Document And Entity Information
Document And Entity Information | 12 Months Ended |
Dec. 31, 2016USD ($)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, 2016 |
Amendment Flag | false |
Document Fiscal Year Focus | 2,016 |
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, 2016 | Dec. 31, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 7,185 | $ 8,869 |
Short-term restricted cash | 433 | 105 |
Accounts receivable, net of allowance of $889 and $1,402, respectively | 37,611 | 27,111 |
Other receivables | 8,061 | 18,526 |
Receivables due from affiliate | 8,883 | 1,053 |
Prepaid expenses and other current assets | 3,986 | 4,774 |
Derivative financial instruments | 83 | 62,631 |
Total current assets | 66,242 | 123,069 |
PROPERTY AND EQUIPMENT | ||
Oil and natural gas properties, successful efforts method, net | 712,162 | 525,942 |
Other property and equipment, net | 9,731 | 11,097 |
Total property and equipment, net | 721,893 | 537,039 |
OTHER ASSETS | ||
Investment in LLC - cost | 9,000 | 9,000 |
Deferred financing costs, net | 3,029 | 1,199 |
Notes receivable due from affiliate | 9,987 | 9,213 |
Deposits and other long-term assets | 2,977 | 1,370 |
Derivative financial instruments | 723 | 41,635 |
Total other assets | 25,716 | 62,417 |
TOTAL ASSETS | 813,851 | 722,525 |
CURRENT LIABILITIES | ||
Accounts payable and accrued liabilities | 84,234 | 82,621 |
Advances from non-operators | 4,058 | 1,381 |
Advances from related party | 42,528 | |
Asset retirement obligations | 376 | 729 |
Derivative financial instruments | 21,207 | |
Total current liabilities | 152,403 | 84,731 |
LONG-TERM LIABILITIES | ||
Asset retirement obligations, net of current portion | 61,128 | 60,491 |
Long-term debt, net | 529,905 | 717,775 |
Notes payable to founder | 26,957 | 25,748 |
Derivative financial instruments | 4,482 | |
Other long-term liabilities | 6,870 | 10,829 |
Total long-term liabilities | 629,342 | 814,843 |
TOTAL LIABILITIES | 781,745 | 899,574 |
Commitments and Contingencies (Note 12) | ||
PARTNERS' CAPITAL (DEFICIT) | 32,106 | (177,049) |
TOTAL LIABILITIES AND PARTNERS' CAPITAL (DEFICIT) | $ 813,851 | $ 722,525 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Consolidated Balance Sheets [Abstract] | ||
Allowance for doubtful accounts | $ 889 | $ 1,402 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
OPERATING REVENUES AND OTHER | |||
Oil | $ 163,677 | $ 199,799 | $ 347,842 |
Natural gas | 30,953 | 30,621 | 65,002 |
Natural gas liquids | 15,663 | 10,864 | 18,281 |
Other revenues | 415 | 682 | 1,003 |
Total operating revenues | 210,708 | 241,966 | 432,128 |
Gain on sale of assets | 3,542 | 67,781 | 87,520 |
Gain (loss) on derivative contracts | (40,460) | 124,141 | 96,559 |
Total operating revenues and other | 173,790 | 433,888 | 616,207 |
OPERATING EXPENSES | |||
Lease and plant operating expense | 56,893 | 67,706 | 64,686 |
Marketing and transportation expense | 13,326 | 4,030 | 9,134 |
Production and ad valorem taxes | 10,750 | 15,131 | 28,214 |
Workover expense | 4,714 | 6,511 | 8,961 |
Exploration expense | 24,777 | 42,718 | 61,912 |
Depreciation, depletion, and amortization expense | 92,901 | 143,969 | 141,804 |
Impairment expense | 16,306 | 176,774 | 74,927 |
Accretion expense | 2,174 | 2,076 | 2,198 |
General and administrative expense | 41,758 | 44,454 | 69,198 |
Total operating expenses | 263,599 | 503,369 | 461,034 |
INCOME (LOSS) FROM OPERATIONS | (89,809) | (69,481) | 155,173 |
OTHER INCOME (EXPENSE) | |||
Interest expense | (60,884) | (62,473) | (55,812) |
Interest income | 894 | 723 | 15 |
Loss on extinguishment of debt | (18,151) | ||
Total other income (expense) | (78,141) | (61,750) | (55,797) |
INCOME (LOSS) BEFORE STATE INCOME TAXES | (167,950) | (131,231) | 99,376 |
Provision for state income taxes | (29) | 562 | 176 |
NET INCOME (LOSS) | $ (167,921) | $ (131,793) | $ 99,200 |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Partners' Capital (Deficit) $ in Thousands | USD ($) |
Balance, Beginning 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 Changes In Partners' Capital (Deficit) [Abstract] | |
Contributions | 377,076 |
Net income (loss) | (167,921) |
Balance, Ending at Dec. 31, 2016 | $ 32,106 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ (167,921) | $ (131,793) | $ 99,200 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, and amortization expense | 92,901 | 143,969 | 141,804 |
Impairment expense | 16,306 | 176,774 | 74,927 |
Accretion expense | 2,174 | 2,076 | 2,198 |
Amortization of deferred finacing costs | 3,905 | 3,392 | 2,885 |
Amortization of debt discount | 468 | 510 | 510 |
Dry hole expense | 419 | 22,708 | 30,294 |
Expired leases | 11,158 | 6,526 | 4,319 |
(Gain) loss on derivative contracts | 40,460 | (124,141) | (96,559) |
Settlements of derivative contracts | 88,689 | 106,949 | 9,493 |
Loss on extinguishment of debt | 18,151 | ||
Interest converted into debt | 1,209 | 1,208 | 1,209 |
Interest on notes receivable due from affiliate | (774) | (713) | |
Gain on sale of assets | (3,542) | (67,781) | (87,520) |
Changes in assets and liabilities: | |||
Restricted cash unrelated to property divestiture | (328) | (106) | |
Accounts receivable | (10,500) | 16,470 | (95) |
Other receivables | 10,465 | (10,288) | (5,686) |
Receivables due from affiliate | 45 | (1,725) | |
Prepaid expenses and other non-current assets | (819) | (2,269) | 7,251 |
Advances from related party | 42,528 | ||
Settlement of asset retirement obligation | (2,125) | (1,794) | (3,942) |
Accounts payable, accrued liabilities, and other liabilities | (11,493) | 3,900 | 4,702 |
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES | 131,376 | 143,978 | 184,884 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Capital expenditures for property and equipment | (214,061) | (223,604) | (366,090) |
Acquisitions | (11,527) | (48,202) | (18,110) |
Proceeds from sale of property | 1,290 | 141,404 | 177,476 |
Proceeds from property divestiture classified as restricted cash | 41,590 | ||
Investment in restricted cash related to property divestitures | 24,587 | (24,587) | |
NET CASH USED IN INVESTING ACTIVITIES | (224,298) | (105,815) | (189,721) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Proceeds from long-term debt | 222,557 | 252,500 | 169,500 |
Repayments of long-term debt | (333,935) | (295,020) | (169,270) |
Repayments of senior secured term loan | (127,708) | ||
Repurchase of senior notes due 2018 | (459,391) | ||
Proceeds from issuance of senior notes due 2024 | 500,000 | ||
Additions to deferred financing costs | (13,747) | (4,313) | (42) |
Capital distributions | (3,810) | (539) | |
Capital contributions | 303,462 | 20,000 | |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES | 91,238 | (30,643) | (351) |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1,684) | 7,520 | (5,188) |
CASH AND CASH EQUIVALENTS, beginning of period | 8,869 | 1,349 | 6,537 |
CASH AND CASH EQUIVALENTS, end of period | $ 7,185 | $ 8,869 | $ 1,349 |
Nature Of Operations
Nature Of Operations | 12 Months Ended |
Dec. 31, 2016 | |
Nature Of Operations [Abstract] | |
Nature Of Operations | NOTE 1 — NATURE OF OPERATIONS Nature of Operations . Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin referred to as the STACK. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. Our operations also include other oil and natural gas interests in Texas, Louisiana and Florida. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
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’ capital (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 acquired 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, 2016 , the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or unclaimed property for pooling orders in Oklahoma. Accounts Receivable . Our receivables arise primarily 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. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable consisted of the following: As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889) (1,402) Total accounts receivable, net $ 37,611 $ 27,111 See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, 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 statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets. 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, delay rentals, 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. See Note 5 for further details. 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 $ 16.1 million, $ 172.0 million and $ 72.9 million for the years ended December 31, 2016 , 2015 and 2014, 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 statements of operations. For the years ended December 31, 2016 , 2015 and 2014, impairment expense of unproved properties was $ 0.2 million, $ 4.8 million, and $ 2.0 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, 2016 , 201 5 and 201 4, 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, 2016 , 2015 and 2014 related to oil and natural gas properties was $ 90.0 million, $140.9 million, and $139.0 million, respectively. Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. 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, 2016 , 2015 and 2014 was $ 2.9 million, $3.0 million, and $2.8 million respectively. Investments . 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 and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. Alta Mesa is a part owner of AEM with an ownership interest of less than 10% . AEM markets 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 collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13. 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 6 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 gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. 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. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016. The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) 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, 2016 and 2015 . 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, 2016 , 2015 or 2014 . The Company’s tax returns for the years ended December 31, 2013 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. 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 senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine 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. In December 2016, we issued $500 million in aggregate principal amount of our 7.875% senior unsecured notes due 2024 (the “2024 Notes”). We have estimated the fair value of the 2024 Notes payable at $520 million on December 31, 2016 . Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments and details related to the 2024 Notes, refer to Note 6 – Fair Value Disclosures and Note 10 - Long-Term Debt, Net. 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, measurement and disclosure 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 deferred 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. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements. 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 does not plan to adopt the standard early. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases . In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments , which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows. In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control . This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows. In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 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. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | NOTE 3 – SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Year Ended December 31, 2016 2015 2014 (in thousands) Supplemental cash flow information: Cash paid for interest $ 74,694 $ 56,579 $ 51,219 Cash paid (received) for state income taxes, net of refunds 285 751 (123) Non-cash investing and financing activities: Change in asset retirement obligations 2,719 487 2,643 Asset retirement obligations assumed, purchased properties — — 3,002 Change in accruals or liabilities for capital expenditures 12,375 (34,160) 23,858 Divestiture of oil and gas properties — — (34,000) Acquisition of property and land — 2,473 — Contribution of interests in oil and gas properties 65,740 — — Contribution receivable 7,875 — — |
Significant Acquisitions And Di
Significant Acquisitions And Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Significant Acquisitions And Divestitures [Abstract] | |
Significant Acquisitions And Divestitures | NOTE 4 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES 201 6 Activity During 2016, we acquired approximately $10.6 million of oil and gas properties in Oklahoma which were primarily related to unevaluated leasehold. On December 31, 2016, our Class B partner, High Mesa , Inc. (“High Mesa”) purchased from BCE and contributed interests in 24 pro ducing wells (the “Contributed Wells”) drilled under the joint development agreement to us. The Company accounted for the Contributed Wells as a business combination and therefore, recorded the contribution at their estimated contribution date fair value. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end. The unaudited pro forma combined financial results, had the contribution of the Contributed Wells occurred at January 1, 2016, are provided below. The Contributed Wells came online during 2016, therefore, no unaudited pro forma combined results are shown for the beginning of the comparable prior year. Total operating revenues and other Net loss (in thousands) (unaudited) Pro forma results for the combined entity for the year ended December 31, 2016 $ 199,982 $ (157,230) This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the contribution had been completed as of the beginning of the period, nor are they necessarily indicative of future results. 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 $125.0 million subject to certain adjustments, consisting of $118.0 million (the “Base Purchase Price”), and additional contingent payments of approximately $7.0 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 adjustmen ts, and recognized a gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving 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 senior secured revolving 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 D ivestiture”). 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 $173.0 million, subsequently adjusted to approximately $171.0 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 D ivestiture 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 pre-tax income in the first qua rter of 2014, prior to its sale . 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. |
Property And Equipment
Property And Equipment | 12 Months Ended |
Dec. 31, 2016 | |
Property And Equipment [Abstract] | |
Property And Equipment | NOTE 5 — PROPERTY AND EQUIPMENT Property and equipment consists of the following: December 31, December 31, 2016 2015 (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 116,311 $ 127,551 Accumulated impairment (65) (2,684) Unproved properties, net 116,246 124,867 Proved oil and natural gas properties 1,611,249 1,345,482 Accumulated depreciation, depletion, amortization and impairment (1,015,333) (944,407) Proved oil and natural gas properties, net 595,916 401,075 TOTAL OIL AND NATURAL GAS PROPERTIES, net 712,162 525,942 OTHER PROPERTY AND EQUIPMENT Land 4,730 3,868 Office furniture and equipment, vehicles 19,446 18,794 Accumulated depreciation (14,445) (11,565) OTHER PROPERTY AND EQUIPMENT, net 9,731 11,097 TOTAL PROPERTY AND EQUIPMENT, net $ 721,893 $ 537,039 Capitalized Exploratory Well C osts The following table reflects the net changes in capitalized exploratory well costs during 2016 , 201 5 , and 201 4 . The table does not include amounts that were capitalized and either subsequently expensed within the same year. Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 6,006 $ 13,301 $ 20,317 Additions to capitalized well costs pending determination of proved reserves 3,736 4,364 15,870 Reclassifications to proved properties (7,484) (8,583) (6,593) Capitalized exploratory well costs charged to expense (169) (3,076) (16,293) Balance, end of year $ 2,089 $ 6,006 $ 13,301 The ending balance in capitalized exploratory well costs includes the costs of five wells primarily in three prospects that were capitalized for periods greater than one year at December 31, 2016 . We have capitali zed $0.7 million and $3.0 million of exploratory well costs covering periods greater than one year at December 31, 2016 and 201 5 . We continue to assess and evaluate these projects. |
Fair Value Disclosures
Fair Value Disclosures | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures | NOTE 6 — 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. W e 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 $ 33.9 million were written down to their fair value of $ 17.6 million, resulting in an impairment charge of $ 16.3 million for the year ended December 31, 2016 . 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. 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. 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 $ 1.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2016 . 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 . The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 201 5 , 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, 2016: Financial Assets: Derivative contracts for oil and natural gas — $ 15,773 — $ 15,773 Financial Liabilities: Derivative contracts for oil and natural gas — $ 40,656 — $ 40,656 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 The amounts above are presented on a gross basis. P resentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Financial Instruments [Abstract] | |
Derivative Financial Instruments | NOTE 7 — 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 the benchmark index price and the specific locational index 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 senior secured revolving credit facility described in Note 10 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving 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 . A ccordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement s 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 6 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815: December 31, 2016 Net Fair Gross Gross amounts Value of Assets 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 $ 3,296 $ (3,213) $ 83 Derivative financial instruments, long-term assets 12,477 (11,754) 723 Total $ 15,773 $ (14,967) $ 806 Net Fair Gross Gross amounts Value of Liabilities 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 $ 24,420 $ (3,213) $ 21,207 Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482 Total $ 40,656 $ (14,967) $ 25,689 December 31, 2015 Net Fair Gross Gross amounts Value of Assets 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 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) $ — The following table summarizes the effect of our derivative instruments in the consolidated statements of operations: Derivatives not designated as hedging Year Ended December 31, instruments under ASC 815 2016 2015 2014 (in thousands) Gain (loss) on derivative contracts Oil commodity contracts $ (36,572) $ 113,295 $ 82,510 Natural gas commodity contracts (2,410) 10,712 14,049 Natural gas liquids commodity contracts (1,478) 134 — Total gain (loss) on derivative contracts $ (40,460) $ 124,141 $ 96,559 Other receivables include $7.8 million and $17.5 million of derivative positions settled, but not yet received as of December 31, 2016 and 201 5 , 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 senior secured revolving 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, 2016 : OIL DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract in Bbls Average High Low 2017 Price Swap Contracts 1,460,000 $ 46.93 $ 48.43 $ 45.00 Collar Contracts Short Call Options 2,075,000 60.46 85.00 54.40 Long Put Options 1,527,500 48.39 50.00 47.00 Short Put Options 1,527,500 37.19 40.00 35.00 2018 Collar Contracts Short Call Options 1,825,000 60.64 60.90 60.50 Long Put Options 1,825,000 50.00 50.00 50.00 Short Put Options 1,825,000 40.00 40.00 40.00 2019 Collar Contracts Short Call Options 1,241,000 62.90 63.00 62.75 Long Put Options 1,241,000 50.00 50.00 50.00 Short Put Options 1,241,000 37.50 37.50 37.50 We had the following open derivative contracts for natural gas at December 31, 2016 : NATURAL GAS DERIVATIVE CONTRACTS Volume in Weighted Range Period and Type of Contract MMBtu Average High Low 2017 Price Swap Contracts 450,000 $ 2.47 $ 2.47 $ 2.47 Collar Contracts Short Call Options 10,220,000 3.68 3.94 3.56 Long Put Options 9,320,000 3.09 3.30 3.00 Long Call Options 1,125,000 3.44 3.56 3.25 Short Put Options 9,320,000 2.56 2.70 2.50 2018 Collar Contracts Short Call Options 6,132,000 5.34 5.53 4.00 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, 2016 : NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract in Gal Average High Low 2017 Price Swap Contracts 5,371,800 $ 0.46 $ 0.47 $ 0.45 We had the following open financial basis swap contracts for natural gas at December 31, 2016 : BASIS SWAP DERIVATIVE CONTRACTS Weighted Average Spread Volume in MMBtu Reference Price 1 (1) Reference Price 2 (1) Period ($ per MMBtu) 12,470,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan’17 — Dec ’17 $ (0.24) 5,910,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’18 — Oct’18 (0.27) (1) Represents short swaps that fix the basis differentials between T ex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | N OTE 8 — ASSET RETIREMENT OBLIGATIONS A summary of the changes in our asset retirement obligations is included in the table below: Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 61,220 $ 62,872 $ 56,023 Liabilities incurred 1,438 1,988 1,129 Liabilities assumed with acquired producing properties — — 3,002 Liabilities settled (2,125) (1,794) (3,942) Liabilities transferred in sales of properties (3,036) (3,149) (1,886) Revisions to estimates 1,833 (773) 6,348 Accretion expense 2,174 2,076 2,198 Balance, end of year 61,504 61,220 62,872 Less: Current portion 376 729 1,136 Long-term portion $ 61,128 $ 60,491 $ 61,736 The total revisions included $1.3 million related to additions to property, plant and equipment for the year ended December 31, 2016 . Total revisions included $1.5 million related to reductions and $2.9 million related to additions to property, plant and equipment for the years ended December 31, 2015 and 201 4 , respectively. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | NOTE 9 — RELATED PARTY TRANSACTIONS We have notes payable to our founder which bear interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 201 5 , respectively. See Note 10 for further information. Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions during the years ended December 31, 2016 an d 2015 and received $516,500 of capital distributions fr om us during the year ended December 31, 201 4 , respectively. Da vid Murrell, our Vice President of 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, 2016 , 201 5 and 201 4 were approximately $146,000 , $133,000 and $150,000 . The contract may be terminated by either party without penalty upon 30 days’ notice. David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000 , $275,000 and $450,000 for the years ended December 31, 2016 , 201 5 and 201 4 . 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 of Land and Business Development, David Murrell, received total compensation of $180,000 , $146,000 and $260,000 for the years ended December 31, 2016 , 201 5 and 201 4 . Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. On January 13, 2016, o ur wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joi nt development agreement (the “joint d evelop ment a gr eement”) , with BCE-STACK Development LLC (“BCE”) , a fund advised by Bayou City Energy Management LLC (“Bayou City”) , to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage . As described in Note 16, William W. McMullen and Mark Stoner , partners at Bayou City , were appointed to the board of managers of Alta Mesa Holdings GP, LLC, our general partner during the third quarter of 2016. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each . The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 pro ducing wells drilled under the joint development agreement to us. See Notes 4 and 16 for further details. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each . As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 wells to be drilled under the joint development agreement. Under the j oint development agreement , as amended on December 31, 2016, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding the aggregate limit of $64 million in any tranche . In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE i nterest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well. The approximate dollar value of the amount involved in this transaction or Messrs. McMullen or Stoner ’s interests in the transaction depends on a number of factors outside their control and is not known at this time. As of December 31 , 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheet s , which represents net advances from BCE for their working interest share of the drilling and d evelopment cost as part of the joint d evelopment a greement. During the year ended December 31, 2016, High Mesa contributed $311.3 million to us, of which $7.9 million is included in receivables due from affiliate at December 31, 2016 and the amount was collected subsequent to year-end. During the year ended December 31, 2015, High Mesa contributed $20 million to us. For additional information, see Note 1 6 - Partners’ Capital ( Deficit ) . As of December 31, 2016 and 2015, approximately $0.9 million and $1. 1 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from affiliates on the consolidated balance sheets. On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate , Northwest Gas Processing, LLC (“NWGP”), which is a subsidiary of High Mesa . We recorded $25.5 million in other receivable s and $8.5 million in long- term note s 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 in full . The $8.5 million long-term 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, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the no te receivable from our affiliate amounted to $0.8 million and $0.7 million during the year s ended December 31, 2016 and 2015, respectively . Such amounts have been a dded to the balance of the note receivable. On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million. We are party to a services agreement dated January 1, 2016 with NWGP. Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014. During the year ended December 31, 2016, NWGP was billed for management services provided in the amount of approximately $0.1 million. On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended and restated on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM for gathering and processing. Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities. Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed gathering fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system. Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed. Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant. The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million. The plant commenced operations in the second quarter of 2016. These fees are recorded as marketing and transportation expense in the consolidated statement s of operations. As of December 31, 2016, we accrued approximately $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant. Subsequent to year-end, Oklahoma Energy entered into an agreement with KFM whereby the Company made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/day for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018. |
Long Term Debt, Net
Long Term Debt, Net | 12 Months Ended |
Dec. 31, 2016 | |
Long Term Debt, Net [Abstract] | |
Long Term Debt, Net | NOTE 10 — LONG TERM DEBT, NET Long-term debt , net consists of the following: December 31, December 31, 2016 2015 (in thousands) Senior secured revolving credit facility $ 40,622 $ 152,000 Senior secured term loan — 125,000 9.625% senior unsecured notes due 2018 — 448,598 7.875% senior unsecured notes due 2024 500,000 — Unamortized deferred financing costs (10,717) (7,823) Total long-term debt, net $ 529,905 $ 717,775 Notes payable to founder $ 26,957 $ 25,748 Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative a gent, and a syndicate of banks . The amended and restated credit facility, among other things, (i) reaffirms the existing borrowing base amount of $300 million through the new redetermination of the borrowing base, (ii) increases the maximum credit amount from $500 million to $750 million, subject to borrowing base limit (iii) extends the maturity of the credit facility to November 10, 2020 with the completion of a refinancing of the 2018 Notes (as described below), (iv) increases our pricing grid by 25 to 50 basis points (depending on our leverage ratio), and (v) increases our mortgage requirement from 85% of the value of our proven reserves to 90% . Our borrowing base was reduced to $287.5 million from $300 million following the issuance of the 2024 Notes, as described below. As of December 31, 2016 , the Company had $40.6 million outstanding with $239.3 million of available borrowing capacity under the credit facility . The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. 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. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00 , depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The r eference r ate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1% , plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 4.00 % as of December 31, 2016 and 2.89% as of December 31, 2015 . The letters of credit outstanding as of December 31, 2016 and 201 5 were $7.6 million and $65,000 , respectively . The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect. As of December 31, 2016, the covenants of the Company’s credit facility prohibit it from making any distributions. The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0, commencing with the fiscal quarter ending December 31, 2016. As of December 31, 2016 , we were in compliance with all covenants under the credit facility . 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. I n October 2016, High Mesa contributed $300 million to us from the investment by Bayou City, as described in Note 16. We used a portion of the contribution to repay all amounts outstanding under the term loan f acility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date . For the year ended December 31, 2016, the Company recognized a loss of $4.7 million, which included unamortized deferred financing cost write-offs of $2.0 million, and are reflected in loss on extinguishment of debt in the consolidated statements of operations. Senior Unsecured Notes. On December 8, 2016, the Company and our wholly owned subsidiary Alta Mesa Finances Services Corp. (collectively, the “Issuers”) issued $500.0 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 at par, the 2024 Notes, which resulted in aggregate net proceeds to the Company of $491.3 million, after deducting commission offering expenses. The Company used the proceeds from the issuance of the 2024 Notes to fund the repurchase of the 2018 Notes pursuant to a tender offer and the redemption of any of the 2018 Notes that remained outstanding after consummation of the tender offer. The remainder of the proceeds were used to repay a portion of our indebtedness under our credit facility. The 2024 Notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 2024 Notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, the Company may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 Notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the 2024 Notes may require the Company to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, the Company may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption. The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of the Company’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Company’s credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of the Company’s subsidiaries that do not guarantee the 2024 Notes. The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change the Company’s line of business. As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions. Under the term s of the indenture for the 2024 N otes, 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. Repurchase and Redemption of 9.625% Senior Unsecured Notes due 2018 On November 30, 2016 we commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016 and on December 8, 2016, we made payment of the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, on December 8, 2016, the Company caused to be deposited, with Wells Fargo Bank, National Association, the Trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the 2018 Notes. The Satisfaction and Discharge, among other things, discharged the indenture and the obligations of the Company thereunder. As a result of the tender offer and redemption, the Company repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016. For the year ended December 31, 2016, the Company recognized a loss of $13.5 million, which includes unamortized discount write-off of $0.9 million, unamortized deferred financing costs write- off of $3.2 million, tender premium of $2.5 million and accrued interest of $6.9 million, which is all reflected in loss on extinguishment of debt in the consolidated statements of operations. Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $ 27.0 million and $ 25.7 million at December 31, 2016 and 2015 , 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 of High Mesa . 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 16, 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 partnership agreement, as amended, 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, 2016, 2015 and 20 14 . Such amounts have been added to the balance of the founder notes. Deferred financing costs. As of December 31, 2016 , the Company had $13.7 million of deferred financing costs related to the credit facility and the 2024 Notes , which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.7 million related to the 2024 Notes are included in long-term debt on the consolidated balance sheet s as of December 31, 2016 . Deferred financing costs of $3.0 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at December 31, 2016 . Amortization of deferred financing costs recorded for the years ended December 31, 201 6 , 201 5 and 201 4 was $3.9 million, $3.4 million and $2.9 million, respectively. These costs are included in interest expense on the consolidated statement s of operations. The loss on extinguishment of debt in the consolidated statements of operations included unamortized deferred financing costs write- offs of $5.1 million related to the repayment of the term loan facility and the repurchase and redemption of the 2018 Notes for the year ended December 31, 2016. No deferred financing costs were written off during the years ended December 31, 2015 and 2014. Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs , at December 31, 2016 are as follows ( in thousands ): Year ending December 31, 2017 $ — 2018 — 2019 — 2020 40,622 2021 26,957 Thereafter 500,000 $ 567,579 The credit facility and the 2024 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, 2016 , we were in compliance with the covenants of our debt agreements. |
Accounts Payable And Accrued Li
Accounts Payable And Accrued Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Accounts Payable And Accrued Liabilities [Abstract] | |
Accounts Payable And Accrued Liabilities | NOTE 11 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES The following provides the detail of accounts payable and accrued liabilities: December 31, December 31, 2016 2015 (in thousands) Capital expenditures $ 15,155 $ 10,780 Revenues and royalties payable 12,187 5,082 Operating expenses/taxes 17,499 17,955 Interest 2,627 9,919 Compensation 5,302 5,434 Derivatives settlement payable 1,126 11,149 Other 1,164 1,201 Total accrued liabilities 55,060 61,520 Accounts payable 29,174 21,101 Accounts payable and accrued liabilities $ 84,234 $ 82,621 |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | NOTE 12 — COMMITMENTS AND CONTINGENCIES Contingencies 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, 2016 . 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 remedia tion costs, if any. Management revised the estimated liability for groundwater contamination in Florida based on our reassessment of our remediation costs and plan, which is pending approval by the State of Florida. As of December 31, 2016, our revised estimated remediation liability was approximately $0.1 million. As of December 31, 2015, we had estimated a liability of $ 1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 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. Litigation : On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Exte x, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary , which we acquired in 2010 ), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claim they are owners of land upon which oil f ield waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of December 31, 2016 , we have accrued approximately $4.0 million ( $0.8 million in current liabilities and $3.2 million in other long-term liabilities) in connection with the settlement. The settlement requires payment over the term of six years. 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. 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 can be construed in accordance with the meaning of the term “change in control event” ) 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 201 6 , we granted 360,000 PARs and terminated 26,200 PARs with a SIDV of $40 , resulting in 575,300 PAR s issued at a weighted average value of $36.78 . Subsequent to year end, 306,300 PARs were granted with a SIDV of $40 and 500 PARs with a SIDV of $40 were terminated, resulting in 881,100 PARs issued at a weighted average value of $37.90 . 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, 2016 or 201 5 . 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 . Total r ent expense, net of sublease income, including office space and compressors, for the years ended December 31, 2016 , 201 5 , and 201 4 amounted to approximately $5.7 million, $4.8 million, and $5.7 million, respectively. At December 31, 2016 , the future minimum base rentals for non-cancelable operating leases are as follows : Amount (1) Year Ending December 31, (in thousands) 2017 $ 3,956 2018 1,453 2019 1,545 2020 1,593 2021 1,620 Thereafter 1,207 $ 11,374 (1) These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019. Additionally, at December 31, 2016 , the Company had posted bonds in the aggregate amount of $24.0 million, primarily to cover future abandonment costs. |
Significant Concentrations
Significant Concentrations | 12 Months Ended |
Dec. 31, 2016 | |
Significant Concentrations [Abstract] | |
Significant Concentrations | NOTE 13 — SIGNIFICANT CONCENTRATIONS We sell our oil and natural gas primarily through a marketing contract with AEM. AEM is our marketing agent and acts on our behalf to market our oil and natural gas to any purchasers identified by AEM. We are a part owner of AEM with an ownership interest of less than 10% . AEM markets 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 in to account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. The fee charged to us by AEM for marketing is recorded as a marketing and transportation expense. Our marketing agreement with AEM commenced in June 2013. This agreement will terminate in June 2018, with additional provisions for extensions beyond five years and for early termination. AEM marketed majority of our production from operated fields between 2014 and 2016. Production from non-operated fields was marketed on our behalf by the operators of those properties. For the year ended December 31, 2016 , revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities. For the year ended December 31, 2015 , revenues marketed by AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities. For the year ended December 31, 2014, revenues marketed by AEM were $220.9 million , or 51.1% of total revenue excluding hedging activities , and b ased on revenues excluding hedging activities , one major customer, Murphy Oil Corporation accounted for 10% or more of those revenues, with revenues excluding hedges of $61.2 million. We believe that the loss of any of our significant customers, or of our marketing agent 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, 2016 | |
401(k) Savings Plan [Abstract] | |
401(k) Savings Plan | NOTE 1 4 — 401(k) SAVINGS PLAN Employees of Alta Mesa Services , LP, our wholly owned subsidiary (“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 100% of an employee’s salary deferral contribution up to a maximum of 5% of an employee’s salary , effective January 1, 2016 . Matching contributions to the plan were approximately $1,122,000 , $710,000 , and $ 683,000 for the years ended December 31, 2016 , 201 5 and 201 4 , respectively. |
Significant Risks And Uncertain
Significant Risks And Uncertainties | 12 Months Ended |
Dec. 31, 2016 | |
Significant Risks And Uncertainties [Abstract] | |
Significant Risks And Uncertainties | NOTE 1 5 — 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 have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted . 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. 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 7 . |
Partners' Capital (Deficit)
Partners' Capital (Deficit) | 12 Months Ended |
Dec. 31, 2016 | |
Partners' Capital (Deficit) [Abstract] | |
Partners' Capital (Deficit) | NOTE 1 6 — 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 M anagement LP in High Mesa. Our board of d irectors includes one me mber nominated by Highbridge, f ive members nominated by the Class A partners and two members nominated by Bayou City . 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 m ay not be removed except for 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. On August 31, 2016, our Class B partner completed the sale of preferred stock to BCE-MESA Holdings LLC (“BCE-MESA”), a fund managed by Bayou City. In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Amended Partnership Agreement”). The Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner by the Class A partners of their remaining Class A units upon an initial public offering. In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of mana gers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen , the founder and managing partner of Bayou City, was appointed to the board of managers of our General Partner. On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City. In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner. Contribution, Distribution, and Income Allocation: All distributions under the Amended 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 t he terms of our credit facility and our senior notes. Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the Amended Partnership Agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. 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. In connection with the final sale of preferred stock to Bayou City, our Class B partner contributed $300 million from the Bayou City investment to us. We used a portion of the contribution to repay all amounts outstanding under the t erm loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date. The remaining funds are available to be used for general corporate purposes. As described in Notes 4 and 9, High Mesa purchased from BCE and contributed interests in 24 pro ducing wells drilled under the joint development agreement to us on December 31, 2016. High Mesa’s equity contribution was recorded at the contribution date fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected subsequent to year end. 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. We made no distributions for the year ended December 31, 2016. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partne r. For the year ended December 31, 2014, we made distributions of approximately $0.5 million to our founder as discussed in Note 9 and the partners’ share of taxes related to the sale of AME as discussed in Note 4. |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2016 | |
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 and our credit facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. The 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 and are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company. |
Supplemental Quarterly Informat
Supplemental Quarterly Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Information [Abstract] | |
Supplemental Quarterly Information | NOTE 1 8 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) Results of operations by quarter for the year ended December 31, 2016 were: Quarter Ended 2016 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 38,167 $ 53,823 $ 54,532 $ 64,186 Loss from operations (1)(2) (7,967) (52,686) (8,620) (20,536) Net loss $ (24,157) $ (70,327) $ (26,567) $ (46,870) (1) Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively. (2) Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016. 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) Total operating revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (3)(4)(5) (95,077) (23,881) 110,069 (60,592) Net income (loss) $ (109,211) $ (39,509) $ 93,079 $ (76,152) (3) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (4) 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 . (5) Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 201 5 . |
Supplemental Oil And Natural Ga
Supplemental Oil And Natural Gas Disclosures | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Oil and Natural Gas Disclosures [Abstract] | |
Supplemental Oil And Natural Gas Disclosures | 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, 2016 , 201 5 and 201 4 , 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, 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 Production (4,001) (13,959) (956) (7,284) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73) (966) (10) (244) Revisions of previous quantity estimates and other (3,680) 14,100 (3,794) (5,124) Balance at December 31, 2016 57,799 316,005 28,290 138,757 Proved Developed Reserves: 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 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Proved Undeveloped Reserves: 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 Balance at December 31, 2016 40,967 222,644 20,313 98,386 (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 – Related Party Transactions and Note 16 – Partners’ Capital (Deficit) for further details. Capitalized Costs Relating to Oil and Natural Gas Producing Activities December 31, 2016 2015 (in thousands) Capitalized costs: Proved properties $ 1,611,249 $ 1,345,482 Unproved properties 116,311 127,551 Total 1,727,560 1,473,033 Accumulated depreciation, depletion, amortization and impairment (1,015,398) (947,091) Net capitalized costs $ 712,162 $ 525,942 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, 2016 2015 2014 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 66,788 $ 74,475 $ 33,787 Proved (2) 68,478 2,899 7,462 Exploration 28,480 34,275 59,201 Development (3) 165,796 146,299 341,594 $ 329,542 $ 257,948 $ 442,044 (1) Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $ 65.7 million. (3) Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016 , 201 5 and 201 4 , 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, 201 6, 2015 and 2 014 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 at December 31, 2016 , 201 5 and 201 4 : At December 31, 2016 2015 2014 (in thousands) Future cash flows $ 3,547,130 $ 2,395,128 $ 3,737,412 Future production costs (1,811,683) (860,600) (991,149) Future development costs (709,738) (403,953) (450,659) Future taxes on income — — — Future net cash flows 1,025,709 1,130,575 2,295,604 Discount to present value at 10 percent per annum (467,101) (500,979) (877,558) Standardized measure of discounted future net cash flows $ 558,608 $ 629,596 $ 1,418,046 Base price for crude oil, per Bbl, in the above computation was: $ 42.75 $ 50.28 $ 94.99 Base price for natural gas, per Mcf, in the above computation was: $ 2.49 $ 2.58 $ 4.35 No consideration was given to the Company’s hedged transactions. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18 . Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. 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, 2016 2015 2014 (in thousands) Balance at beginning of year $ 629,596 $ 1,418,046 $ 1,406,274 Sales of oil and natural gas, net of production costs (124,610) (147,906) (320,130) Changes in sales and transfer prices, net of production costs (324,638) (823,073) (153,770) Revisions of previous quantity estimates (35,972) 53,101 (477,377) Purchases of reserves-in-place 40,611 — 21,633 Sales of reserves-in-place 2,345 (244,251) (107,414) Current year discoveries and extensions 356,631 260,078 701,820 Changes in estimated future development costs 849 4,376 2,591 Development costs incurred during the year 8,363 42,420 161,357 Accretion of discount 62,960 141,805 140,627 Net change in income taxes — — — Change in production rate (timing) and other (57,527) (75,000) 42,435 Net change (70,988) (788,450) 11,772 Balance at end of year $ 558,608 $ 629,596 $ 1,418,046 |
Summary Of Significant Accoun26
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
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 acquired 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 | The reclassifications had no impact on net income (loss) or partners’ capital (deficit). |
Cash And Cash Equivalents | Cash and Cash Equivalents . We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. |
Restricted Cash | Restricted Cash. The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2016 , the restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is in dispute or unclaimed property for pooling orders in Oklahoma. |
Accounts Receivable | Accounts Receivable . Our receivables arise primarily 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. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable consisted of the following: As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889) (1,402) Total accounts receivable, net $ 37,611 $ 27,111 See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, 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 statements of operations. Deferred financing costs related to the Company’s senior secured revolving credit facility are included in deferred financing costs, net and the deferred financing costs related to the senior unsecured notes are included in long-term debt, net, on the Company’s consolidated balance sheets. |
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, delay rentals, 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. See Note 5 for further details. 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 $ 16.1 million, $ 172.0 million and $ 72.9 million for the years ended December 31, 2016 , 2015 and 2014, 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 statements of operations. For the years ended December 31, 2016 , 2015 and 2014, impairment expense of unproved properties was $ 0.2 million, $ 4.8 million, and $ 2.0 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, 2016 , 201 5 and 201 4, 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, 2016 , 2015 and 2014 related to oil and natural gas properties was $ 90.0 million, $140.9 million, and $139.0 million, respectively. Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. 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, 2016 , 2015 and 2014 was $ 2.9 million, $3.0 million, and $2.8 million respectively. |
Investments | Investments . 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 and we have recorded $9.0 million of Investment in LLC on the consolidated balance sheets as of December 31, 2016 and 2015. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations. Alta Mesa is a part owner of AEM with an ownership interest of less than 10% . AEM markets 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 collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13. |
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. Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016. The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) 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, 2016 and 2015 . 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, 2016 , 2015 or 2014 . The Company’s tax returns for the years ended December 31, 2013 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. |
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 senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine 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. In December 2016, we issued $500 million in aggregate principal amount of our 7.875% senior unsecured notes due 2024 (the “2024 Notes”). We have estimated the fair value of the 2024 Notes payable at $520 million on December 31, 2016 . Derivative financial instruments are carried at fair value. For further information on fair values of financial instruments and details related to the 2024 Notes, refer to Note 6 – Fair Value Disclosures and Note 10 - Long-Term Debt, Net. |
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, measurement and disclosure 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 deferred 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. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements. 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 does not plan to adopt the standard early. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases . In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments , which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows. In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control . This guidance provides an amendment to the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. We have adopted this ASU and there was no current impact to our consolidated financial statements. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows. In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 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. |
Derivative Financial Instrume27
Derivative Financial Instruments (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Financial Instruments [Line Items] | |
Derivative Financial Instruments | 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 6 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 gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. 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 the benchmark index price and the specific locational index 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 senior secured revolving credit facility described in Note 10 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving 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] | |
Derivative Financial Instruments | 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. |
Summary Of Significant Accoun28
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
Schedule Of Accounts Receivable | As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889) (1,402) Total accounts receivable, net $ 37,611 $ 27,111 |
Supplemental Cash Flow Inform29
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosures To The Consolidated Statements Of Cash Flows | Year Ended December 31, 2016 2015 2014 (in thousands) Supplemental cash flow information: Cash paid for interest $ 74,694 $ 56,579 $ 51,219 Cash paid (received) for state income taxes, net of refunds 285 751 (123) Non-cash investing and financing activities: Change in asset retirement obligations 2,719 487 2,643 Asset retirement obligations assumed, purchased properties — — 3,002 Change in accruals or liabilities for capital expenditures 12,375 (34,160) 23,858 Divestiture of oil and gas properties — — (34,000) Acquisition of property and land — 2,473 — Contribution of interests in oil and gas properties 65,740 — — Contribution receivable 7,875 — — |
Significant Acquisitions And 30
Significant Acquisitions And Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Significant Acquisitions And Divestitures [Abstract] | |
Summary Of Pro Forma Information | Total operating revenues and other Net loss (in thousands) (unaudited) Pro forma results for the combined entity for the year ended December 31, 2016 $ 199,982 $ (157,230) |
Property And Equipment (Tables)
Property And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property And Equipment [Abstract] | |
Summary Of Property And Equipment | December 31, December 31, 2016 2015 (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 116,311 $ 127,551 Accumulated impairment (65) (2,684) Unproved properties, net 116,246 124,867 Proved oil and natural gas properties 1,611,249 1,345,482 Accumulated depreciation, depletion, amortization and impairment (1,015,333) (944,407) Proved oil and natural gas properties, net 595,916 401,075 TOTAL OIL AND NATURAL GAS PROPERTIES, net 712,162 525,942 OTHER PROPERTY AND EQUIPMENT Land 4,730 3,868 Office furniture and equipment, vehicles 19,446 18,794 Accumulated depreciation (14,445) (11,565) OTHER PROPERTY AND EQUIPMENT, net 9,731 11,097 TOTAL PROPERTY AND EQUIPMENT, net $ 721,893 $ 537,039 |
Capitalized Exploratory Well Costs | Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 6,006 $ 13,301 $ 20,317 Additions to capitalized well costs pending determination of proved reserves 3,736 4,364 15,870 Reclassifications to proved properties (7,484) (8,583) (6,593) Capitalized exploratory well costs charged to expense (169) (3,076) (16,293) Balance, end of year $ 2,089 $ 6,006 $ 13,301 |
Fair Value Disclosures (Tables)
Fair Value Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016: Financial Assets: Derivative contracts for oil and natural gas — $ 15,773 — $ 15,773 Financial Liabilities: Derivative contracts for oil and natural gas — $ 40,656 — $ 40,656 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 |
Derivative Financial Instrume33
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative [Line Items] | |
Fair Values Of Derivative Contracts | December 31, 2016 Net Fair Gross Gross amounts Value of Assets 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 $ 3,296 $ (3,213) $ 83 Derivative financial instruments, long-term assets 12,477 (11,754) 723 Total $ 15,773 $ (14,967) $ 806 Net Fair Gross Gross amounts Value of Liabilities 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 $ 24,420 $ (3,213) $ 21,207 Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482 Total $ 40,656 $ (14,967) $ 25,689 December 31, 2015 Net Fair Gross Gross amounts Value of Assets 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 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) $ — |
Effect Of Derivative Instruments In The Consolidated Statements Of Operations | Derivatives not designated as hedging Year Ended December 31, instruments under ASC 815 2016 2015 2014 (in thousands) Gain (loss) on derivative contracts Oil commodity contracts $ (36,572) $ 113,295 $ 82,510 Natural gas commodity contracts (2,410) 10,712 14,049 Natural gas liquids commodity contracts (1,478) 134 — Total gain (loss) on derivative contracts $ (40,460) $ 124,141 $ 96,559 |
Oil Derivative Contracts [Member] | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume Weighted Range Period and Type of Contract in Bbls Average High Low 2017 Price Swap Contracts 1,460,000 $ 46.93 $ 48.43 $ 45.00 Collar Contracts Short Call Options 2,075,000 60.46 85.00 54.40 Long Put Options 1,527,500 48.39 50.00 47.00 Short Put Options 1,527,500 37.19 40.00 35.00 2018 Collar Contracts Short Call Options 1,825,000 60.64 60.90 60.50 Long Put Options 1,825,000 50.00 50.00 50.00 Short Put Options 1,825,000 40.00 40.00 40.00 2019 Collar Contracts Short Call Options 1,241,000 62.90 63.00 62.75 Long Put Options 1,241,000 50.00 50.00 50.00 Short Put Options 1,241,000 37.50 37.50 37.50 |
Natural Gas Derivative Contract [Member] | |
Derivative [Line Items] | |
Open Derivative Contracts | Volume in Weighted Range Period and Type of Contract MMBtu Average High Low 2017 Price Swap Contracts 450,000 $ 2.47 $ 2.47 $ 2.47 Collar Contracts Short Call Options 10,220,000 3.68 3.94 3.56 Long Put Options 9,320,000 3.09 3.30 3.00 Long Call Options 1,125,000 3.44 3.56 3.25 Short Put Options 9,320,000 2.56 2.70 2.50 2018 Collar Contracts Short Call Options 6,132,000 5.34 5.53 4.00 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 2017 Price Swap Contracts 5,371,800 $ 0.46 $ 0.47 $ 0.45 |
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) 12,470,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan’17 — Dec ’17 $ (0.24) 5,910,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’18 — Oct’18 (0.27) (1) Represents short swaps that fix the basis differentials between T ex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Summary Of Changes In Asset Retirement Obligations | Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 61,220 $ 62,872 $ 56,023 Liabilities incurred 1,438 1,988 1,129 Liabilities assumed with acquired producing properties — — 3,002 Liabilities settled (2,125) (1,794) (3,942) Liabilities transferred in sales of properties (3,036) (3,149) (1,886) Revisions to estimates 1,833 (773) 6,348 Accretion expense 2,174 2,076 2,198 Balance, end of year 61,504 61,220 62,872 Less: Current portion 376 729 1,136 Long-term portion $ 61,128 $ 60,491 $ 61,736 |
Long Term Debt, Net (Tables)
Long Term Debt, Net (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Long Term Debt, Net [Abstract] | |
Long-Term Debt, Net | December 31, December 31, 2016 2015 (in thousands) Senior secured revolving credit facility $ 40,622 $ 152,000 Senior secured term loan — 125,000 9.625% senior unsecured notes due 2018 — 448,598 7.875% senior unsecured notes due 2024 500,000 — Unamortized deferred financing costs (10,717) (7,823) Total long-term debt, net $ 529,905 $ 717,775 Notes payable to founder $ 26,957 $ 25,748 |
Summary Of Future Maturities Of Long-Term Debt | Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs , at December 31, 2016 are as follows ( in thousands ): Year ending December 31, 2017 $ — 2018 — 2019 — 2020 40,622 2021 26,957 Thereafter 500,000 $ 567,579 |
Accounts Payable And Accrued 36
Accounts Payable And Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounts Payable And Accrued Liabilities [Abstract] | |
Detail Of Accounts Payable And Accrued Liabilities | December 31, December 31, 2016 2015 (in thousands) Capital expenditures $ 15,155 $ 10,780 Revenues and royalties payable 12,187 5,082 Operating expenses/taxes 17,499 17,955 Interest 2,627 9,919 Compensation 5,302 5,434 Derivatives settlement payable 1,126 11,149 Other 1,164 1,201 Total accrued liabilities 55,060 61,520 Accounts payable 29,174 21,101 Accounts payable and accrued liabilities $ 84,234 $ 82,621 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Future Base Rentals For Non-Cancelable Leases | Amount (1) Year Ending December 31, (in thousands) 2017 $ 3,956 2018 1,453 2019 1,545 2020 1,593 2021 1,620 Thereafter 1,207 $ 11,374 (1) These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019. |
Supplemental Quarterly Inform38
Supplemental Quarterly Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Information [Abstract] | |
Summary Of Quarterly Results Of Operations | Results of operations by quarter for the year ended December 31, 2016 were: Quarter Ended 2016 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 38,167 $ 53,823 $ 54,532 $ 64,186 Loss from operations (1)(2) (7,967) (52,686) (8,620) (20,536) Net loss $ (24,157) $ (70,327) $ (26,567) $ (46,870) (1) Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively. (2) Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016. 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) Total operating revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (3)(4)(5) (95,077) (23,881) 110,069 (60,592) Net income (loss) $ (109,211) $ (39,509) $ 93,079 $ (76,152) (3) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (4) 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 . (5) Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 201 5 . |
Supplemental Oil And Natural 39
Supplemental Oil And Natural Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Oil and Natural Gas Disclosures [Abstract] | |
Estimated Quantities Of Proved Reserves | Oil Gas NGL's BOE (MBbls) (MMcf) (MBbls) (MBbls) Total Proved Reserves: 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 Production (4,001) (13,959) (956) (7,284) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73) (966) (10) (244) Revisions of previous quantity estimates and other (3,680) 14,100 (3,794) (5,124) Balance at December 31, 2016 57,799 316,005 28,290 138,757 Proved Developed Reserves: 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 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Proved Undeveloped Reserves: 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 Balance at December 31, 2016 40,967 222,644 20,313 98,386 (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 – Related Party Transactions and Note 16 – Partners’ Capital (Deficit) for further details. |
Capitalized Costs Relating To Oil And Natural Gas Producing Activities | December 31, 2016 2015 (in thousands) Capitalized costs: Proved properties $ 1,611,249 $ 1,345,482 Unproved properties 116,311 127,551 Total 1,727,560 1,473,033 Accumulated depreciation, depletion, amortization and impairment (1,015,398) (947,091) Net capitalized costs $ 712,162 $ 525,942 |
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities | Year Ended December 31, 2016 2015 2014 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 66,788 $ 74,475 $ 33,787 Proved (2) 68,478 2,899 7,462 Exploration 28,480 34,275 59,201 Development (3) 165,796 146,299 341,594 $ 329,542 $ 257,948 $ 442,044 (1) Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $ 65.7 million. (3) Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016 , 201 5 and 201 4 , respectively. |
Components Of The Standardized Measure Of Discounted Future Net Cash Flows | At December 31, 2016 2015 2014 (in thousands) Future cash flows $ 3,547,130 $ 2,395,128 $ 3,737,412 Future production costs (1,811,683) (860,600) (991,149) Future development costs (709,738) (403,953) (450,659) Future taxes on income — — — Future net cash flows 1,025,709 1,130,575 2,295,604 Discount to present value at 10 percent per annum (467,101) (500,979) (877,558) Standardized measure of discounted future net cash flows $ 558,608 $ 629,596 $ 1,418,046 Base price for crude oil, per Bbl, in the above computation was: $ 42.75 $ 50.28 $ 94.99 Base price for natural gas, per Mcf, in the above computation was: $ 2.49 $ 2.58 $ 4.35 |
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Year Ended December 31, 2016 2015 2014 (in thousands) Balance at beginning of year $ 629,596 $ 1,418,046 $ 1,406,274 Sales of oil and natural gas, net of production costs (124,610) (147,906) (320,130) Changes in sales and transfer prices, net of production costs (324,638) (823,073) (153,770) Revisions of previous quantity estimates (35,972) 53,101 (477,377) Purchases of reserves-in-place 40,611 — 21,633 Sales of reserves-in-place 2,345 (244,251) (107,414) Current year discoveries and extensions 356,631 260,078 701,820 Changes in estimated future development costs 849 4,376 2,591 Development costs incurred during the year 8,363 42,420 161,357 Accretion of discount 62,960 141,805 140,627 Net change in income taxes — — — Change in production rate (timing) and other (57,527) (75,000) 42,435 Net change (70,988) (788,450) 11,772 Balance at end of year $ 558,608 $ 629,596 $ 1,418,046 |
Summary Of Significant Accoun40
Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary Of Significant Accounting Policies [Line Items] | |||
FDIC insured maximum amount | $ 250,000 | ||
Proceeds from sale of property | 1,290,000 | $ 141,404,000 | $ 177,476,000 |
Accounts receivable | 37,611,000 | 27,111,000 | |
Impairment expense of proved properties | 16,100,000 | 172,000,000 | 72,900,000 |
Impairment expense of unproved properties | 200,000 | 4,800,000 | 2,000,000 |
Other write-downs and impairment expense | 0 | 0 | 0 |
Depreciation depletion and amortization related to oil and gas properties | 90,000,000 | 140,900,000 | 139,000,000 |
Depreciation expense for other property and equipment | $ 2,900,000 | 3,000,000 | 2,800,000 |
Ownership interest in a drilling company | 10.17% | ||
Liability for uncertain tax positions | $ 0 | 0 | |
Income tax penalties and interest | 0 | 0 | $ 0 |
Fair value of senior notes payable | 520,000,000 | ||
Notes payable | 567,579,000 | ||
Amount of excess of net assets | 101,500,000 | ||
Investment in LLC - cost | $ 9,000,000 | 9,000,000 | |
Minimum [Member] | Other Property And Equipment [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciable life of property and equipment | 3 years | ||
Maximum [Member] | Other Property And Equipment [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciable life of property and equipment | 7 years | ||
7.875% Senior Unsecured Notes Due 2024 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Notes payable | $ 500,000,000 | ||
Stated interest rate of senior notes | 7.875% | ||
Maturity date of debt | Dec. 15, 2024 | ||
9.625% Senior Unsecured Notes Due 2018 [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Stated interest rate of senior notes | 9.625% | ||
Maturity date of debt | Oct. 15, 2018 | ||
ARM Energy Management, LLC [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $ 17,700,000 | $ 12,600,000 |
Summary Of Significant Accoun41
Summary Of Significant Accounting Policies (Schedule Of Accounts Receivable ) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Summary Of Significant Accounting Policies [Abstract] | ||
Oil, natural gas and natural gas liquids sales | $ 25,149 | $ 17,865 |
Joint interest billings | 13,344 | 10,162 |
Other | 7 | 486 |
Allowance for doubtful accounts | (889) | (1,402) |
Total accounts receivable net | $ 37,611 | $ 27,111 |
Supplemental Cash Flow Inform42
Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest | $ 74,694 | $ 56,579 | $ 51,219 |
Cash paid (received) for state income taxes, net of refunds | 285 | 751 | (123) |
Change in asset retirement obligations | 2,719 | 487 | 2,643 |
Asset retirement obligations assumed, purchased properties | 3,002 | ||
Change in accruals or liabilities for capital expenditures | 12,375 | (34,160) | 23,858 |
Non-cash divestiture of oil and gas properties | $ (34,000) | ||
Non-cash acquisition of property and land | $ 2,473 | ||
Non-cash contribution of interests in oil and gas properties | 65,740 | ||
Contribution receivable | $ 7,875 |
Significant Acquisitions And 43
Significant Acquisitions And Divestitures (Narrative) (Details) $ in Thousands, bbl in Millions, MMBbls in Millions | Jul. 06, 2015USD ($)a | Sep. 19, 2014USD ($)MMcf | Sep. 19, 2014USD ($)MMcf | Mar. 25, 2014USD ($) | Sep. 30, 2015USD ($) | Mar. 31, 2014USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)bbl | Jul. 01, 2015MMBbls |
Business Acquisition [Line Items] | |||||||||||
Gain (loss) on sale of assets | $ 66,400 | $ 3,542 | $ 67,781 | $ 87,520 | |||||||
Other receivables | 8,061 | 18,526 | |||||||||
Contribution | 65,740 | ||||||||||
Cash contribution | 11,300 | ||||||||||
Cash collected | 7,900 | ||||||||||
Alta Mesa Eagle, LLC Divestiture [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Initial cash purchase price for properties sold | $ 118,000 | ||||||||||
Cash purchase price | 125,000 | ||||||||||
Additional contingent payment | $ 7,000 | ||||||||||
Adjusted cash purchase price, net of costs of transaction | 4,000 | ||||||||||
Estimated proved reserves | MMBbls | 7.8 | ||||||||||
Gain on sale of oil and gas properties | 67,600 | 72,500 | |||||||||
Operating income from sold oil and gas properties | 68,900 | 118,500 | |||||||||
Other receivables | $ 122,000 | ||||||||||
Undeveloped Leasehold In Oklahoma [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash consideration for Undeveloped Leasehold | $ 10,600 | ||||||||||
Kingfisher Leasehold [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Net acres | a | 19,000 | ||||||||||
Cash consideration for Undeveloped Leasehold | $ 46,200 | ||||||||||
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 | ||||||||||
Cash purchase price | $ 171,000 | ||||||||||
Gain on sale of oil and gas properties | $ 72,500 | ||||||||||
Operating income from sold oil and gas properties | $ 11,100 | ||||||||||
Eagleville Divestiture [Member] | BOE [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 | $ 38,900 | |||||||||
Gain on sale of oil and gas properties | $ 15,900 | ||||||||||
Operating income from sold oil and gas properties | $ 7,700 | ||||||||||
Hilltop Divestiture 2014 [Member] | Natural Gas in MMcf [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated proved reserves | MMcf | 29,800 | 29,800 | |||||||||
High Mesa [Member] | Contributed Wells [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of wells | item | 24 |
Significant Acquisitions And 44
Significant Acquisitions And Divestitures (Summary Of Pro Forma Information) (Details) - Pro Forma [Member] $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | |
Pro Forma Operating Revenues and other | $ 199,982 |
Pro Forma Net Loss | $ (157,230) |
Property And Equipment (Narrati
Property And Equipment (Narrative) (Details) $ in Thousands | Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) |
Property And Equipment [Abstract] | ||
Number of wells included in ending balance in deferred capitalized exploratory well costs | 5 | |
Number of prospects | 3 | |
Capitalized exploratory well costs that have been capitalized for period greater than one year | $ | $ 700 | $ 3,000 |
Property And Equipment (Summary
Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Property And Equipment [Abstract] | ||
Unproved properties | $ 116,311 | $ 127,551 |
Accumulated impairment | (65) | (2,684) |
Unproved properties, net | 116,246 | 124,867 |
Proved oil and natural gas properties | 1,611,249 | 1,345,482 |
Accumulated depreciation, depletion, amortization and impairment | (1,015,333) | (944,407) |
Proved oil and natural gas properties, net | 595,916 | 401,075 |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | 712,162 | 525,942 |
Land | 4,730 | 3,868 |
Office furniture and equipment, vehicles | 19,446 | 18,794 |
Accumulated depreciation | (14,445) | (11,565) |
OTHER PROPERTY AND EQUIPMENT, net | 9,731 | 11,097 |
Total property and equipment, net | $ 721,893 | $ 537,039 |
Property And Equipment (Capital
Property And Equipment (Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property And Equipment [Abstract] | |||
Capitalized Exploratory Well Costs, Beginning Balance | $ 6,006 | $ 13,301 | $ 20,317 |
Additions to capitalized well costs pending determination of proved reserves | 3,736 | 4,364 | 15,870 |
Reclassifications to proved properties | (7,484) | (8,583) | (6,593) |
Capitalized exploratory well costs charged to expense | (169) | (3,076) | (16,293) |
Capitalized Exploratory Well Costs, Ending Balance | $ 2,089 | $ 6,006 | $ 13,301 |
Fair Value Disclosures (Narrati
Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value Disclosures [Abstract] | |||||||||
Fair value of senior notes payable | $ 520,000 | $ 520,000 | |||||||
Carrying value of oil and gas properties | 33,900 | $ 499,600 | $ 148,400 | ||||||
Written down fair value of oil and gas properties | 17,600 | 322,800 | 73,500 | ||||||
Impairment charges to oil and gas properties | $ 2,100 | $ 11,600 | $ 1,800 | $ 90,500 | $ 8,900 | $ 73,100 | 16,306 | 176,774 | $ 74,927 |
Asset retirement obligation measured at fair value | $ 1,400 | $ 2,000 |
Fair Value Disclosures (Measure
Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Financial Assets: | ||
Commodity derivative contracts, gross | $ 15,773 | $ 166,106 |
Financial Liabilities: | ||
Commodity derivative contracts, gross | 40,656 | 61,840 |
Level 1 [Member] | ||
Financial Assets: | ||
Commodity derivative contracts, gross | ||
Financial Liabilities: | ||
Commodity derivative contracts, gross | ||
Level 2 [Member] | ||
Financial Assets: | ||
Commodity derivative contracts, gross | 15,773 | 166,106 |
Financial Liabilities: | ||
Commodity derivative contracts, gross | 40,656 | 61,840 |
Level 3 [Member] | ||
Financial Assets: | ||
Commodity derivative contracts, gross | ||
Financial Liabilities: | ||
Commodity derivative contracts, gross |
Derivative Financial Instrume50
Derivative Financial Instruments (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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 senior secured revolving 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 | $ 7,800 | $ 17,500 |
Derivative Financial Instrume51
Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | $ 15,773 | $ 166,106 |
Derivative assets, Gross amounts offset against assets in the Balance Sheet | (14,967) | (61,840) |
Derivative Assets, Current | 83 | 62,631 |
Derivative Assets, Noncurrent | 723 | 41,635 |
Derivative assets, net, total | 806 | 104,266 |
Derivative liabilities, Gross Fair Value of Liabilities | 40,656 | 61,840 |
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet | (14,967) | (61,840) |
Derivative Liabilities, Current | 21,207 | |
Derivative Liabilities, Noncurrent | 4,482 | |
Derivative liabilities, net, total | 25,689 | |
Derivative Assets Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 3,296 | 86,000 |
Derivative assets, Gross amounts offset against assets in the Balance Sheet | (3,213) | (23,369) |
Derivative Assets, Current | 83 | 62,631 |
Derivative Asset Non-Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, Gross Fair Value of Assets | 12,477 | 80,106 |
Derivative assets, Gross amounts offset against assets in the Balance Sheet | (11,754) | (38,471) |
Derivative Assets, Noncurrent | 723 | 41,635 |
Derivative Liabilities Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 24,420 | 23,369 |
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet | (3,213) | (23,369) |
Derivative Liabilities, Current | 21,207 | |
Derivative Liabilities Non Current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities, Gross Fair Value of Liabilities | 16,236 | 38,471 |
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet | (11,754) | (38,471) |
Derivative Liabilities, Noncurrent | $ 4,482 |
Derivative Financial Instrume52
Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Total gains (losses) on derivative contracts | $ 16,500 | $ 38,300 | $ 72,000 | $ (40,460) | $ 124,141 | $ 96,559 |
Not Designated As Hedging Instrument [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Total gains (losses) on derivative contracts | (40,460) | 124,141 | 96,559 | |||
Not Designated As Hedging Instrument [Member] | Oil Commodity Contracts [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Total gains (losses) on derivative contracts | (36,572) | 113,295 | 82,510 | |||
Not Designated As Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Total gains (losses) on derivative contracts | (2,410) | 10,712 | $ 14,049 | |||
Not Designated As Hedging Instrument [Member] | Natural Gas Liquids Commodity Contract [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Total gains (losses) on derivative contracts | $ (1,478) | $ 134 |
Derivative Financial Instrume53
Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil Derivative Contracts [Member] | 12 Months Ended |
Dec. 31, 2016$ / bblbbl | |
Price Swap Contracts [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,460,000 |
Weighted Average Swap Price | 46.93 |
Price Swap Contracts [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 48.43 |
Price Swap Contracts [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 45 |
Short Call Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 2,075,000 |
Weighted Average Option Price | 60.46 |
Short Call Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 85 |
Short Call Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 54.40 |
Short Call Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,825,000 |
Weighted Average Option Price | 60.64 |
Short Call Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 60.90 |
Short Call Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 60.50 |
Short Call Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,241,000 |
Weighted Average Option Price | 62.90 |
Short Call Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 63 |
Short Call Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 62.75 |
Long Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,527,500 |
Weighted Average Option Price | 48.39 |
Long Put Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 50 |
Long Put Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 47 |
Long Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,825,000 |
Weighted Average Option Price | 50 |
Long Put Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 50 |
Long Put Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 50 |
Long Put Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,241,000 |
Weighted Average Option Price | 50 |
Long Put Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 50 |
Long Put Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 50 |
Short Put Options [Member] | 2017 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,527,500 |
Weighted Average Option Price | 37.19 |
Short Put Options [Member] | 2017 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 40 |
Short Put Options [Member] | 2017 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 35 |
Short Put Options [Member] | 2018 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,825,000 |
Weighted Average Option Price | 40 |
Short Put Options [Member] | 2018 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 40 |
Short Put Options [Member] | 2018 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 40 |
Short Put Options [Member] | 2019 [Member] | |
Derivative [Line Items] | |
Volume in Bbls | bbl | 1,241,000 |
Weighted Average Option Price | 37.50 |
Short Put Options [Member] | 2019 [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 37.50 |
Short Put Options [Member] | 2019 [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 37.50 |
Derivative Financial Instrume54
Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural Gas [Member] | 12 Months Ended |
Dec. 31, 2016MMBTU$ / MMBTU | |
2017 [Member] | Price Swap Contracts [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 450,000 |
Weighted Average Swap Price | 2.47 |
2017 [Member] | Price Swap Contracts [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Swap Price | 2.47 |
2017 [Member] | Price Swap Contracts [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Swap Price | 2.47 |
2017 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 10,220,000 |
Weighted Average Option Price | 3.68 |
2017 [Member] | Short Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 3.94 |
2017 [Member] | Short Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3.56 |
2017 [Member] | Long Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 9,320,000 |
Weighted Average Option Price | 3.09 |
2017 [Member] | Long Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 3.30 |
2017 [Member] | Long Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3 |
2017 [Member] | Long Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 1,125,000 |
Weighted Average Option Price | 3.44 |
2017 [Member] | Long Call Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 3.56 |
2017 [Member] | Long Call Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 3.25 |
2017 [Member] | Short Put Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 9,320,000 |
Weighted Average Option Price | 2.56 |
2017 [Member] | Short Put Options [Member] | Maximum [Member] | |
Derivative [Line Items] | |
Option Price | 2.70 |
2017 [Member] | Short Put Options [Member] | Minimum [Member] | |
Derivative [Line Items] | |
Option Price | 2.50 |
2018 [Member] | Short Call Options [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 6,132,000 |
Weighted Average Option Price | 5.34 |
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 | 4 |
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 Instrume55
Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Details) - 2017 [Member] - Natural Gas Liquids Derivative Contracts [Member] - Price Swap Contracts [Member] | 12 Months Ended |
Dec. 31, 2016$ / galgal | |
Derivative [Line Items] | |
Volume in Gal | gal | 5,371,800 |
Weighted Average Option Price | 0.46 |
Minimum [Member] | |
Derivative [Line Items] | |
Weighted Average Swap Price | 0.45 |
Maximum [Member] | |
Derivative [Line Items] | |
Weighted Average Swap Price | 0.47 |
Derivative Financial Instrume56
Derivative Financial Instruments (Natural Gas Basis Swaps) (Details) - Financial Basis Swap Contracts For Gas [Member] | 12 Months Ended |
Dec. 31, 2016MMBTU$ / MMBTU | |
2017 [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 12,470,000 |
First remaining period of term of derivative contract | Jan. 1, 2017 |
Last remaining period of term of derivative contract | Dec. 31, 2017 |
Weighted average spread | $ / MMBTU | (0.24) |
2018 [Member] | |
Derivative [Line Items] | |
Volume in MMbtu | MMBTU | 5,910,000 |
First remaining period of term of derivative contract | Jan. 31, 2018 |
Last remaining period of term of derivative contract | Oct. 31, 2018 |
Weighted average spread | $ / MMBTU | (0.27) |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations [Abstract] | |||
Reductions To PPE Included In ARO Revisions | $ 1.5 | ||
Additions To PPE Included In ARO Revisions | $ 1.3 | $ 2.9 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations [Abstract] | ||||||
Balance, beginning of year | $ 61,220 | $ 62,872 | $ 56,023 | |||
Liabilities incurred | 1,438 | 1,988 | 1,129 | |||
Liabilities assumed with acquired producing properties | 3,002 | |||||
Liabilities settled | (2,125) | (1,794) | (3,942) | |||
Liabilities transferred in sales of properties | (3,036) | (3,149) | (1,886) | |||
Revisions to estimates | 1,833 | (773) | 6,348 | |||
Accretion expense | 2,174 | 2,076 | 2,198 | |||
Balance, end of period | $ 61,220 | $ 62,872 | $ 56,023 | $ 61,504 | $ 61,220 | $ 62,872 |
Less: Current portion | 376 | 729 | 1,136 | |||
Long-term portion | $ 61,128 | $ 60,491 | $ 61,736 |
Related Party Transactions (Det
Related Party Transactions (Details) | Jan. 13, 2017USD ($)MMBTU | Dec. 31, 2016USD ($)itemshares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jan. 02, 2015USD ($) |
Related Party Transaction [Line Items] | |||||
Notes payable to founder | $ 27,000,000 | $ 25,700,000 | |||
Total expenditures for land consulting services | $ 146,000 | 133,000 | $ 150,000 | ||
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 | $ 377,076,000 | 20,000,000 | |||
Non-cash land acquisition from affiliate | 700,000 | ||||
Related party total cost | 3,000,000 | ||||
Interest income on notes receivable | 774,000 | 713,000 | |||
Advances from related party | 42,528,000 | ||||
Receivables due from affiliate | 8,883,000 | 1,053,000 | |||
Contribution receivable | 7,875,000 | ||||
High Mesa [Member] | |||||
Related Party Transaction [Line Items] | |||||
Contributions | 311,300,000 | ||||
Receivables due from affiliate | 900,000 | 1,100,000 | |||
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 | 425,000 | 275,000 | 450,000 | ||
Landman [Member] | |||||
Related Party Transaction [Line Items] | |||||
Total compensation | 180,000 | 146,000 | 260,000 | ||
Founder [Member] | |||||
Related Party Transaction [Line Items] | |||||
Distributions | $ 0 | $ 0 | $ 516,500 | ||
BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 40 | ||||
Threshold of project cost | $ 64,000,000 | ||||
NWGP [Member] | |||||
Related Party Transaction [Line Items] | |||||
Receivables due from affiliate | 100,000 | ||||
Crude Oil Gathering Agreement And Gas Gathering And Processing Agreement [Member] | |||||
Related Party Transaction [Line Items] | |||||
Related party total cost | $ 7,500,000 | ||||
Period of term | 15 years | ||||
Gas Gathering And Processing Agreement [Member] | |||||
Related Party Transaction [Line Items] | |||||
Allocated shares of processing rights | shares | 260 | ||||
Oklahoma Energy [Member] | Subsequent Event [Member] | |||||
Related Party Transaction [Line Items] | |||||
Prepaid expense | $ 10,000,000 | ||||
Prepaid expense, Transporation capacity | MMBTU | 100,000 | ||||
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 | 10.00% | ||||
Notes Payable To Founder [Member] | |||||
Related Party Transaction [Line Items] | |||||
Effective rate of interest on senior notes | 10.00% | 10.00% | |||
Joint Development Agreement [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 60 | ||||
Number of wells drilled | item | 20 | ||||
Joint Development Agreement [Member] | BCE-STACK [Member] | Maximum [Member] | |||||
Related Party Transaction [Line Items] | |||||
Drilling and completion costs | $ 3,200,000 | ||||
Joint Development Agreement Tranch 1 [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percent of interest reduced | 12.50% | ||||
Percent of internal return rate | 25.00% | ||||
Joint Development Agreement Tranch 1 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 20 | ||||
Percent committed to fund | 100.00% | ||||
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] | |||||
Related Party Transaction [Line Items] | |||||
Percent of interest reduced | 12.50% | ||||
Percent of internal return rate | 25.00% | ||||
Joint Development Agreement Tranch 2 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 20 | ||||
Percent committed to fund | 100.00% | ||||
Percent of working interest | 80.00% | ||||
Percent of interest reduced | 20.00% | ||||
Percent of internal return rate | 15.00% | ||||
Joint Development Agreement Tranch 3 [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percent of interest reduced | 12.50% | ||||
Percent of internal return rate | 25.00% | ||||
Joint Development Agreement Tranch 3 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 20 | ||||
Percent committed to fund | 100.00% | ||||
Percent of working interest | 80.00% | ||||
Percent of interest reduced | 20.00% | ||||
Percent of internal return rate | 15.00% | ||||
Joint Development Agreement Tranch 4 [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percent of interest reduced | 12.50% | ||||
Percent of internal return rate | 25.00% | ||||
Joint Development Agreement Tranch 4 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 20 | ||||
Percent committed to fund | 100.00% | ||||
Percent of working interest | 80.00% | ||||
Percent of interest reduced | 20.00% | ||||
Percent of internal return rate | 15.00% | ||||
Joint Development Agreement Tranch 1, 2, 3, and 4 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 80 | ||||
Joint Development Agreement Tranch 3 and 4 [Member] | BCE-STACK [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 40 | ||||
Contributed Wells [Member] | High Mesa [Member] | |||||
Related Party Transaction [Line Items] | |||||
Number of wells | item | 24 |
Long Term Debt, Net (Narrative)
Long Term Debt, Net (Narrative) (Details) - USD ($) | Mar. 25, 2014 | Nov. 30, 2016 | Oct. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Oct. 31, 2015 | Jun. 02, 2015 |
Debt Instrument [Line Items] | ||||||||
Letter of credit outstanding | $ 7,600,000 | $ 65,000 | ||||||
Notes payable to founder | 26,957,000 | 25,748,000 | ||||||
Interest on notes payable to founder | 1,209,000 | 1,208,000 | $ 1,209,000 | |||||
Amortization of deferred financing costs | $ 3,905,000 | 3,392,000 | 2,885,000 | |||||
Debt covenant compliance description | At December 31, 2016, we were in compliance with the covenants of our debt agreements. | |||||||
Deferred financing costs | $ 3,029,000 | 1,199,000 | ||||||
Debt Instrument, Customary events of default | The credit facility and the 2024 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. | |||||||
Loss on extinguishment of debt | $ 18,151,000 | |||||||
Deferred financing cost write-off | 0 | $ 0 | ||||||
Contributions | $ 377,076,000 | 20,000,000 | ||||||
Federal Funds Effective Swap Rate [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 50.00% | |||||||
Eurodollar [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 1.00% | |||||||
6th Amended And Restated Credit Agreement [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility borrowing base | $ 40,600,000 | |||||||
Credit Facility, Term Loan Facility, And Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Deferred financing costs | 13,700,000 | |||||||
Term Loan Facility And Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Deferred financing costs | $ 10,700,000 | |||||||
9.625% Senior Unsecured Notes Due 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date of debt | Oct. 15, 2018 | |||||||
Amortization of deferred financing costs | $ 5,100,000 | |||||||
Loss on extinguishment of debt | 13,500,000 | |||||||
Deferred financing cost write-off | $ 3,200,000 | |||||||
Notes payable | $ 448,598,000 | |||||||
Stated interest rate of senior notes | 9.625% | |||||||
Repurchase amount | $ 459,400,000 | |||||||
Unamortized premium | 2,500,000 | |||||||
Interest expense | $ 6,900,000 | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date of debt | Dec. 15, 2024 | |||||||
Optional redemption price of Senior Notes | 35.00% | |||||||
Notes payable | $ 500,000,000 | |||||||
Stated interest rate of senior notes | 7.875% | |||||||
First annual payment date | June 15 | |||||||
Second annual payment date | December 15 | |||||||
Net proceeds | $ 491,300,000 | |||||||
Redemption percentage of aggregate principle | 65.00% | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | Prior to December 15, 2019 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price due to specific change of control events | 107.875% | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2019 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price due to specific change of control events | 105.906% | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2020 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price due to specific change of control events | 103.938% | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2021 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price due to specific change of control events | 101.969% | |||||||
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2022 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Redemption price due to specific change of control events | 100.00% | |||||||
Senior Secured Revolving 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 | $ 300,000,000 | |||||||
Margin interest rate | 25.00% | |||||||
Credit facility interest rate | 4.00% | 2.89% | ||||||
Pro forma leverage ratio | 3.00% | |||||||
Percentage of proven reserves value | 85.00% | |||||||
Minimum Working Capital Ratio | 1 | |||||||
Maximum Leverage Ratio | 4 | |||||||
Debt instrument collateral | The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. 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 restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect. As of December 31, 2016, the covenants of the Company's credit facility prohibit it from making any distributions. The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses ("EBITDAX") over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0, commencing with the fiscal quarter ending December 31, 2016. | |||||||
Deferred financing costs | $ 3,000,000 | |||||||
Credit facility amount | $ 500,000,000 | |||||||
Percent of unused distribution | 20.00% | |||||||
Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility applicable interest rate, description | the London Interbank Offered Rate ("LIBOR") plus applicable margins ranging from 2.75% and 3.75% | |||||||
Leverage rate | 3.25% | |||||||
Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility applicable interest rate, description | plus a margin ranging from 1.75% to 2.75% | |||||||
Leverage rate | 3.25% | |||||||
Senior Secured Revolving Credit Facility [Member] | 6th Amended And Restated Credit Agreement [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Line of Credit Facility, Remaining borrowing capacity | $ 239,300,000 | |||||||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 2.75% | |||||||
Exceeded leverage rate | 3.00% | |||||||
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 1.75% | |||||||
Exceeded leverage rate | 2.00% | |||||||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 3.75% | |||||||
Exceeded leverage rate | 4.00% | |||||||
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Margin interest rate | 2.75% | |||||||
Exceeded leverage rate | 3.00% | |||||||
Amended And Restated Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility borrowing base | $ 287,500,000 | |||||||
Margin interest rate | 50.00% | |||||||
Percentage of proven reserves value | 90.00% | |||||||
Maturity date of debt | Nov. 10, 2020 | |||||||
Credit facility amount | $ 750,000,000 | |||||||
Notes Payable To Founder [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date of debt | Dec. 31, 2018 | Dec. 31, 2021 | ||||||
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 16, 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 partnership agreement, as amended, and subordinated to the rights of the holders of Series B preferred stock to receive payments. | |||||||
Senior Secured Term Loan [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Amount borrowed | $ 125,000,000 | |||||||
Net proceeds used to pay down outstanding amounts under existing credit facility | $ 127,700,000 | |||||||
Loss on extinguishment of debt | 4,700,000 | |||||||
Deferred financing cost write-off | 2,000,000 | |||||||
Prepayment premium | 2,500,000 | |||||||
Senior Notes [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Amount borrowed | $ 125,000,000 | |||||||
Face value of senior notes issued | $ 450,000,000 | |||||||
Redemption price due to specific change of control events | 101.00% |
Long Term Debt, Net (Long-Term
Long Term Debt, Net (Long-Term Debt, Net) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | $ (10,717) | $ (7,823) |
Total long-term debt, net | 529,905 | 717,775 |
Notes payable to founder | 26,957 | 25,748 |
Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Senior Secured Term Loan | 125,000 | |
7th Amended And Restated Credit Agreement [Member] | ||
Debt Instrument [Line Items] | ||
Credit Facility | $ 40,622 | 152,000 |
9.625% Senior Unsecured Notes Due 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Notes payable | $ 448,598 | |
Maturity date of debt | Oct. 15, 2018 | |
Stated interest rate of senior notes | 9.625% | |
7.875% Senior Unsecured Notes Due 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Notes payable | $ 500,000 | |
Maturity date of debt | Dec. 15, 2024 | |
Stated interest rate of senior notes | 7.875% |
Long Term Debt (Summary Of Futu
Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Summary of future maturities of long-term debt | |
2,020 | $ 40,622 |
2,021 | 26,957 |
Thereafter | 500,000 |
Total long-term debt | $ 567,579 |
Accounts Payable And Accrued 63
Accounts Payable And Accrued Liabilities (Detail Of Accounts Payable And Accrued Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accounts Payable And Accrued Liabilities [Abstract] | ||
Capital expenditures | $ 15,155 | $ 10,780 |
Revenues and royalties payable | 12,187 | 5,082 |
Operating expenses/taxes | 17,499 | 17,955 |
Interest | 2,627 | 9,919 |
Compensation | 5,302 | 5,434 |
Derivatives settlement payable | 1,126 | 11,149 |
Other | 1,164 | 1,201 |
Total accrued liabilities | 55,060 | 61,520 |
Accounts payable | 29,174 | 21,101 |
Accounts payable and accrued liabilities | $ 84,234 | $ 82,621 |
Commitments and Contingencies64
Commitments and Contingencies (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands | Jan. 01, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Commitment And Contingencies [Line Items] | ||||
Liability for soil contamination | $ 100 | $ 1,300 | ||
Vesting period, PARs | 5 years | |||
Weighted average stipulated price of PARs granted | $ 36.78 | |||
Number of performance appreciation rights granted | 360,000 | |||
Number of performance appreciation rights terminated | 26,200 | |||
Number of performance appreciation rights | 575,300 | |||
Weighted average stipulated price of PARs terminated | $ 40 | |||
Other long-term litigation liabilities | $ 6,870 | 10,829 | ||
Payment under contingent commitment towards properties acquired | 2,200 | |||
Rent expense | 5,700 | $ 4,800 | $ 5,700 | |
Performance Bonds Outstanding | 24,000 | |||
Subsequent Event [Member] | ||||
Commitment And Contingencies [Line Items] | ||||
Weighted average stipulated price of PARs granted | $ 37.90 | |||
Number of performance appreciation rights granted | 306,300 | |||
Weighted average price of PARs granted | $ 40 | |||
Number of performance appreciation rights terminated | 500 | |||
Number of performance appreciation rights | 881,100 | |||
Weighted average stipulated price of PARs terminated | $ 40 | |||
Litigation [Member] | ||||
Commitment And Contingencies [Line Items] | ||||
Estimated litigation liability | 4,000 | |||
Current litigation liabilities | 800 | |||
Other long-term litigation liabilities | $ 3,200 | |||
Settlement payment term | 6 years | |||
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 |
Commitments And Contingencies65
Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Future base rentals for non-cancelable leases | |
2,017 | $ 3,956 |
2,018 | 1,453 |
2,019 | 1,545 |
2,020 | 1,593 |
2,021 | 1,620 |
Thereafter | 1,207 |
Total future base rental | 11,374 |
Expected sublease income | $ 200 |
Significant Concentrations (Det
Significant Concentrations (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)customer | |
Concentration Risk [Line Items] | |||||||||||
Revenues | $ 64,186 | $ 54,532 | $ 53,823 | $ 38,167 | $ 48,325 | $ 61,344 | $ 71,755 | $ 60,542 | $ 173,790 | $ 433,888 | $ 616,207 |
Number of customers that accounted for 10% or more of revenues | customer | 1 | ||||||||||
Minimum percentage of contribution of customers to revenue | 10.00% | ||||||||||
Benchmark for determining customer significance | revenues excluding hedging activities | ||||||||||
Murphy [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Revenues | $ 61,200 | ||||||||||
ARM Energy Management, LLC [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Marketing fee | 1.00% | ||||||||||
Term of agreement left until extensions may come into effect | 5 years | ||||||||||
Revenues | $ 160,700 | $ 178,200 | $ 220,900 | ||||||||
ARM Energy Management, LLC [Member] | Revenues [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Concentration Risk, Percentage | 80.00% | 73.90% | 51.10% | ||||||||
ARM Energy Management, LLC [Member] | Maximum [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Percentage of ownership | 10.00% | 10.00% |
401(k) Savings Plan (Details)
401(k) Savings Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
401(k) Savings Plan [Abstract] | |||
Percentage of matching contribution by company | 100.00% | ||
Maximum percentage of employee's salary deferral contribution | 5.00% | ||
Matching contributions to the plan | $ 1,122,000 | $ 710,000 | $ 683,000 |
Significant Risks And Uncerta68
Significant Risks And Uncertainties (Details) | 12 Months Ended |
Dec. 31, 2016 | |
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 have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. 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. 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) | 12 Months Ended | |||
Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Mar. 25, 2014USD ($) | |
Debt Instrument [Line Items] | ||||
Number of classes of limited partners | item | 2 | |||
Amount of recapitalization | $ 350,000,000 | |||
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 | 5 | |||
Contributions | $ 377,076,000 | $ 20,000,000 | ||
Cash contribution | 11,300,000 | |||
Related party total cost | 3,000,000 | |||
Cash collected | 7,900,000 | |||
Contribution | 65,740,000 | |||
Limited Partner [Member] | ||||
Debt Instrument [Line Items] | ||||
Distributions | 0 | 3,800,000 | $ 500,000 | |
Contributions | $ 20,000,000 | |||
High Mesa [Member] | ||||
Debt Instrument [Line Items] | ||||
Contributions | $ 311,300,000 | |||
Contributed Wells [Member] | High Mesa [Member] | ||||
Debt Instrument [Line Items] | ||||
Number of wells | item | 24 | |||
Senior Secured Term Loan [Member] | ||||
Debt Instrument [Line Items] | ||||
Prepayment premium | $ 2,500,000 | |||
Net proceeds used to pay down outstanding amounts under existing credit facility | $ 127,700,000 |
Supplemental Quarterly Inform70
Supplemental Quarterly Information (Summary Of Quarterly Results Of Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Quarterly Information [Abstract] | |||||||||||
Total operating revenues | $ 64,186 | $ 54,532 | $ 53,823 | $ 38,167 | $ 48,325 | $ 61,344 | $ 71,755 | $ 60,542 | $ 173,790 | $ 433,888 | $ 616,207 |
Income (loss) from operations | (20,536) | (8,620) | (52,686) | (7,967) | (60,592) | 110,069 | (23,881) | (95,077) | (89,809) | (69,481) | 155,173 |
Net income (loss) | (46,870) | (26,567) | (70,327) | (24,157) | (76,152) | 93,079 | $ (39,509) | (109,211) | (167,921) | (131,793) | 99,200 |
Gain on sale of assets | 66,400 | 3,542 | 67,781 | 87,520 | |||||||
Impairment expense | 2,100 | $ 11,600 | $ 1,800 | $ 90,500 | 8,900 | $ 73,100 | 16,306 | 176,774 | 74,927 | ||
Gain (loss) on derivative contracts | $ 16,500 | $ 38,300 | $ 72,000 | $ (40,460) | $ 124,141 | $ 96,559 |
Supplemental Oil And Natural 71
Supplemental Oil And Natural Gas Disclosures (Narrative) (Details) - $ / bbl | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Oil and Natural Gas Disclosures [Abstract] | |||
Base price for crude oil, per Bbl, in the above computations was | 42.75 | 50.28 | 94.99 |
Estimated realized prices | 15.18 |
Supplemental Oil And Natural 72
Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details) | 12 Months Ended | ||
Dec. 31, 2016MMcfMBbls | Dec. 31, 2015MMcfMBbls | Dec. 31, 2014MMcfMBbls | |
Oil [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 34,142 | 31,344 | 32,517 |
Production | (4,001) | (4,203) | (3,770) |
Purchases in place | 1,508 | 610 | |
Discoveries and extensions | 29,903 | 12,981 | 13,281 |
Sales of reserves in place | (73) | (6,544) | (6,298) |
Revisions of previous quantity estimates and other | (3,680) | 564 | (4,996) |
Proved Reserves, Ending balance | 57,799 | 34,142 | 31,344 |
Proved Developed Reserves | 16,832 | 14,942 | 15,182 |
Proved Undeveloped Reserves | 40,967 | 19,200 | 16,162 |
Natural Gas [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | MMcf | 155,423 | 103,148 | 132,265 |
Production | MMcf | (13,959) | (11,900) | (14,449) |
Purchases in place | MMcf | 6,754 | 327 | |
Discoveries and extensions | MMcf | 154,653 | 58,129 | 28,822 |
Sales of reserves in place | MMcf | (966) | (8,250) | (35,857) |
Revisions of previous quantity estimates and other | MMcf | 14,100 | 14,296 | (7,960) |
Proved Reserves, Ending balance | MMcf | 316,005 | 155,423 | 103,148 |
Proved Developed Reserves | MMcf | 93,361 | 71,752 | 63,334 |
Proved Undeveloped Reserves | MMcf | 222,644 | 83,671 | 39,814 |
Natural Gas Liquids [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 18,437 | 8,388 | 5,735 |
Production | (956) | (678) | (537) |
Purchases in place | 613 | ||
Discoveries and extensions | 14,000 | 7,763 | 4,119 |
Sales of reserves in place | (10) | (748) | (949) |
Revisions of previous quantity estimates and other | (3,794) | 3,712 | 20 |
Proved Reserves, Ending balance | 28,290 | 18,437 | 8,388 |
Proved Developed Reserves | 7,977 | 6,958 | 4,028 |
Proved Undeveloped Reserves | 20,313 | 11,479 | 4,360 |
BOE [Member] | |||
Total Proved Reserves: | |||
Proved Reserves, Beginning Balance | 78,483 | 56,923 | 60,296 |
Production | (7,284) | (6,865) | (6,715) |
Purchases in place | 3,247 | 665 | |
Discoveries and extensions | 69,679 | 30,432 | 22,204 |
Sales of reserves in place | (244) | (8,667) | (13,223) |
Revisions of previous quantity estimates and other | (5,124) | 6,660 | (6,304) |
Proved Reserves, Ending balance | 138,757 | 78,483 | 56,923 |
Proved Developed Reserves | 40,371 | 33,859 | 29,765 |
Proved Undeveloped Reserves | 98,386 | 44,624 | 27,158 |
Supplemental Oil And Natural 73
Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Capitalized costs: | ||
Proved properties | $ 1,611,249 | $ 1,345,482 |
Unproved properties | 116,311 | 127,551 |
Total | 1,727,560 | 1,473,033 |
Accumulated depreciation, depletion, amortization and impairment | (1,015,398) | (947,091) |
TOTAL OIL AND NATURAL GAS PROPERTIES, net | $ 712,162 | $ 525,942 |
Supplemental Oil And Natural 74
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities | ||||
Property acquisition costs, unproved properties | [1] | $ 66,788 | $ 74,475 | $ 33,787 |
Property acquisition costs, proved properties | [1],[2] | 68,478 | 2,899 | 7,462 |
Costs incurred, exploration | 28,480 | 34,275 | 59,201 | |
Costs incurred, development | [3] | 165,796 | 146,299 | 341,594 |
Costs Incurred, Total | 329,542 | 257,948 | 442,044 | |
Costs Incurred, Additional Information [Abstract] | ||||
Additions to asset retirement obligations | 1,900 | (300) | $ 4,500 | |
Unproven leasehold acquisition cost | $ 46,600 | |||
Stone [Member] | ||||
Costs Incurred, Additional Information [Abstract] | ||||
Total cost of business acquisition | $ 65,700 | |||
[1] | Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. | |||
[2] | Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $65.7 million. | |||
[3] | Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. |
Supplemental Oil And Natural 75
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, 2016USD ($)$ / Mcf$ / bbl | Dec. 31, 2015USD ($)$ / Mcf$ / bbl | Dec. 31, 2014USD ($)$ / Mcf$ / bbl | Dec. 31, 2013USD ($) | |
Components of the standardized measure of discounted future net cash flows | ||||
Future cash flows | $ 3,547,130 | $ 2,395,128 | $ 3,737,412 | |
Future production costs | (1,811,683) | (860,600) | (991,149) | |
Future development costs | (709,738) | (403,953) | (450,659) | |
Future taxes on income | ||||
Future net cash flows | 1,025,709 | 1,130,575 | 2,295,604 | |
Discount to present value at 10 percent per annum | (467,101) | (500,979) | (877,558) | |
Standardized measure of discounted future net cash flows | $ 558,608 | $ 629,596 | $ 1,418,046 | $ 1,406,274 |
Base price for crude oil, per Bbl, in the above computations was | $ / bbl | 42.75 | 50.28 | 94.99 | |
Base price for natural gas, per Mcf, in the above computations was | $ / Mcf | 2.49 | 2.58 | 4.35 |
Supplemental Oil And Natural 76
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Components of changes in standardized measure of discounted future net cash flows | |||
Balance at beginning of year | $ 629,596 | $ 1,418,046 | $ 1,406,274 |
Sales of oil and natural gas, net of production costs | (124,610) | (147,906) | (320,130) |
Changes in sales and transfer prices, net of production costs | (324,638) | (823,073) | (153,770) |
Revisions of previous quantity estimates | (35,972) | 53,101 | (477,377) |
Purchases of reserves-in-place | 40,611 | 21,633 | |
Sales of reserves-in-place | 2,345 | (244,251) | (107,414) |
Current year discoveries and extensions | 356,631 | 260,078 | 701,820 |
Changes in estimated future development costs | 849 | 4,376 | 2,591 |
Development costs incurred during the year | 8,363 | 42,420 | 161,357 |
Accretion of discount | 62,960 | 141,805 | 140,627 |
Net change in income taxes | |||
Change in production rate (timing) and other | (57,527) | (75,000) | 42,435 |
Net change | (70,988) | (788,450) | 11,772 |
Balance at end of year | $ 558,608 | $ 629,596 | $ 1,418,046 |