.0 million, $2.8 million, and $3.1 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, natural gas and natural gas liquids. 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) on derivative contracts.” Cash flows from settlements of derivative contracts are classified as 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 “ 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, 2015 and 2014 . 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, 2015 , 2014 , or 2013 . The Company’s tax returns for the years ended December 31, 2012 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 fair value estimate 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 estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. We have estimated the fair value of our $450 million senior notes payable at $162 million on December 31, 2015 . Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 5 – Fair value disclosures and Note 9 - 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 May 2014, the FASB issued ASU No. 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. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments , which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations. In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations . In February 2016, the FASB issued ASU 2016-02 , Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. |
Significant Acquisition And Div
Significant Acquisition And Divestitures | 12 Months Ended |
Dec. 31, 2015 | |
Significant Acquisition and Divestitures [Abstract] | |
Significant Acquisition and Divestitures | NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES 2015 Activity Alta Mesa Eagle, LLC Divestiture On September 30, 2015 , we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”). AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas. In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area. The effective date of the transaction (the “Effective Date”) is July 1, 2015 . The aggregate cash purchase price for the Membership Interests was $125 million subject to certain adjustments, consisting of $118 million (the “Base Purchase Price”), and additional contingent payments of approximately $7 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received. The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a preliminary gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE. The sale of AME contributed approximately $ 68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118. 5 million in pre-tax profit for the year ended December 31, 2014, which includes a $7 2.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below. Kingfisher Leasehold Acquisition On July 6, 2015 , we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments. The effective date of the acquisition was April 1, 2015. The purchase was funded with borrowings under our credit facility . 2014 Activity 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. 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 gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on an 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 in net pre-tax profit for the year ended December 31, 2013. Hilltop Divestiture 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 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. 2013 Activity 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. 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. The Hilltop interests contributed approximately $6.9 million in net pre-tax loss during the year ended December 31, 2013. 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 $4 2 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 allocation of the purchase prices are as follows: October 1, 2013 (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 the date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2013, 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) (in thousands) Actual results of Stone 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, 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, 2015 | |
Property And Equipment [Abstract] | |
Property And Equipment | NOTE 4 — PROPERTY AND EQUIPMENT Property and equipment consists of the following: December 31, December 31, 2015 2014 (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 127,551 $ 84,620 Accumulated impairment (2,684) (3,749) Unproved properties, net 124,867 80,871 Proved oil and natural gas properties 1,345,482 1,417,785 Accumulated depreciation, depletion, amortization and impairment (944,407) (812,480) Proved oil and natural gas properties, net 401,075 605,305 TOTAL OIL AND NATURAL GAS PROPERTIES, net 525,942 686,176 LAND 3,868 2,820 OTHER PROPERTY AND EQUIPMENT Office furniture and equipment, vehicles 18,794 17,302 Accumulated depreciation (11,565) (8,617) OTHER PROPERTY AND EQUIPMENT, net 7,229 8,685 TOTAL PROPERTY AND EQUIPMENT, net $ 537,039 $ 697,681 Capitalized Exploratory Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2015, 2014, and 2013. The table does not include amounts that were capitalized and either subsequently expensed within the same year. Year Ended December 31, 2015 2014 2013 (in thousands) Balance, beginning of year $ 13,301 $ 20,317 $ 3,863 Additions to capitalized well costs pending determination of proved reserves 4,364 15,870 21,387 Reclassifications to proved properties (8,583) (6,593) (4,933) Capitalized exploratory well costs charged to expense (3,076) (16,293) — Balance, end of year $ 6,006 $ 13,301 $ 20,317 The ending balance in capitalized exploratory well costs includes the costs of six wells primarily in two prospects that were capitalized for periods greater than one year at December 31, 2015. We have capitalized $3.0 million and $2.2 million of exploratory well costs covering periods greater than one year at December 31, 2015 and 2014. |
Fair Value Disclosures
Fair Value Disclosures | 12 Months Ended |
Dec. 31, 2015 | |
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, natural gas, and natural gas liquids derivative contracts as Level 2. Our senior notes are carried at historical cost, net of unamortized 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 $ 499.6 million were written down to their fair value of $ 322.8 million, resulting in an impairment charge of $ 176.8 million for the year ended December 31, 2015 . 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. 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 $ 2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015. 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. The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value: Level 1 Level 2 Level 3 Total (in thousands) At December 31, 2015: Financial Assets: Derivative contracts for oil and natural gas — $ 166,106 — $ 166,106 Financial Liabilities: Derivative contracts for oil and natural gas — $ 61,840 — $ 61,840 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 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 Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
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, natural gas, and natural gas liquids. 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, natural gas, and natural gas liquids 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 oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) 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 December 31, 2015 Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current assets $ 86,000 $ (23,369) $ 62,631 Derivative financial instruments, long-term assets 80,106 (38,471) 41,635 Total $ 166,106 $ (61,840) $ 104,266 Net Fair Gross Gross amounts Value of Liabilities December 31, 2015 Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current liabilities $ 23,369 $ (23,369) $ — Derivative financial instruments, long-term liabilities 38,471 (38,471) — Total $ 61,840 $ (61,840) $ — Net Fair Gross Gross amounts Value of Assets December 31, 2014 Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (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 December 31, 2014 Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (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) $ — The following table summarizes the effect of our 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) 2015 2014 2013 (in thousands) Oil commodity contracts Gain (loss) on derivative contracts $ 113,295 $ 82,510 $ (17,715) Natural gas commodity contracts Gain on derivative contracts 10,712 14,049 565 Natural gas liquids commodity contracts Gain on derivative contracts 134 — — Total gains (losses) from derivatives not designated as hedges $ 124,141 $ 96,559 $ (17,150) Other receivables includes $17.5 million and $8.0 million of derivative positions settled, but not yet received as of December 31, 2015 and 2014, respectively. 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, 2015 : OIL DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract in Bbls Average High Low 2016 Price Swap Contracts 2,532,300 $ 64.16 $ 94.92 $ 53.00 Collar Contracts Short Call Options 739,100 99.69 130.00 75.00 Long Put Options 603,800 63.71 95.00 40.55 Short Put Options 420,800 72.81 75.00 65.00 2017 Collar Contracts Short Call Options 1,960,150 85.02 113.83 62.50 Long Put Options 1,412,650 72.27 90.00 60.00 Short Put Options 1,412,650 54.63 70.00 45.00 2018 Collar Contracts Short Call Options 1,183,000 80.51 104.65 72.00 Long Put Options 1,183,000 67.05 80.00 62.50 Short Put Options 1,183,000 48.90 60.00 45.00 2019 Collar Contracts Short Call Options 821,250 75.17 75.70 74.50 Long Put Options 821,250 62.50 62.50 62.50 Short Put Options 821,250 45.00 45.00 45.00 We had the following open derivative contracts for natural gas at December 31, 2015 : NATURAL GAS DERIVATIVE CONTRACTS Volume in Weighted Range Period and Type of Contract MMBtu Average High Low 2016 Price Swap Contracts 7,320,000 $ 3.05 $ 3.17 $ 2.95 Collar Contracts Short Call Options 1,510,000 2.40 2.40 2.40 Long Put Options 1,510,000 2.25 2.25 2.25 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. We had the following open derivative contracts for natural gas liquids at December 31, 2015 : NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract in Gal Average High Low 2016 Price Swap Contracts 3,843,000 $ 0.44 $ 0.44 $ 0.44 We had the following open financial basis swap contracts for natural gas at December 31, 2015 : BASIS SWAP DERIVATIVE CONTRACTS Weighted Average Spread Volume in MMBtu Reference Price 1 (1) Reference Price 2 (1) Period ($ per MMBtu) 4,125,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Apr ’16 — Dec ’16 $ 0.27 1,350,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’17 — Mar ’17 0.25 (1) The spread in these trades limits the differential of the settlement quotation prices for Tex/OKL Panhandle Eastern Pipeline (PEPL) inside FERC (IFERC) over NYMEX Henry Hub. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (in thousands) Balance, beginning of year $ 62,872 $ 56,023 $ 48,593 Liabilities incurred 1,988 1,129 1,052 Liabilities assumed with acquired producing properties — 3,002 5,480 Liabilities settled (1,794) (3,942) (1,548) Liabilities transferred in sales of properties (3,149) (1,886) (606) Revisions to estimates (773) 6,348 919 Accretion expense 2,076 2,198 2,133 Balance, end of year 61,220 62,872 56,023 Less: Current portion 729 1,136 3,844 Long term portion $ 60,491 $ 61,736 $ 52,179 The total revisions included $1.5 million related to reductions to property, plant and equipment for the year ended December 31, 2015. Total revisions included $2.9 million and $0.4 million related to additions to property, plant and equipment for the years ended December 31, 2014, and 2013, respectively. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
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 $25.7 million and $24.5 million at December 31, 2015 and 2014, respectively. See further information at Note 9. Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received zero , $516,500 , and $17,500 of capital distributions from us during the years ended December 31, 2015, 2014 and 2013, 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, 2015 , 2014 and 2013 were approximately $133,000 , $150,000 and $175,000 . The contract may be terminated by either party without penalty upon 30 days’ notice. David McClure, our Vice President, Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $275,000 , $450,000 and $390,000 for the years ended December 31, 2015 , 2014 and 2013. 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 cousin of our Vice President, Land and Business Development, David Murrell, received total compensation of $146,000 , $260,000 and $125,000 for the years ended December 31, 2015 , 2014 and 2013. 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 partner, High Mesa, Inc. (“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 Northwest Gas Processing, LLC (“NWGP”) to High Mesa Services, LLC, a subsidiary of High Mesa. The Company believes the note to be fully collectible and accordingly has not recorded a reserve. Interest income on the notes receivable from our affiliate amounted to $0.7 million during year ended December 31, 2015. Such amounts have been added to the balance of the notes receivable. On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million. The receivables due from affiliate balance of $1.0 million as of December 31, 2015 includes the cost of repurchasing the land from NWGP. During the year ended December 31, 2015, High Mesa, our Class B partner contributed $20 million to us. For additional information, see Note 15- Partners’ Capital Deficit. 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, 2015 | |
Long Term Debt [Abstract] | |
Long Term Debt | NOTE 9 — LONG TERM DEBT Long-term debt consists of the following: December 31, December 31, 2015 2014 (in thousands) Credit Facility $ 152,000 $ 319,520 Senior Secured Term Loan 125,000 — Senior Notes 448,598 448,088 Unamortized deferred financing costs (7,823) (6,466) Total long-term debt $ 717,775 $ 761,142 Notes payable to founder $ 25,748 $ 24,540 Credit Facility. As of December 31, 2015, the Company had $152 million outstanding with $148 million of available borrowing capacity under the Sixth Amended and Restated Credit Agreement (as amended, the “ credit facility ”) with Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of banks. On June 2, 2015, we entered into an Agreement and Amendment No. 11 (the “Eleventh Amendment”) to the credit facility . The Eleventh Amendment, among other things, (i) redetermined and decreased the borrowing base from $375 million to $300 million, and (ii) extended the maturity date of the credit facility to October 13, 2017 from May 23, 2016 . The principal amount is payable at maturity. On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the “Twelfth Amendment”) to amend the credit facility to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility. As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million. Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility. The credit facility borrowing base is redetermined semi-annually on or about May 1 and November 1 of each year. In November 2015, the lenders under the credit facility approved an increase in the borrowing base from $255 million to $300 million as part of the semi-annual redetermination . The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. The credit facility bears interest at LIBOR plus applicable margins between 2.00% an d 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 2.87 % as of December 31, 2015 and 2.89% as of December 31, 2014 . The letters of credit outstanding as of December 31, 2015 and 2014 were $65,000 and $0.9 million, 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 expense 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, 2015 , 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. Subsequent to year end, on February 3, 2016, we entered into an Agreement and Amendment No. 13 to the credit facility (the “Thirteenth Amendment”). The Thirteenth Amendment, among other things: (a) permits us to enter into exchanges of outstanding senior notes for a third lien term loan, (b) permits us to draw the remaining borrowing base availability under the credit facility into a controlled account with such funds not being treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, (c) permits us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (d) requires that twice a month we transfer available cash in excess of $25 million to the controlled account, and (e) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.00 to 1.00 to 4.50 to 1.00. Senior Secured Term Loan. On June 2, 2015, we entered into a second lien Senior Secured Term Loan Agreement (the “ Term Loan Facility ”) with Morgan Stanley Energy Capital Inc., as administrative agent, and the lenders party thereto, pursuant to which we borrowed $125 million. The Term Loan Facility includes an accordion feature which allows us to borrow up to an additional $50 million of additional term loans under the Term Loan Facility within one year following the closing, subject to certain conditions. The net proceeds of approximately $121 million from the Term Loan Facility , after payment of transaction-related fees and expenses, were used to pay down outstanding amounts under our existing credit facility . The Term Loan Facility matures on April 15, 2018 . The principal amount is payable at maturity . Borrowings under the Term Loan Facility bear interest at adjusted LIBOR plus 8% . The covenants in the Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) current assets to current liabilities of at least 1.0 to 1.0, (ii) debt to EBITDAX of no more than 4.5 to 1.0, (iii) PV-9 of total proved reserves to total secured debt of at least 1.5 to 1.0, and (iv) EBITDAX to interest expense of at least 2.5 to 1.0. PV-9 is calculated using four year NYMEX strip pricing adjusted for differentials. Obligations under the Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and affiliates and are secured by second priority liens on substantially all of our subsidiaries assets that serve as collateral under the credit facility. As of December 31, 2015, we were in compliance with all covenants of the Term Loan Facility. We have the option to prepay all or a portion of the Term Loan Facility at any time. The Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, subject to a limited right to reinvest proceeds in capital expenditures, or an initial public offering. Such prepayments are subject to a premium of between 3% declining to 1% prior to the maturity date, and, if made prior to the first anniversary of the closing date, are also subject to a “make whole” premium to ensure that the lenders receive the total amount of interest that would have been paid from the date of prepayment to such first anniversary. Subsequent to year end, on February 3, 2016, we entered into the first amendment to the Term Loan Facility (the “First Amendment”). The First Amendment: (a) permits us to enter into exchanges of outstanding senior notes for third lien term loan, (b) allows us to dispose of oil and natural gas properties pursuant to the joint development agreement with BCE(as defined and further discussed in Note 16), (c) requires that twice a month we transfer available cash in excess of $25 million to a controlled account, with such funds in the controlled account to not be treated as debt for the purposes of leverage ratio compliance so long as they remain in the controlled account, and (d) increases the maximum leverage ratio for the fiscal quarters ending June 30, 2016 and September 30, 2016 from 4.50 to 1.00 to 5.00 to 1.00. 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% . I nterest 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 and the Term Loan 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 $ 1.4 million and $1.9 million at December 31, 2015 and December 31, 2014 , 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. Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase. Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $ 25.7 million and $ 24.5 million at December 31, 2015 and December 31, 2014 , 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. Our founder may convert the notes into shares of our Class B partner’s, 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 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 the years ended December 31, 2015, 2014, and 201 3. Such amounts have been added to the balance of the founder notes. Deferred financing costs. As of December 31, 2015, the Company had $9.0 million of deferred financing costs related to the credit facility, Term Loan Facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $7.8 million related to the Term Loan Facility and senior notes are included in long-term debt on the consolidated balance sheet as of December 31, 2015 in accordance with ASU 2015-03, which we adopted in the fourth quarter of 2015 (see Note 2 — Summary of Significant Accounting Policies). Deferred financing costs of $1.2 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2015. Amortization of deferred financing costs recorded for the years ended December 31, 2015, 2014 and 2013 was $3.4 million, $2.9 million and $2.8 million, respectively. These costs are included in interest expense on the consolidated statement of operations. Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized discount, at December 31, 2015 are as follows ( in thousands ): Year ending December 31, 2016 $ — 2017 152,000 2018 575,000 2019 — 2020 — Thereafter 25,748 $ 752,748 The credit facility, Term Loan Facility and senior notes also contain restrictive covenants that limit our ability to, among other things, incur or guarantee additional debt, make distributions (except distributions equal to the amount of income tax liabilities), repay subordinated debt prior to its maturity, grant additional liens on our assets, enter into transactions with our affiliates, enter into hedging transactions with non-lender hedge counterparties, repurchase equity securities, make certain investments or acquisitions of substantially all or a portion of another entity’s business assets, and merge with another entity of dispose of any material assets. The credit facility, Term Loan Facility and senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. At December 31, 2015, we were in compliance with the covenants of our loan agreements. |
Accounts Payable And Accrued Li
Accounts Payable And Accrued Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 (in thousands) Capital expenditures $ 10,780 $ 32,990 Revenues and royalties payable 5,082 7,302 Operating expenses/taxes 19,336 20,716 Interest 9,919 9,136 Compensation 5,434 10,586 Derivatives settlement payable 11,149 2,344 Other 1,201 261 Total accrued liabilities 62,901 83,335 Accounts payable 21,101 34,225 Accounts payable and accrued liabilities $ 84,002 $ 117,560 |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
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. 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, 2015. 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 groundwater contamination in Florida of $1.3 million at December 31, 2015 and $1.1 million at December 31, 2014, 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 designated value (“SIDV”). 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 stipulated 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 2015, we granted zero PARs and terminated 30,000 PARs with a SIDV of $40 , resulting in 241,500 PARS issued at a weighted average value of $32.34 . Subsequent to year end, 360,000 PARs were issued with a SIDV of $40 and 3,500 PARs with a SIDV of $40 were terminated, resulting in 598,000 PARs issued at a weighted average value of $36.91 . 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, 2015 and 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, 2015, 2014, and 2013 amounted to approximately $4.8 million, $5.7 million, and $5.3 million, respectively. At December 31, 2015, future base rentals for non-cancelable operating leases are as follows ( in thousands ): Year Ending December 31, 2016 $ 4,130 2017 2,899 2018 1,574 2019 1,580 2020 1,593 Thereafter 2,827 $ 14,603 Additionally, at December 31, 2015, the Company had posted bonds in the aggregate amount of $24.4 million, primarily to cover future abandonment costs. |
Major Customers
Major Customers | 12 Months Ended |
Dec. 31, 2015 | |
Major Customers [Abstract] | |
Major Customers | NOTE 12 — MAJOR CUSTOMERS We sell our oil and natural gas primarily under a contract with AEM. We are 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 and 2015, 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 prior to their sale, 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, 2015, revenues from AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, no other major customer accounted for 10% or more of revenues. 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.) 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. |
401(k) Savings Plan
401(k) Savings Plan | 12 Months Ended |
Dec. 31, 2015 | |
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 $710,000 , $683,000 , and $ 585,000 for the years ended December 31, 2015, 2014, and 2013, respectively. |
Significant Risks And Uncertain
Significant Risks And Uncertainties | 12 Months Ended |
Dec. 31, 2015 | |
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 2015 and have declined dramatically since the second half of 2014. 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 oil and natural gas 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 2016. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. 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, 2015 | |
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 sole Class B partner is High Mesa. 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. 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 partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture. Distribution and Income Allocation: In connection with the recapitalization on March 25, 2014, 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 certain provisions are met. After such provisions are met, 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, Term Loan Facility, and our senior notes. 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. During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | NOTE 16 — SUBSEQUENT EVENTS Drillco Contract On January 13, 2016, our wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “Joint Development Agreement”) with BCE-STACK Development LLC (the “BCE”), to fund drilling operations in Kingfisher County, Oklahoma. The drilling program initially calls for the development of forty identified well locations, which will be developed in two tranches of twenty wells each. The parties may also mutually agree to additional tranches on the same terms as the initial tranches. Under the Joint Development Agreement, BCE has committed to fund 100% of Oklahoma Energy’s working interest share of drilling and development costs for each well in which BCE elects to participate (each, a “Joint Well”), provided that to the extent that the total cost of drilling the wells in any tranche exceeds $64 million, Oklahoma Energy will be responsible for its and BCE’s working interest share of the drilling costs in such tranche exceeding such limit. We do not anticipate any such costs to be material. In exchange for the payment of drilling and completion costs, BCE will receive 80% of Oklahoma Energy’s working interest in each Joint Well, which interest will be reduced to 20% of Oklahoma Energy’s initial working interest upon BCE’s achieving a 15% internal rate of return in a tranche, and further reduced to 7.5% of Oklahoma Energy’s initial interest upon BCE’s achieving a 25% internal rate of return. Upon the achievement of these return thresholds, the interest BCE relinquishes will be automatically assigned back to Oklahoma Energy. Following the completion of each Joint Well, BCE and Oklahoma Energy will bear their proportionate working interest share of all subsequent costs and expenses related to such Joint Well. On March 8, 2016, the parties further agreed to add a third tranche of investment that will allow for the drilling of an additional 20 wells, representing an additional investment of up to $64 million. The terms and conditions are the same as those of the first two tranches. Drawdown under Credit Facility On March 16, 2016, we borrowed $141.9 million under the credit facility, which represented the remaining undrawn amount that was available under the credit facility. As required by the terms of the credit facility, the borrowings were deposited into an account controlled by the Admini strative Agent. Such funds will not be treated as debt for the purposes of leverage ratio compliance so long as they remai n in the controlled account. These funds are intended to be used for general corporate purposes. Following the funding of this borrowing, the aggregate principal amount of borrowings under the credit facility was $300.0 million, including $6.1 million of outstanding letters of credit, with no remaining availability. These new borrowings bear interest at 3.25% . |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2015 | |
Subsidiary Guarantors [Abstract] | |
Subsidiary Guarantors | NOTE 17 — SUBSIDIARY GUARANTORS All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes, Term Loan Facility 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 Informat
Supplemental Quarterly Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Quarterly Information [Abstract] | |
Supplemental Quarterly Information | NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) Results of operations by quarter for the year ended December 31, 2015 were: Quarter Ended 2015 March 31 June 30 Sept 30 Dec 31 (in thousands) Revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (1)(2) (95,077) (23,881) 110,069 (60,592) Net income (loss) $ (109,211) $ (39,509) $ 93,079 $ (76,152) (1) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (2) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively. Results of operations by quarter for the year ended December 31, 2014 were: Quarter Ended 2014 March 31 June 30 Sept 30 Dec 31 (in thousands) Revenues $ 103,432 $ 115,590 $ 125,644 $ 87,462 Income (loss) from operations (3)(4) 71,461 (25,186) 73,025 35,873 Net income (loss) $ 56,893 $ (38,812) $ 59,326 $ 21,793 (3) Includes $73.1 million and $18.3 million gain on sale of asset during the quarters ended March 31, 2014 and September 30, 2014, respectively. (4) Includes $18.3 million, and $8.7 million of impairment expense during the quarters ended June 30, 2014 and September 30, 2014, respectively. |
Supplemental Oil And Natural Ga
Supplemental Oil And Natural Gas Disclosures | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 , 2014, and 2013, 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, 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 Production (4,203) (11,900) (678) (6,865) Discoveries and extensions 12,981 58,129 7,763 30,432 Sales of reserves in place (6,544) (8,250) (748) (8,667) Revisions of previous quantity estimates and other 564 14,296 3,712 6,660 Balance at December 31, 2015 34,142 155,423 18,437 78,483 Proved Developed Reserves: 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 Balance at December 31, 2015 14,942 71,752 6,958 33,859 Proved Undeveloped Reserves: 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 Balance at December 31, 2015 19,200 83,671 11,479 44,624 Capitalized Costs Relating to Oil and Natural Gas Producing Activities December 31, 2015 2014 (in thousands) Capitalized costs: Proved properties $ 1,345,482 $ 1,417,785 Unproved properties 127,551 84,620 Total 1,473,033 1,502,405 Accumulated depreciation, depletion, amortization and impairment (947,091) (816,229) Net capitalized costs $ 525,942 $ 686,176 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, 2015 2014 2013 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 74,475 $ 33,787 $ 34,884 Proved (2) 2,899 7,462 35,954 Exploration 34,275 59,201 55,300 Development (3) 146,299 341,594 242,912 $ 257,948 $ 442,044 $ 369,050 (1) Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. (3) Includes asset retirement additions (revisions) of ($0.3) million, $4.5 million, and $1.4 million for the years ended December 31, 2015 , 2014, and 2013, 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, 2015 and 2014 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, 2015 , 2014, and 2013: Year Ended December 31, 2015 2014 2013 (in thousands) Future cash flows $ 2,395,128 $ 3,737,412 $ 3,959,938 Future production costs (860,600) (991,149) (1,146,123) Future development costs (403,953) (450,659) (474,191) Future taxes on income — — — Future net cash flows 1,130,575 2,295,604 2,339,624 Discount to present value at 10 percent per annum (500,979) (877,558) (933,350) Standardized measure of discounted future net cash flows $ 629,596 $ 1,418,046 $ 1,406,274 Base price for crude oil, per Bbl, in the above computation was: $ 50.28 $ 94.99 $ 96.78 Base price for natural gas, per Mcf, in the above computation was: $ 2.58 $ 4.35 $ 3.67 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, 2015 2014 2013 (in thousands) Balance at beginning of year $ 1,418,046 $ 1,406,274 $ 914,421 Sales of oil and natural gas, net of production costs (147,906) (320,130) (263,952) Changes in sales and transfer prices, net of production costs (823,073) (153,770) 69,609 Revisions of previous quantity estimates 53,101 (477,377) (150,634) Purchases of reserves-in-place — 21,633 93,877 Sales of reserves-in-place (244,251) (107,414) (11,193) Current year discoveries and extensions 260,078 701,820 621,832 Changes in estimated future development costs 4,376 2,591 11,623 Development costs incurred during the year 42,420 161,357 75,973 Accretion of discount 141,805 140,627 91,442 Net change in income taxes — — — Change in production rate (timing) and other (75,000) 42,435 (46,724) Net change (788,450) 11,772 491,853 Balance at end of year $ 629,596 $ 1,418,046 $ 1,406,274 |
Summary Of Significant Accoun26
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2015 | |
Summary Of Significant Accounting Policies [Abstract] | |
Principles Of Consolidation And Reporting | Principles of Consolidation . The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). 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 | Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ deficit. In the fourth quarter of 2015, the Company adopted Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”), which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of debt discount, but does not affect the recognition or measurement of debt issuance costs. In accordance with the new guidance, deferred financing costs related to the Company’s senior unsecured notes and Term Loan Facility (as defined in Note 9), which had been included in deferred financing costs, net under other assets on the consolidated balance sheets prior to the adoption of ASU 2015-03, are now included in long-term debt on the consolidated balance sheets, resulting in decreases in both deferred financing costs, net and long-term debt of $7.8 million as of December 31, 2015. ASU 2015-03 was applied on a retrospective basis, wherein the balance sheet of each individual period presented was adjusted to reflect the period-specific effects of applying the new guidance. As a result, the consolidated balance sheet as of December 31, 2014 included a deduction for deferred financing costs of $6.5 million in long-term debt, which had previously been presented in deferred financing costs, net under other assets. Deferred financing costs incurred in connection with the Company’s revolving credit facility continue to be presented in deferred financing costs, net under other assets on the consolidated balance sheets consistent with prior periods as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”). |
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, 2015, the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute. As of December 31, 2014 , the Company had $24.6 million of proceeds remaining 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 from the sale of our Hilltop field Deep Bossier properties. Not all of the cash deposited with the qualified intermediary was used for like-kind-exchange transactions, and in March 2015, the remaining $23.7 million of restricted cash was returned to us to be used for general corporate purposes and, as such, was classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. T he Company planned 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 . 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 $ 9.8 million and $ 10.3 million at December 31, 2015 and 2014, respectively. Trade receivables from the sale of oil and natural gas were $17.9 million and $35.1 million at December 31, 2015 and 2014, respectively. See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC (“AEM”). Accounts receivable from AEM were $12.6 million and $16.6 million as of December 31, 2015 and 2014, 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. |
Deferred Financing Costs | Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the consolidated statement of operations. |
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, or “suspended” on the balance sheet 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 $ 172.0 million, $ 72.9 million and $ 135.2 million for the years ended December 31, 2015, 2014, and 2013, respectively, primarily due to lower forecasted commodity prices. 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, 2015, 2014 and 2013, impairment expense of unproved properties was $ 4.8 million, $ 2.0 million, and $ 8.0 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, 201 5, 201 4, and 201 3, 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, 2015, 2014, and 2013 related to oil and natural gas properties was $ 140.9 million, $139.0 million, and $115.5 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, 2015, 2014, and 2013 was $ 3.0 million, $2.8 million, and $3.1 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. |
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 “ 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, 2015 and 2014 . 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, 2015 , 2014 , or 2013 . The Company’s tax returns for the years ended December 31, 2012 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 fair value estimate 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 estimate of our senior secured term loan is not considered to be materially different from carrying value as there were no significant changes in our credit risk. The fair value of the debt to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. We have estimated the fair value of our $450 million senior notes payable at $162 million on December 31, 2015 . Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments see Note 5 – Fair value disclosures and Note 9 - 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 May 2014, the FASB issued ASU No. 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. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 September 2015, the FASB issued ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments , which eliminates the requirement for an acquirer in a business combination to restate prior period financial statements for measurement period adjustments. ASU 2015-16 requires that the cumulative impact of measurement period adjustments on current and prior periods be recognized in the reporting period in which the adjustment amount is determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations. In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities , which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations . In February 2016, the FASB issued ASU 2016-02 , Leases (Topic 842) which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. |
Derivative Financial Instrume27
Derivative Financial Instruments (Policy) | 12 Months Ended |
Dec. 31, 2015 | |
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, natural gas and natural gas liquids. 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) on derivative contracts.” Cash flows from settlements of derivative contracts are classified as 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, natural gas, and natural gas liquids. 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, natural gas, and natural gas liquids 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 oil production equivalent to barrels (Bbl) per month, gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) 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 Acquisition And D28
Significant Acquisition And Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Significant Acquisition and Divestitures [Abstract] | |
Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices | October 1, 2013 (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) (in thousands) Actual results of Stone 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, 2013 $ 376,063 $ (146,866) |
Property And Equipment (Tables)
Property And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property And Equipment [Abstract] | |
Property And Equipment | December 31, December 31, 2015 2014 (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 127,551 $ 84,620 Accumulated impairment (2,684) (3,749) Unproved properties, net 124,867 80,871 Proved oil and natural gas properties 1,345,482 1,417,785 Accumulated depreciation, depletion, amortization and impairment (944,407) (812,480) Proved oil and natural gas properties, net 401,075 605,305 TOTAL OIL AND NATURAL GAS PROPERTIES, net 525,942 686,176 LAND 3,868 2,820 OTHER PROPERTY AND EQUIPMENT Office furniture and equipment, vehicles 18,794 17,302 Accumulated depreciation (11,565) (8,617) OTHER PROPERTY AND EQUIPMENT, net 7,229 8,685 TOTAL PROPERTY AND EQUIPMENT, net $ 537,039 $ 697,681 |
Capitalized Exploratory Well Costs Roll Forward Table | Year Ended December 31, 2015 2014 2013 (in thousands) Balance, beginning of year $ 13,301 $ 20,317 $ 3,863 Additions to capitalized well costs pending determination of proved reserves 4,364 15,870 21,387 Reclassifications to proved properties (8,583) (6,593) (4,933) Capitalized exploratory well costs charged to expense (3,076) (16,293) — Balance, end of year $ 6,006 $ 13,301 $ 20,317 |
Fair Value Disclosures (Tables)
Fair Value Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis | Level 1 Level 2 Level 3 Total (in thousands) At December 31, 2015: Financial Assets: Derivative contracts for oil and natural gas — $ 166,106 — $ 166,106 Financial Liabilities: Derivative contracts for oil and natural gas — $ 61,840 — $ 61,840 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 |
Derivative Financial Instrume31
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative [Line Items] | |
Fair Values Of Derivative Contracts | Net Fair Gross Gross amounts Value of Assets December 31, 2015 Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current assets $ 86,000 $ (23,369) $ 62,631 Derivative financial instruments, long-term assets 80,106 (38,471) 41,635 Total $ 166,106 $ (61,840) $ 104,266 Net Fair Gross Gross amounts Value of Liabilities December 31, 2015 Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current liabilities $ 23,369 $ (23,369) $ — Derivative financial instruments, long-term liabilities 38,471 (38,471) — Total $ 61,840 $ (61,840) $ — Net Fair Gross Gross amounts Value of Assets December 31, 2014 Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (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 December 31, 2014 Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (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) $ — |
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) 2015 2014 2013 (in thousands) Oil commodity contracts Gain (loss) on derivative contracts $ 113,295 $ 82,510 $ (17,715) Natural gas commodity contracts Gain on derivative contracts 10,712 14,049 565 Natural gas liquids commodity contracts Gain on derivative contracts 134 — — Total gains (losses) from derivatives not designated as hedges $ 124,141 $ 96,559 $ (17,150) |
Oil Derivative Contracts [Member] | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume Weighted Range Period and Type of Contract in Bbls Average High Low 2016 Price Swap Contracts 2,532,300 $ 64.16 $ 94.92 $ 53.00 Collar Contracts Short Call Options 739,100 99.69 130.00 75.00 Long Put Options 603,800 63.71 95.00 40.55 Short Put Options 420,800 72.81 75.00 65.00 2017 Collar Contracts Short Call Options 1,960,150 85.02 113.83 62.50 Long Put Options 1,412,650 72.27 90.00 60.00 Short Put Options 1,412,650 54.63 70.00 45.00 2018 Collar Contracts Short Call Options 1,183,000 80.51 104.65 72.00 Long Put Options 1,183,000 67.05 80.00 62.50 Short Put Options 1,183,000 48.90 60.00 45.00 2019 Collar Contracts Short Call Options 821,250 75.17 75.70 74.50 Long Put Options 821,250 62.50 62.50 62.50 Short Put Options 821,250 45.00 45.00 45.00 |
Natural Gas Derivative Contract [Member] | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume in Weighted Range Period and Type of Contract MMBtu Average High Low 2016 Price Swap Contracts 7,320,000 $ 3.05 $ 3.17 $ 2.95 Collar Contracts Short Call Options 1,510,000 2.40 2.40 2.40 Long Put Options 1,510,000 2.25 2.25 2.25 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 |
Natural Gas Liquids Derivative Contracts [Member] | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume Weighted Range Period and Type of Contract in Gal Average High Low 2016 Price Swap Contracts 3,843,000 $ 0.44 $ 0.44 $ 0.44 |
Basis Swap Derivative Contract [Member] | |
Derivative [Line Items] | |
Open Financial Basis Swap Contracts | Weighted Average Spread Volume in MMBtu Reference Price 1 (1) Reference Price 2 (1) Period ($ per MMBtu) 4,125,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Apr ’16 — Dec ’16 $ 0.27 1,350,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’17 — Mar ’17 0.25 (1) The spread in these trades limits the differential of the settlement quotation prices for Tex/OKL Panhandle Eastern Pipeline (PEPL) inside FERC (IFERC) over NYMEX Henry Hub. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligations [Abstract] | |
Summary Of Changes In Asset Retirement Obligations | Year Ended December 31, 2015 2014 2013 (in thousands) Balance, beginning of year $ 62,872 $ 56,023 $ 48,593 Liabilities incurred 1,988 1,129 1,052 Liabilities assumed with acquired producing properties — 3,002 5,480 Liabilities settled (1,794) (3,942) (1,548) Liabilities transferred in sales of properties (3,149) (1,886) (606) Revisions to estimates (773) 6,348 919 Accretion expense 2,076 2,198 2,133 Balance, end of year 61,220 62,872 56,023 Less: Current portion 729 1,136 3,844 Long term portion $ 60,491 $ 61,736 $ 52,179 |
Long Term Debt (Tables)
Long Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Long Term Debt [Abstract] | |
Long-Term Debt And Notes Payable To Founder | December 31, December 31, 2015 2014 (in thousands) Credit Facility $ 152,000 $ 319,520 Senior Secured Term Loan 125,000 — Senior Notes 448,598 448,088 Unamortized deferred financing costs (7,823) (6,466) Total long-term debt $ 717,775 $ 761,142 Notes payable to founder $ 25,748 $ 24,540 |
Summary Of Future Maturities Of Long-Term Debt | Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized discount, at December 31, 2015 are as follows ( in thousands ): Year ending December 31, 2016 $ — 2017 152,000 2018 575,000 2019 — 2020 — Thereafter 25,748 $ 752,748 |
Accounts Payable And Accrued 34
Accounts Payable And Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounts Payable And Accrued Liabilities [Abstract] | |
Detail Of Accounts Payable And Accrued Liabilities | December 31, December 31, 2015 2014 (in thousands) Capital expenditures $ 10,780 $ 32,990 Revenues and royalties payable 5,082 7,302 Operating expenses/taxes 19,336 20,716 Interest 9,919 9,136 Compensation 5,434 10,586 Derivatives settlement payable 11,149 2,344 Other 1,201 261 Total accrued liabilities 62,901 83,335 Accounts payable 21,101 34,225 Accounts payable and accrued liabilities $ 84,002 $ 117,560 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments And Contingencies [Abstract] | |
Future Base Rentals For Non-Cancelable Leases | At December 31, 2015, future base rentals for non-cancelable operating leases are as follows ( in thousands ): Year Ending December 31, 2016 $ 4,130 2017 2,899 2018 1,574 2019 1,580 2020 1,593 Thereafter 2,827 $ 14,603 |
Supplemental Quarterly Inform36
Supplemental Quarterly Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Quarterly Information [Abstract] | |
Summary Of Quarterly Results Of Operations | Results of operations by quarter for the year ended December 31, 2015 were: Quarter Ended 2015 March 31 June 30 Sept 30 Dec 31 (in thousands) Revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (1)(2) (95,077) (23,881) 110,069 (60,592) Net income (loss) $ (109,211) $ (39,509) $ 93,079 $ (76,152) (1) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (2) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively. Results of operations by quarter for the year ended December 31, 2014 were: Quarter Ended 2014 March 31 June 30 Sept 30 Dec 31 (in thousands) Revenues $ 103,432 $ 115,590 $ 125,644 $ 87,462 Income (loss) from operations (3)(4) 71,461 (25,186) 73,025 35,873 Net income (loss) $ 56,893 $ (38,812) $ 59,326 $ 21,793 (3) Includes $73.1 million and $18.3 million gain on sale of asset during the quarters ended March 31, 2014 and September 30, 2014, respectively. (4) Includes $18.3 million, and $8.7 million of impairment expense during the quarters ended June 30, 2014 and September 30, 2014, respectively. |
Supplemental Oil And Natural 37
Supplemental Oil And Natural Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 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 Production (4,203) (11,900) (678) (6,865) Discoveries and extensions 12,981 58,129 7,763 30,432 Sales of reserves in place (6,544) (8,250) (748) (8,667) Revisions of previous quantity estimates and other 564 14,296 3,712 6,660 Balance at December 31, 2015 34,142 155,423 18,437 78,483 Proved Developed Reserves: 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 Balance at December 31, 2015 14,942 71,752 6,958 33,859 Proved Undeveloped Reserves: 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 Balance at December 31, 2015 19,200 83,671 11,479 44,624 |
Capitalized Costs Relating To Oil And Natural Gas Producing Activities | December 31, 2015 2014 (in thousands) Capitalized costs: Proved properties $ 1,345,482 $ 1,417,785 Unproved properties 127,551 84,620 Total 1,473,033 1,502,405 Accumulated depreciation, depletion, amortization and impairment (947,091) (816,229) Net capitalized costs $ 525,942 $ 686,176 |
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities | Year Ended December 31, 2015 2014 2013 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 74,475 $ 33,787 $ 34,884 Proved (2) 2,899 7,462 35,954 Exploration 34,275 59,201 55,300 Development (3) 146,299 341,594 242,912 $ 257,948 $ 442,044 $ 369,050 (1) Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. (3) Includes asset retirement additions (revisions) of ($0.3) million, $4.5 million, and $1.4 million for the years ended December 31, 2015 , 2014, and 2013, respectively. |
Components Of The Standardized Measure Of Discounted Future Net Cash Flows | Year Ended December 31, 2015 2014 2013 (in thousands) Future cash flows $ 2,395,128 $ 3,737,412 $ 3,959,938 Future production costs (860,600) (991,149) (1,146,123) Future development costs (403,953) (450,659) (474,191) Future taxes on income — — — Future net cash flows 1,130,575 2,295,604 2,339,624 Discount to present value at 10 percent per annum (500,979) (877,558) (933,350) Standardized measure of discounted future net cash flows $ 629,596 $ 1,418,046 $ 1,406,274 Base price for crude oil, per Bbl, in the above computation was: $ 50.28 $ 94.99 $ 96.78 Base price for natural gas, per Mcf, in the above computation was: $ 2.58 $ 4.35 $ 3.67 |
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Year Ended December 31, 2015 2014 2013 (in thousands) Balance at beginning of year $ 1,418,046 $ 1,406,274 $ 914,421 Sales of oil and natural gas, net of production costs (147,906) (320,130) (263,952) Changes in sales and transfer prices, net of production costs (823,073) (153,770) 69,609 Revisions of previous quantity estimates 53,101 (477,377) (150,634) Purchases of reserves-in-place — 21,633 93,877 Sales of reserves-in-place (244,251) (107,414) (11,193) Current year discoveries and extensions 260,078 701,820 621,832 Changes in estimated future development costs 4,376 2,591 11,623 Development costs incurred during the year 42,420 161,357 75,973 Accretion of discount 141,805 140,627 91,442 Net change in income taxes — — — Change in production rate (timing) and other (75,000) 42,435 (46,724) Net change (788,450) 11,772 491,853 Balance at end of year $ 629,596 $ 1,418,046 $ 1,406,274 |
Summary Of Significant Accoun38
Summary Of Significant Accounting Policies (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Mar. 25, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summary Of Significant Accounting Policies [Line Items] | ||||
FDIC insured maximum amount | $ 250,000 | |||
Proceeds from sale of property | 141,404,000 | $ 177,476,000 | $ 26,668,000 | |
Amount of restricted cash refunded from investment | $ 23,700,000 | |||
Long-term restricted cash | 900,000 | |||
Receivables from joint interest owners | 9,800,000 | 10,300,000 | ||
Receivables from oil, natural gas, and natural gas liquids sales | 17,900,000 | 35,100,000 | ||
Impairment expense of proved properties | 172,000,000 | 72,900,000 | 135,200,000 | |
Impairment expense of unproved properties | 4,800,000 | 2,000,000 | 8,000,000 | |
Depreciation depletion and amortization related to oil and gas properties | 140,900,000 | 139,000,000 | 115,500,000 | |
Depreciation expense for other property and equipment | $ 3,000,000 | 2,800,000 | 3,100,000 | |
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 | 162,000,000 | |||
Deferred financing cost, net reclassed to LT Debt | 7,800,000 | 6,500,000 | ||
ARM Energy Management, LLC [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Accounts receivable | $ 12,600,000 | 16,600,000 | ||
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 | |||
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 Acquisition and D39
Significant Acquisition and Divestitures (Narrative) (Details) bbl in Millions, MMBbls in Millions | Jul. 06, 2015USD ($)a | Sep. 19, 2014USD ($)MMcf | Oct. 01, 2013USD ($) | Jul. 01, 2013MMcfbbl | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)bbl | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jul. 01, 2015MMBbls |
Business Acquisition [Line Items] | |||||||||||
Payment towards acquisition of all working interests | $ 42,000,000 | ||||||||||
Gain (loss) on sale of assets | $ 66,400,000 | $ 18,300,000 | $ 73,100,000 | $ 67,781,000 | $ 87,520,000 | (2,715,000) | |||||
Other receivables | 18,526,000 | 8,238,000 | |||||||||
Drilling Rig [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Sale of drilling rig, cash purchase price | 7,000,000 | ||||||||||
Gain (loss) on sale of assets | (1,200,000) | ||||||||||
Alta Mesa Eagle, LLC Divestiture [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Initial cash purchase price for properties sold | 118,000,000 | ||||||||||
Cash purchase price | 125,000,000 | ||||||||||
Additional contingent payment | 7,000,000 | ||||||||||
Adjusted cash purchase price, net of costs of transaction | 4,000,000 | ||||||||||
Estimated proved reserves | MMBbls | 7.8 | ||||||||||
Gain on sale of oil and gas properties | 67,600,000 | 72,500,000 | |||||||||
Operating income from sold oil and gas properties | 68,900,000 | 118,500,000 | |||||||||
Other receivables | $ 122,000,000 | ||||||||||
Oklahoma [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Net acres | a | 19,000 | ||||||||||
Cash consideration for Undeveloped Leasehold | $ 46,200,000 | ||||||||||
Eagleville Divestiture [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Date of acquisition or sale of properties | Mar. 25, 2014 | ||||||||||
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 | $ 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 | |||||||||
Eagleville Divestiture [Member] | Barrels of Oil Equivalent [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated proved reserves | bbl | 7.5 | ||||||||||
Hilltop Divestiture 2014 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Date of acquisition or sale of properties | Sep. 19, 2014 | ||||||||||
Cash purchase price | $ 41,600,000 | $ 38,900,000 | |||||||||
Gain on sale of oil and gas properties | $ 15,900,000 | ||||||||||
Operating income from sold oil and gas properties | $ 7,700,000 | ||||||||||
Hilltop Divestiture 2014 [Member] | Natural Gas in MMcf [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated proved reserves | MMcf | 29,800 | ||||||||||
Hilltop Divestiture 2013 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Date of acquisition or sale of properties | Oct. 2, 2013 | ||||||||||
Cash purchase price | $ 19,000,000 | ||||||||||
Gain on sale of oil and gas properties | $ 0 | ||||||||||
Operating income from sold oil and gas properties | $ 6,900,000 | ||||||||||
Hilltop Divestiture 2013 [Member] | Natural Gas in MMcf [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated proved reserves | MMcf | 11,200 | ||||||||||
Stone [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Acquisition effective date | Oct. 1, 2013 | ||||||||||
Payment towards acquisition of all working interests | $ 41,841,000 | ||||||||||
Total estimated net proved reserves acquired | bbl | 1.8 | ||||||||||
Acquisition effective date | Jul. 1, 2013 |
Significant Acquisition And D40
Significant Acquisition And Divestitures (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Details) - USD ($) $ in Thousands | Oct. 01, 2013 | Dec. 31, 2013 |
Business Acquisition [Line Items] | ||
Cash | $ 42,000 | |
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 | |
Unproved oil and natural gas properties | 16,873 | |
Total | $ 47,152 |
Significant Acquisition And D41
Significant Acquisition And Divestitures (Summary Of Pro Forma Information) (Details) - Stone [Member] $ in Thousands | 12 Months Ended |
Dec. 31, 2013USD ($) | |
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 |
Pro Forma Income (Loss) | $ (146,866) |
Property And Equipment (Summary
Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property And Equipment [Abstract] | ||
Unproved properties | $ 127,551 | $ 84,620 |
Accumulated impairment | (2,684) | (3,749) |
Unproved properties, net | 124,867 | 80,871 |
Proved oil and natural gas properties | 1,345,482 | 1,417,785 |
Accumulated depreciation, depletion, amortization and impairment | (944,407) | (812,480) |
Proved oil and natural gas properties, net | 401,075 | 605,305 |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | 525,942 | 686,176 |
LAND | 3,868 | 2,820 |
Office furniture and equipment, vehicles | 18,794 | 17,302 |
Accumulated depreciation | (11,565) | (8,617) |
OTHER PROPERTY AND EQUIPMENT, net | 7,229 | 8,685 |
Total property and equipment, net | $ 537,039 | $ 697,681 |
Property And Equipment (Capital
Property And Equipment (Capitalized Exploratory Well Costs) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves | |||
Capitalized Exploratory Well Costs, Beginning Balance | $ 13,301 | $ 20,317 | $ 3,863 |
Additions to capitalized well costs pending determination of proved reserves | 4,364 | 15,870 | 21,387 |
Reclassifications to proved based on determination of proved reserves | (8,583) | (6,593) | (4,933) |
Capitalized Exploratory Well Costs, Ending Balance | $ 6,006 | 13,301 | $ 20,317 |
Number of wells included in ending balance in deferred capitalized exploratory well costs | item | 6 | ||
Number of prospects | item | 2 | ||
Capitalized exploratory well costs that have been capitalized for period greater than one year | $ 3,000 | $ 2,200 |
Fair Value Disclosures (Narrati
Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2015 | Sep. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value Disclosures [Line Items] | ||||||||
Carrying value of oil and gas properties | $ 499,600 | $ 148,400 | $ 237,200 | |||||
Written down fair value of oil and gas properties | 322,800 | 73,500 | 94,000 | |||||
Impairment charges to oil and gas properties | $ 90,500 | $ 8,900 | $ 73,100 | $ 8,700 | $ 18,300 | 176,774 | 74,927 | 143,166 |
Asset retirement obligation measured at fair value | $ 2,000 | $ 4,100 | ||||||
Stone [Member] | ||||||||
Fair Value Disclosures [Line Items] | ||||||||
Fair value of oil and gas properties acquired | $ 47,200 |
Fair Value Disclosures (Measure
Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Financial Assets: | ||
Derivative contracts for oil and natural gas, gross | $ 166,106 | $ 140,652 |
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross | $ 61,840 | $ 53,578 |
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 | $ 166,106 | $ 140,652 |
Financial Liabilities: | ||
Derivative contracts for oil and natural gas, gross | $ 61,840 | $ 53,578 |
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 Instrume46
Derivative Financial Instruments (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | 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 receivables | $ 17,500 | $ 8,000 |
Derivative Financial Instrume47
Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | $ 166,106 | $ 146,666 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | (61,840) | (59,592) |
Derivative Assets, Current | 62,631 | 59,803 |
Derivative Assets, Noncurrent | 41,635 | 27,271 |
Derivative assets, net, total | 104,266 | 87,074 |
Derivative liabilities, Gross Fair Value of Liabilities | 61,840 | 59,592 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | (61,840) | (59,592) |
Derivative Assets Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 86,000 | 91,341 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | (23,369) | (31,538) |
Derivative Assets, Current | 62,631 | 59,803 |
Derivative Asset Non-Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 80,106 | 55,325 |
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet | (38,471) | (28,054) |
Derivative Assets, Noncurrent | 41,635 | 27,271 |
Derivative Liabilities Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 23,369 | 31,538 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | (23,369) | (31,538) |
Derivative Liabilities Non Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 38,471 | 28,054 |
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet | $ (38,471) | $ (28,054) |
Derivative Liabilities, Noncurrent |
Derivative Financial Instrume48
Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | $ 124,141 | $ 96,559 | $ (17,150) |
Oil Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 113,295 | 82,510 | (17,715) |
Natural Gas Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 10,712 | 14,049 | 565 |
Natural Gas Liquids Commodity Contract [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | 134 | ||
Not Designated As Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Total gains (losses) from oil and natural gas commodity contracts | $ 124,141 | $ 96,559 | $ (17,150) |
Derivative Financial Instrume49
Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil Derivative Contracts [Member] | 12 Months Ended |
Dec. 31, 2015$ / bblbbl | |
Price Swap Contracts [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,532,300 |
Weighted Average Swap Price | 64.16 |
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 | 53 |
Short Call Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 739,100 |
Weighted Average Option Price | 99.69 |
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 | 75 |
Short Call Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,960,150 |
Weighted Average Option Price | 85.02 |
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 | 62.50 |
Short Call Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,183,000 |
Weighted Average Option Price | 80.51 |
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 | 72 |
Short Call Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 821,250 |
Weighted Average Option Price | 75.17 |
Short Call Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 75.70 |
Short Call Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 74.50 |
Long Put Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 603,800 |
Weighted Average Option Price | 63.71 |
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 | 40.55 |
Long Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,412,650 |
Weighted Average Option Price | 72.27 |
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 | 60 |
Long Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,183,000 |
Weighted Average Option Price | 67.05 |
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 | 62.50 |
Long Put Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 821,250 |
Weighted Average Option Price | 62.50 |
Long Put Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 62.50 |
Long Put Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 62.50 |
Short Put Options [Member] | 2016 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 420,800 |
Weighted Average Option Price | 72.81 |
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 | 65 |
Short Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,412,650 |
Weighted Average Option Price | 54.63 |
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 | 45 |
Short Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,183,000 |
Weighted Average Option Price | 48.90 |
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 | 45 |
Short Put Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 821,250 |
Weighted Average Option Price | 45 |
Short Put Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 45 |
Short Put Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 45 |
Derivative Financial Instrume50
Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural Gas [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTU | |
2016 [Member] | Price Swap Contracts [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 7,320,000 |
Weighted Average Swap Price | 3.05 |
2016 [Member] | Price Swap Contracts [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 3.17 |
2016 [Member] | Price Swap Contracts [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 2.95 |
2016 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,510,000 |
Weighted Average Option Price | 2.40 |
2016 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 2.40 |
2016 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 2.40 |
2016 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,510,000 |
Weighted Average Option Price | 2.25 |
2016 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 2.25 |
2016 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 2.25 |
2017 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 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 | MMBTU | 6,570,000 |
Weighted Average Option Price | 4.50 |
2017 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.50 |
2017 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.50 |
2017 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 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 | MMBTU | 5,475,000 |
Weighted Average Option Price | 5.50 |
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 | MMBTU | 5,475,000 |
Weighted Average Option Price | 4.50 |
2018 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 4.50 |
2018 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 4.50 |
2018 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | 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 |
Derivative Financial Instrume51
Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Details) - 2016 [Member] - Natural Gas Liquids Derivative Contracts [Member] - Price Swap Contracts [Member] | 12 Months Ended |
Dec. 31, 2015$ / galgal | |
Derivative [Line Items] | |
Volume in Gal | gal | 3,843,000 |
Weighted Average Swap Price | 0.44 |
Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 0.44 |
Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 0.44 |
Derivative Financial Instrume52
Derivative Financial Instruments (Gas Basis Swaps) (Details) - Financial Basis Swap Contracts For Gas [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTU | |
2016 [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 4,125,000 |
First remaining period of term of derivative contract | Apr. 1, 2016 |
Last remaining period of term of derivative contract | Dec. 31, 2016 |
Weighted average spread | $ / MMBTU | 0.27 |
2017 [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,350,000 |
First remaining period of term of derivative contract | Jan. 1, 2017 |
Last remaining period of term of derivative contract | Mar. 31, 2017 |
Weighted average spread | $ / MMBTU | 0.25 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligations [Abstract] | ||||||
Balance, beginning of year | $ 62,872 | $ 56,023 | $ 48,593 | |||
Liabilities incurred | 1,988 | 1,129 | 1,052 | |||
Liabilities assumed with acquired producing properties | 3,002 | 5,480 | ||||
Liabilities settled | (1,794) | (3,942) | (1,548) | |||
Liabilities transferred in sales of properties | (3,149) | (1,886) | (606) | |||
Revisions to estimates | (773) | 6,348 | 919 | |||
Accretion expense | 2,076 | 2,198 | 2,133 | |||
Balance, end of period | 62,872 | 56,023 | 48,593 | $ 61,220 | $ 62,872 | $ 56,023 |
Less: Current portion | 729 | 1,136 | 3,844 | |||
Long-term portion | $ 60,491 | $ 61,736 | $ 52,179 | |||
Reductions to PPE included in ARO revisions | $ (1,500) | |||||
Additions To PPE Included In ARO Revisions | $ 2,900 | $ 400 |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jan. 02, 2015 | |
Related Party Transaction [Line Items] | ||||
Notes payable to founder | $ 25,700,000 | $ 24,500,000 | ||
Total expenditures for land consulting services | $ 133,000 | 150,000 | $ 175,000 | |
Contract termination period without penalty for either party | 30 days | |||
Amount of receivable paid | $ 25,500,000 | |||
Interest rate on note receivable | 8.00% | |||
Contributions | $ 20,000,000 | |||
Interest Income On Notes Receivable | 713,000 | |||
Receivable due from affiliate | 1,053,000 | 25,500,000 | ||
Non-cash land acquisition from affiliate | 700,000 | |||
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 | |||
Vice President, Facilities and Midstream [Member] | ||||
Related Party Transaction [Line Items] | ||||
Total compensation | 275,000 | 450,000 | 390,000 | |
Landman [Member] | ||||
Related Party Transaction [Line Items] | ||||
Total compensation | 146,000 | 260,000 | 125,000 | |
Founder [Member] | ||||
Related Party Transaction [Line Items] | ||||
Distributions | $ 0 | $ 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) (Det
Long Term Debt (Narrative) (Details) | Feb. 03, 2016USD ($) | Jun. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Mar. 16, 2016USD ($) | Nov. 01, 2015USD ($) | Oct. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Sep. 29, 2015USD ($) | Jun. 02, 2015USD ($) | Jun. 01, 2015USD ($) |
Debt Instrument [Line Items] | |||||||||||||
Letter of credit outstanding | $ 65,000 | $ 900,000 | |||||||||||
Face value of senior notes issued | 450,000,000 | ||||||||||||
Notes payable to founder | 25,748,000 | 24,540,000 | |||||||||||
Interest on notes payable to founder | 1,208,000 | 1,209,000 | $ 1,208,000 | ||||||||||
Amortization of deferred financing costs | $ 3,392,000 | 2,885,000 | 2,839,000 | ||||||||||
Debt covenant compliance description | At December 31, 2015, we were in compliance with the covenants of our loan agreements. | ||||||||||||
Debt restrictive covenants description | The credit facility, Term Loan Facility and senior notes also contain restrictive covenants that limit our ability to, among other things, incur or guarantee additional debt, make distributions (except distributions equal to the amount of income tax liabilities), repay subordinated debt prior to its maturity, grant additional liens on our assets, enter into transactions with our affiliates, enter into hedging transactions with non-lender hedge counterparties, repurchase equity securities, make certain investments or acquisitions of substantially all or a portion of another entity's business assets, and merge with another entity of dispose of any material assets. | ||||||||||||
Deferred financing costs | $ 1,199,000 | 1,634,000 | |||||||||||
Amortization of deferred financing costs | $ 3,400,000 | $ 2,900,000 | 2,800,000 | ||||||||||
Debt Instrument, Customary events of default | The credit facility, Term Loan Facility and senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. | ||||||||||||
6th Amended And Restated Credit Agreement [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit facility borrowing base | $ 152,000,000 | ||||||||||||
Credit Facility, Term Loan Facility, And Senior Notes [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Deferred financing costs | 9,000,000 | ||||||||||||
Term Loan Facility And Senior Notes [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Deferred financing costs | $ 7,800,000 | ||||||||||||
Credit Facility [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Line of Credit Facility, Collateral | The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. | ||||||||||||
Credit facility borrowing base | $ 255,000,000 | ||||||||||||
Line of Credit Facility, Remaining borrowing capacity | $ 0 | ||||||||||||
Date of maturity of credit facility | May 23, 2016 | ||||||||||||
Credit facility interest rate | 2.87% | 2.89% | 3.25% | ||||||||||
Letter of credit outstanding | $ 6,100,000 | ||||||||||||
Minimum Working Capital Ratio | 1 | ||||||||||||
Minimum Coverage of Interest Expense Ratio | 3 | ||||||||||||
Maximum Leverage Ratio | 4 | ||||||||||||
Debt instrument collateral | The principal amount is payable at maturity. On September 30, 2015, we entered into an Agreement and Amendment No. 12 (the "Twelfth Amendment") to amend the credit facility to permit the Eagle Ford divesture as described in Note 3 and to release AME as a guarantor from the credit facility. As a result of the Eagle Ford divestiture, the borrowing base decreased from $300 million to $255 million. Net proceeds from the Eagle Ford divestiture were used to pay down the credit facility. The credit facility borrowing base is redetermined semi-annually on or about May 1 and November 1 of each year. In November 2015, the lenders under the credit facility approved an increase in the borrowing base from $255 million to $300 million as part of the semi-annual redetermination. The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. | ||||||||||||
Debt covenants description | 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 expense 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. | ||||||||||||
Deferred financing costs | $ 1,200,000 | ||||||||||||
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] | 6th Amended And Restated Credit Agreement [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Line of Credit Facility, Remaining borrowing capacity | $ 148,000,000 | ||||||||||||
Credit Facility [Member] | 11th Amendment [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit facility borrowing base | $ 300,000,000 | $ 375,000,000 | |||||||||||
Date of maturity of credit facility | Oct. 13, 2017 | ||||||||||||
Credit Facility [Member] | 12th Amendment [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit facility borrowing base | $ 300,000,000 | $ 255,000,000 | $ 300,000,000 | ||||||||||
Credit Facility [Member] | 13th Amendment [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Excess cash transferred | $ 25,000,000 | ||||||||||||
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% | ||||||||||||
Subsequent Event [Member] | Credit Facility [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Credit facility borrowing base | $ 141,900,000 | ||||||||||||
Scenario, Forecast [Member] | Credit Facility [Member] | 13th Amendment [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Maximum Leverage Ratio | 4 | 4.50 | |||||||||||
Senior Notes [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Face value of senior notes issued | $ 450,000,000 | ||||||||||||
Maturity date of debt | Oct. 15, 2018 | ||||||||||||
Stated interest rate of senior notes | 9.625% | ||||||||||||
Effective rate of interest | 9.7825% | ||||||||||||
Senior notes interest payable date | Interest is payable semi-annually each April 15th and October 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 and the Term Loan Facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. | ||||||||||||
Remaining unamortized discount | $ 1,400,000 | $ 1,900,000 | |||||||||||
Redemption price due to specific change of control events | 101.00% | ||||||||||||
Senior Notes [Member] | Twelve Mos Beginning October 15, 2015 [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Optional redemption price of Senior Notes | 102.406% | ||||||||||||
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 | Dec. 31, 2021 | Dec. 31, 2018 | |||||||||||
Effective rate of interest | 10.00% | 10.00% | |||||||||||
Debt instrument collateral | 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 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. | ||||||||||||
Notes payable to founder | $ 25,700,000 | $ 24,500,000 | |||||||||||
Interest on notes payable to founder | $ 1,200,000 | $ 1,200,000 | $ 1,200,000 | ||||||||||
Senior Secured Term Loan [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Minimum Working Capital Ratio | 1 | ||||||||||||
Maximum Debt To EBITDAX Ratio | 4.5 | ||||||||||||
Minimum PV-9 Of Total Proved Reserves To Total Secured Debt Ratio | 1.5 | ||||||||||||
Minimum EBITDAX To Interest Expense Ratio | 2.5 | ||||||||||||
Amount borrowed | $ 125,000,000 | 125,000,000 | |||||||||||
Additional borrowings allowed | $ 50,000,000 | ||||||||||||
Period following closing additional borrowings can be made | 1 year | ||||||||||||
Net proceeds used to pay down outstanding amounts under existing credit facility | $ 121,000,000 | ||||||||||||
Mandatory prepayments of percentage of net cash proceeds from asset sales | 75.00% | ||||||||||||
Maturity date of debt | Apr. 15, 2018 | ||||||||||||
Senior Secured Term Loan [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Margin interest rate | 8.00% | ||||||||||||
Senior Secured Term Loan [Member] | Minimum [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Mandatory prepayments of percentage of net cash proceeds from asset sales | 1.00% | ||||||||||||
Senior Secured Term Loan [Member] | Maximum [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Premium percentage prepayments are subject to | 3.00% | ||||||||||||
Senior Secured Term Loan [Member] | Subsequent Event [Member] | 1st Amendment [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Excess cash transferred | $ 25,000,000 | ||||||||||||
Senior Secured Term Loan [Member] | Scenario, Forecast [Member] | |||||||||||||
Debt Instrument [Line Items] | |||||||||||||
Maximum Leverage Ratio | 4.50 | 5 |
Long Term Debt (Long-Term Debt
Long Term Debt (Long-Term Debt And Notes Payable To Founder) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Long Term Debt [Abstract] | ||
Credit Facility | $ 152,000 | $ 319,520 |
Senior Notes, net of discount | 448,598 | 448,088 |
Unamortized Deferred Financing Cost | (7,823) | (6,466) |
Total long-term debt | 717,775 | 761,142 |
Notes payable to founder | $ 25,748 | $ 24,540 |
Long Term Debt (Summary Of Futu
Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Summary of future maturities of long-term debt | |
2,016 | |
2,017 | $ 152,000 |
2,018 | $ 575,000 |
2,019 | |
2,020 | |
Thereafter | $ 25,748 |
Total long-term debt | $ 752,748 |
Accounts Payable And Accrued 58
Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts Payable And Accrued Liabilities [Abstract] | ||
Capital expenditures | $ 10,780 | $ 32,990 |
Revenues and royalties payable | 5,082 | 7,302 |
Operating expenses/taxes | 19,336 | 20,716 |
Interest | 9,919 | 9,136 |
Compensation | 5,434 | 10,586 |
Derivatives Settlement Payable | 11,149 | 2,344 |
Other | 1,201 | 261 |
Total accrued liabilities | 62,901 | 83,335 |
Accounts payable | 21,101 | 34,225 |
Accounts payable and accrued liabilities | $ 84,002 | $ 117,560 |
Commitments and Contingencies59
Commitments and Contingencies (Details) $ / shares in Units, $ in Thousands | Jan. 01, 2016$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jul. 24, 2013item |
Commitment And Contingencies [Line Items] | |||||
Liability for soil contamination | $ | $ 1,300 | $ 1,100 | |||
Vesting period, PARs | 5 years | ||||
Weighted average stipulated price of PARs granted | $ / shares | $ 32.34 | ||||
Number of performance appreciation rights granted | 0 | ||||
Number of performance appreciation rights terminated | 30,000 | ||||
Number of performance appreciation rights | 241,500 | ||||
Weighted average price of PARs terminated | $ / shares | $ 40 | $ 40 | |||
Other long-term litigation liabilities | $ | $ 10,829 | 6,457 | |||
Payment under contingent commitment towards properties acquired | $ | 2,200 | ||||
Rent expense | $ | 4,800 | $ 5,700 | $ 5,300 | ||
Performance Bonds Outstanding | $ | $ 24,400 | ||||
Subsequent Event [Member] | |||||
Commitment And Contingencies [Line Items] | |||||
Weighted average stipulated price of PARs granted | $ / shares | $ 36.91 | ||||
Number of performance appreciation rights granted | 360,000 | ||||
Number of performance appreciation rights terminated | 3,500 | ||||
Number of performance appreciation rights | 598,000 | ||||
Weighted average price of PARs terminated | $ / shares | $ 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 | item | 32 | ||||
Number of dredging permits | item | 2 | ||||
Number of right of way agreements | item | 4 |
Commitments And Contingencies60
Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Future base rentals for non-cancelable leases | |
2,015 | $ 4,130 |
2,016 | 2,899 |
2,017 | 1,574 |
2,018 | 1,580 |
2,019 | 1,593 |
Thereafter | 2,827 |
Total future base rental | $ 14,603 |
Major Customers (Details)
Major Customers (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)customer | Dec. 31, 2014USD ($)customer | Dec. 31, 2013USD ($) | |
Revenue, Major Customer [Line Items] | |||||||||||
Revenues | $ 48,325 | $ 61,344 | $ 71,755 | $ 60,542 | $ 87,462 | $ 125,644 | $ 115,590 | $ 103,432 | $ 433,888 | $ 616,207 | $ 355,792 |
Number of customers that accounted for 10% or more of revenues | customer | 1 | 3 | |||||||||
Minimum percentage of contribution of customers to revenue | 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 | $ 178,200 | $ 220,900 | $ 61,300 | ||||||||
Concentration Risk, Percentage | 73.90% | 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 | |||||||||
Shell Trading (US) Company [Member] | |||||||||||
Revenue, Major Customer [Line Items] | |||||||||||
Revenues | 53,900 | ||||||||||
Plains Marketing And Transportation, Inc. [Member] | |||||||||||
Revenue, Major Customer [Line Items] | |||||||||||
Revenues | $ 42,000 |
401(k) Savings Plan (Details)
401(k) Savings Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 710,000 | $ 683,000 | $ 585,000 |
Significant Risks And Uncerta63
Significant Risks And Uncertainties (Details) | 12 Months Ended |
Dec. 31, 2015 | |
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 2015 and have declined dramatically since the second half of 2014. 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 oil and natural gas 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 2016. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. |
Partners' Capital (Deficit) (De
Partners' Capital (Deficit) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)item | |
Number of classes of limited partners | item | 2 |
Amount of recapitalization | $ 350,000 |
Number of members added to Board of Directors, nominated by Highbridge | item | 1 |
Number of members added to Board of Directors, nominated by Class A partners | item | 4 |
Contributions | $ 20,000 |
Limited Partner [Member] | |
Distributions | 3,800 |
Contributions | $ 20,000 |
Subsequent Events (Details)
Subsequent Events (Details) | Mar. 08, 2016USD ($)item | Jan. 13, 2016USD ($)item | Mar. 16, 2016USD ($) | Dec. 31, 2015USD ($) | Oct. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Subsequent Event [Line Items] | ||||||
Letter of credit outstanding | $ 65,000 | $ 900,000 | ||||
Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Percent commited to fund | 100.00% | |||||
Total cost of drilling | $ 64,000,000 | |||||
Credit Facility [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Credit facility borrowing base | $ 255,000,000 | |||||
Credit facility amount | $ 300,000,000 | |||||
Letter of credit outstanding | $ 6,100,000 | |||||
Line of Credit Facility, Remaining borrowing capacity | $ 0 | |||||
Credit facility interest rate | 3.25% | 2.87% | 2.89% | |||
Credit Facility [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Credit facility borrowing base | $ 141,900,000 | |||||
Joint Development Agreement [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Number of well locations | item | 40 | |||||
Number of tranches | item | 2 | |||||
Number of wells | item | 20 | |||||
Joint Development Agreement Tranch 1 [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Percent of working interest | 80.00% | |||||
Percent of interest reduced | 20.00% | |||||
Percent of internal return rate | 15.00% | |||||
Joint Development Agreement Tranch 2 [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Percent of interest reduced | 7.50% | |||||
Percent of internal return rate | 25.00% | |||||
Joint Development Agreement Tranch 3 [Member] | Subsequent Event [Member] | ||||||
Subsequent Event [Line Items] | ||||||
Additional number of wells | item | 20 | |||||
Additional cost of drilling | $ 64,000,000 |
Supplemental Quarterly Inform66
Supplemental Quarterly Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Quarterly Information [Abstract] | |||||||||||
Revenues | $ 48,325 | $ 61,344 | $ 71,755 | $ 60,542 | $ 87,462 | $ 125,644 | $ 115,590 | $ 103,432 | $ 433,888 | $ 616,207 | $ 355,792 |
Income (loss) from operations | (60,592) | 110,069 | (23,881) | (95,077) | 35,873 | 73,025 | (25,186) | 71,461 | (69,481) | 155,173 | (98,651) |
Net income (loss) | (76,152) | 93,079 | $ (39,509) | (109,211) | 21,793 | 59,326 | $ (38,812) | 56,893 | (131,793) | 99,200 | (153,715) |
Gain on sale of asset | 66,400 | $ 18,300 | 73,100 | 67,781 | 87,520 | (2,715) | |||||
Impairment expense | $ 90,500 | $ 8,900 | $ 73,100 | $ 8,700 | $ 18,300 | $ 176,774 | $ 74,927 | $ 143,166 |
Supplemental Oil And Natural 67
Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details) | 12 Months Ended | ||
Dec. 31, 2015MMcfMBbls | Dec. 31, 2014MMcfMBbls | Dec. 31, 2013MMcfMBbls | |
Oil [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 31,344 | 32,517 | 20,620 |
Production | (4,203) | (3,770) | (2,897) |
Purchases in place | 610 | 1,462 | |
Discoveries and extensions | 12,981 | 13,281 | 14,541 |
Sales of reserves in place | (6,544) | (6,298) | (13) |
Revisions of previous quantity estimates and other | 564 | (4,996) | (1,196) |
Proved Reserves, Ending balance | 34,142 | 31,344 | 32,517 |
Developed Reserves | 14,942 | 15,182 | 16,335 |
Proved Undeveloped Reserves | 19,200 | 16,162 | 16,182 |
Natural Gas in MMcf [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | MMcf | 103,148 | 132,265 | 152,489 |
Production | MMcf | (11,900) | (14,449) | (16,664) |
Purchases in place | MMcf | 327 | 1,265 | |
Discoveries and extensions | MMcf | 58,129 | 28,822 | 29,012 |
Sales of reserves in place | MMcf | (8,250) | (35,857) | (10,912) |
Revisions of previous quantity estimates and other | MMcf | 14,296 | (7,960) | (22,925) |
Proved Reserves, Ending balance | MMcf | 155,423 | 103,148 | 132,265 |
Developed Reserves | MMcf | 71,752 | 63,334 | 92,640 |
Proved Undeveloped Reserves | MMcf | 83,671 | 39,814 | 39,625 |
Natural Gas Liquids [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 8,388 | 5,735 | 5,695 |
Production | (678) | (537) | (398) |
Discoveries and extensions | 7,763 | 4,119 | 1,969 |
Sales of reserves in place | (748) | (949) | |
Revisions of previous quantity estimates and other | 3,712 | 20 | (1,531) |
Proved Reserves, Ending balance | 18,437 | 8,388 | 5,735 |
Developed Reserves | 6,958 | 4,028 | 3,138 |
Proved Undeveloped Reserves | 11,479 | 4,360 | 2,597 |
Barrels of Oil Equivalent [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 56,923 | 60,296 | 51,731 |
Production | (6,865) | (6,715) | (6,072) |
Purchases in place | 665 | 1,673 | |
Discoveries and extensions | 30,432 | 22,204 | 21,345 |
Sales of reserves in place | (8,667) | (13,223) | (1,832) |
Revisions of previous quantity estimates and other | 6,660 | (6,304) | (6,549) |
Proved Reserves, Ending balance | 78,483 | 56,923 | 60,296 |
Developed Reserves | 33,859 | 29,765 | 34,913 |
Proved Undeveloped Reserves | 44,624 | 27,158 | 25,383 |
Supplemental Oil And Natural 68
Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Capitalized costs: | ||
Proved properties | $ 1,345,482 | $ 1,417,785 |
Unproved properties | 127,551 | 84,620 |
Total | 1,473,033 | 1,502,405 |
Accumulated depreciation, depletion, amortization and impairment | (947,091) | (816,229) |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | $ 525,942 | $ 686,176 |
Supplemental Oil And Natural 69
Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | ||||
Property acquisition costs, unproved properties | $ 74,475 | $ 33,787 | $ 34,884 | |
Property acquisition costs, proved properties | [1] | 2,899 | 7,462 | 35,954 |
Costs incurred, exploration | 34,275 | 59,201 | 55,300 | |
Costs incurred, development | [2] | 146,299 | 341,594 | 242,912 |
Costs Incurred, Total | 257,948 | 442,044 | 369,050 | |
Costs Incurred, Additional Information [Abstract] | ||||
Development Costs Incurred As Asset Retirement Obligations | (300) | 4,500 | $ 1,400 | |
Unproved Leasehold Acquisition Cost | $ 46,600 | |||
Stone [Member] | ||||
Costs Incurred, Additional Information [Abstract] | ||||
Total cost of Business Acquisition | $ 30,600 | |||
[1] | Property acquisition costs in unproved properties in 2015 include the undeveloped leasehold portion of the Kingfisher acquisition of $46.6 million. Property acquisition costs in the proved properties in 2013 include primarily the proved portion of the Stone acquisition of $30.6 million. | |||
[2] | Includes asset retirement additions (revisions) of ($0.3) million, $4.5 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively. |
Supplemental Oil And Natural 70
Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($)$ / Mcf$ / bbl | Dec. 31, 2014USD ($)$ / Mcf$ / bbl | Dec. 31, 2013USD ($)$ / Mcf$ / bbl | Dec. 31, 2012USD ($) | |
Components of the standardized measure of discounted future net cash flows | ||||
Future cash flows | $ 2,395,128 | $ 3,737,412 | $ 3,959,938 | |
Future production costs | (860,600) | (991,149) | (1,146,123) | |
Future development costs | $ (403,953) | $ (450,659) | $ (474,191) | |
Future taxes on income | ||||
Future net cash flows | $ 1,130,575 | $ 2,295,604 | $ 2,339,624 | |
Discount to present value at 10 percent per annum | (500,979) | (877,558) | (933,350) | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | $ 629,596 | $ 1,418,046 | $ 1,406,274 | $ 914,421 |
Base price for crude oil, per Bbl, in the above computations was | $ / bbl | 50.28 | 94.99 | 96.78 | |
Base price for natural gas, per Mcf, in the above computations was | $ / Mcf | 2.58 | 4.35 | 3.67 |
Supplemental Oil And Natural 71
Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of changes in standardized measure of discounted future net cash flows | |||
Balance at beginning of year | $ 1,418,046 | $ 1,406,274 | $ 914,421 |
Sales of oil and natural gas, net of production costs | (147,906) | (320,130) | (263,952) |
Changes in sales and transfer prices, net of production costs | (823,073) | (153,770) | 69,609 |
Revisions of previous quantity estimates | 53,101 | (477,377) | (150,634) |
Purchases of reserves-in-place | 21,633 | 93,877 | |
Sales of reserves-in-place | (244,251) | (107,414) | (11,193) |
Current year discoveries and extensions | 260,078 | 701,820 | 621,832 |
Changes in estimated future development costs | 4,376 | 2,591 | 11,623 |
Development costs incurred during the year | 42,420 | 161,357 | 75,973 |
Accretion of discount | $ 141,805 | $ 140,627 | $ 91,442 |
Net change in income taxes | |||
Change in production rate (timing) and other | $ (75,000) | $ 42,435 | $ (46,724) |
Net change | (788,450) | 11,772 | 491,853 |
Balance at end of year | $ 629,596 | $ 1,418,046 | $ 1,406,274 |