Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Nov. 08, 2013 | |
Document And Entity Information [Abstract] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 30-Sep-13 | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Trading Symbol | 'cep | ' |
Entity Registrant Name | 'Constellation Energy Partners LLC | ' |
Entity Central Index Key | '0001362705 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Smaller Reporting Company | ' |
Entity Common Stock, Shares Outstanding | ' | 28,463,746 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash and cash equivalents | $3,724 | $1,959 |
Accounts receivable | 6,784 | 5,615 |
Prepaid expenses | 1,419 | 1,309 |
Risk management assets (see Note 5) | 12,196 | 17,965 |
Current assets from discontinued operations | ' | 1,886 |
Total current assets | 24,123 | 28,734 |
Oil and natural gas properties (See Note 6) | ' | ' |
Oil and natural gas properties, equipment and facilities | 638,231 | 594,020 |
Material and supplies | 846 | 771 |
Less accumulated depreciation, depletion, amortization, and impairments | -489,083 | -474,669 |
Net oil and natural gas properties | 149,994 | 120,122 |
Other assets | ' | ' |
Debt issue costs (net of accumulated amortization of $9,003 and $7,775, respectively) | 865 | 1,168 |
Risk management assets (see Note 5) | 4,404 | 7,431 |
Other non-current assets | 4,109 | 3,194 |
Long-term assets from discontinued operations | ' | 67,373 |
Total assets | 183,495 | 228,022 |
Current liabilities | ' | ' |
Accounts payable | 46 | 480 |
Accrued liabilities | 8,357 | 7,174 |
Royalty payable | 1,364 | 1,418 |
Risk management liabilities (see Note 5) | ' | 523 |
Debt | ' | 50,000 |
Current liabilities from discontinued operations | ' | 1,578 |
Total current liabilities | 9,767 | 61,173 |
Other liabilities | ' | ' |
Asset retirement obligation | 9,325 | 7,665 |
Risk management liabilities (see Note 5) | ' | 637 |
Other non-current liabilities | 1,953 | 589 |
Debt | 50,700 | 34,000 |
Other long-term liabilities from discontinued operations | ' | 7,692 |
Total liabilities | 71,745 | 111,756 |
Commitments and contingencies (See Note 9) | ' | ' |
Members' equity | ' | ' |
Total members' equity | 111,750 | 116,266 |
Total liabilities and members' equity | 183,495 | 228,022 |
Common Class A | ' | ' |
Members' equity | ' | ' |
Limited partners' capital account | 2,847 | 2,326 |
Common Class B | ' | ' |
Members' equity | ' | ' |
Limited partners' capital account | $108,903 | $113,940 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, except Share data, unless otherwise specified | ||
Debt issue costs, accumulated amortization | 9,003 | 7,775 |
Common Class A | ' | ' |
Share units authorized | 1,615,017 | 483,418 |
Share units issued | 1,615,017 | 483,418 |
Shares units outstanding | 1,615,017 | 483,418 |
Common Class B | ' | ' |
Share units authorized | 28,848,785 | 24,124,378 |
Share units issued | 28,463,746 | 23,687,507 |
Shares units outstanding | 28,463,746 | 23,687,507 |
Condensed_Consolidated_Stateme
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Revenues | ' | ' | ' | ' |
Natural gas sales | $7,328 | $1,898 | $18,745 | $23,243 |
Oil and liquids sales | 4,803 | 1,379 | 13,874 | 9,847 |
Total revenues (see Note 5) | 12,131 | 3,277 | 32,619 | 33,090 |
Operating expenses: | ' | ' | ' | ' |
Lease operating expenses | 5,191 | 4,869 | 13,332 | 14,727 |
Cost of sales | 323 | 287 | 1,122 | 923 |
Production taxes | 731 | 374 | 1,840 | 1,141 |
General and administrative | 3,015 | 4,014 | 11,156 | 11,555 |
Loss on sale of assets | 31 | ' | 8 | ' |
Depreciation, depletion, and amortization | 5,491 | 2,373 | 15,056 | 7,078 |
Asset impairments | ' | ' | ' | 107 |
Accretion expense | 163 | 116 | 409 | 345 |
Total operating expenses | 14,945 | 12,033 | 42,923 | 35,876 |
Other expenses (income) | ' | ' | ' | ' |
Interest expense | 420 | 1,534 | 2,636 | 4,590 |
Other expenses (income) | 23 | -21 | -149 | -114 |
Total other expenses | 443 | 1,513 | 2,487 | 4,476 |
Total expenses | 15,388 | 13,546 | 45,410 | 40,352 |
Loss from continuing operations | -3,257 | -10,269 | -12,791 | -7,262 |
Loss from discontinued operations | ' | -894 | -2,686 | -3,026 |
Net loss | -3,257 | -11,163 | -15,477 | -10,288 |
Change in fair value of commodity hedges | ' | 63 | ' | 151 |
Cash settlement of commodity hedges | ' | -1,722 | ' | -4,367 |
Other comprehensive loss | ' | -1,659 | ' | -4,216 |
Comprehensive loss | ($3,257) | ($12,822) | ($15,477) | ($14,504) |
Loss per unit (see Note 2) | ' | ' | ' | ' |
Loss from continuing operations per unit-Basic | ($0.12) | ($0.42) | ($0.51) | ($0.30) |
Loss from discontinued operations per unit-Basic | ' | ($0.04) | ($0.11) | ($0.13) |
Net loss per unit-Basic | ($0.12) | ($0.46) | ($0.62) | ($0.43) |
Units outstanding-Basic | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 |
Loss from continuing operations per unit-Diluted | ($0.12) | ($0.42) | ($0.51) | ($0.30) |
Loss from discontinued operations per unit-Diluted | ' | ($0.04) | ($0.11) | ($0.13) |
Net loss per unit-Diluted | ($0.12) | ($0.46) | ($0.62) | ($0.43) |
Units outstanding-Diluted | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 |
Distributions declared and paid per unit | ' | ' | ' | ' |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Cash Flows (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Cash flows from operating activities: | ' | ' |
Net loss | ($15,477) | ($10,288) |
Adjustments to reconcile net loss to cash provided by operating activities | ' | ' |
Depreciation, depletion and amortization | 15,056 | 7,078 |
Asset impairments (see Note 6) | ' | 107 |
Amortization of debt issuance costs | 1,228 | 974 |
Accretion expense | 409 | 345 |
Equity earnings in affiliate | -224 | -129 |
Gain from disposition of property and equipment | 8 | ' |
Bad debt expense | 44 | 26 |
Loss from mark-to-market activities | 7,635 | 7,756 |
Unit-based compensation programs | 828 | 1,163 |
Discontinued operations | 2,686 | 3,026 |
Changes in Assets and Liabilities: | ' | ' |
(Increase) decrease in accounts receivable | -1,212 | 1,004 |
(Increase) decrease in prepaid expenses | -110 | 278 |
Increase in other assets | -1,107 | -600 |
Increase (decrease) in accounts payable | -434 | 279 |
Decrease in accrued liabilities | -1,614 | -2,699 |
Decrease in royalty payable | -54 | -47 |
Increase in other liabilities | 1,114 | 507 |
Net cash provided by continuing operations | 8,776 | 8,780 |
Net cash provided by discontinued operations | 1,062 | 2,655 |
Net cash provided by operating activities | 9,838 | 11,435 |
Cash flows from investing activities: | ' | ' |
Cash paid for acquisitions, net of cash acquired | -20,221 | -75 |
Development of oil and natural gas properties | -12,564 | -10,309 |
Proceeds from sale of assets | 58,987 | 1,505 |
Distributions from equity affiliate | 135 | 150 |
Net cash provided by (used in) continuing operations | 26,337 | -8,729 |
Net cash used in discontinued operations | ' | -147 |
Net cash provided by (used in) investing activities | 26,337 | -8,876 |
Cash flows from financing activities: | ' | ' |
Proceeds from issuance of debt | 16,894 | ' |
Repayment of debt | -50,194 | -10,000 |
Units tendered by employees for tax withholdings | -185 | -199 |
Debt issue costs | -925 | -14 |
Net cash used in continuing operations | -34,410 | -10,213 |
Net cash used in discontinued operations | ' | ' |
Net cash used in financing activities | -34,410 | -10,213 |
Net (decrease) increase in cash and cash equivalents | 1,765 | -7,654 |
Cash and cash equivalents, beginning of period | 1,959 | 17,176 |
Cash and cash equivalents, end of period | 3,724 | 9,522 |
Supplemental disclosures of cash flow information: | ' | ' |
Change in accrued capital expenditures | 333 | 34 |
Cash received during the period for interest | ' | 1 |
Cash paid during the period for interest | ($1,405) | ($2,812) |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements of Changes in Members' Equity (USD $) | Common Class A | Common Class B | Accumulated Other Comprehensive Income (Loss) | Total |
In Thousands, except Share data | ||||
Beginning Balance at Dec. 31, 2012 | $2,326 | $113,940 | ' | $116,266 |
Beginning Balance (in shares) at Dec. 31, 2012 | 483,418 | 23,687,507 | ' | ' |
Distributions | ' | ' | ' | ' |
Units tendered by employees for tax (Shares) | -2,853 | -139,810 | ' | ' |
Units tendered by employees for tax | -4 | -181 | ' | -185 |
Unit-based compensation programs (in shares) | 3,940 | 191,642 | ' | ' |
Unit-based compensation programs | 17 | 811 | ' | 828 |
Unit issuance cost (in shares) | 1,130,512 | 4,724,407 | ' | ' |
Unit issuance cost | 818 | 9,500 | ' | 10,318 |
Net loss | -310 | -15,167 | ' | -15,477 |
Ending Balance at Sep. 30, 2013 | $2,847 | $108,903 | ' | $111,750 |
Ending Balance (in shares) at Sep. 30, 2013 | 1,615,017 | 28,463,746 | ' | ' |
Organization_And_Basis_Of_Pres
Organization And Basis Of Presentation | 9 Months Ended |
Sep. 30, 2013 | |
Organization And Basis Of Presentation [Abstract] | ' |
Organization And Basis Of Presentation | ' |
1. ORGANIZATION AND BASIS OF PRESENTATION | |
Organization | |
Constellation Energy Partners LLC (CEP, we, us, our or the Company) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the symbol “CEP”. Through subsidiaries, PostRock Energy Corporation (NASDAQ: PSTR) (PostRock), Exelon Corporation (NYSE: EXC) (Exelon) and Sanchez Oil & Gas Corporation (SOG) own a portion of our outstanding units. As of September 30, 2013, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 484,505 of our Class A units and 5,918,894 of our Class B common units. Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests. Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned 1,130,512, or 70%, of our Class A units and 4,724,407 of our Class B common units. | |
We are currently focused on the acquisition, development and production of oil and natural gas properties, as well as midstream assets. Our proved reserves are located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas and in Texas and Louisiana. | |
Basis of Presentation | |
These unaudited condensed consolidated financial statements include the accounts of CEP and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties. | |
These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP), have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. | |
These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 11, 2013, and amended by Amendment No. 1 thereto filed with the SEC on April 18, 2013. | |
Use of Estimates | |
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. | |
Reclassifications | |
Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no impact on the previously reported net income (loss) for any periods. | |
New Accounting Pronouncements | |
In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities, which requires additional disclosures for financial and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The guidance was effective beginning on or after January 1, 2013, and primarily impacts the disclosures associated with our commodity and interest rate derivatives. Implementation of this guidance did not have any material impact on our consolidated financial position, results of operations or cash flows. | |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Summary Of Significant Accounting Policies [Abstract] | ' | |||||||||||
Summary Of Significant Accounting Policies | ' | |||||||||||
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||
Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2012. | ||||||||||||
Earnings per Unit | ||||||||||||
Basic earnings per unit (EPU) are computed by dividing net income attributable to unitholders by the weighted average number of units outstanding during each period. At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding. Of the Class B common units, 386,579 units are restricted unvested common units granted and outstanding. | ||||||||||||
The following table presents earnings per common unit amounts (in thousands, except per unit data): | ||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Numerator: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -3,257 | $ | -10,269 | $ | -12,791 | $ | -7,262 | ||||
Loss from discontinued operations allocable to unitholders | — | -894 | -2,686 | -3,026 | ||||||||
Loss allocable to unitholders | $ | -3,257 | $ | -11,163 | $ | -15,477 | $ | -10,288 | ||||
Denominator: | ||||||||||||
Weighted average units outstanding | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 | ||||||||
Net earnings per unit: | ||||||||||||
Basic: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Diluted: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Cash | ||||||||||||
All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit reported in accounts payable at September 30, 2013, and our checks-in-transit reported in accounts payable were $0.5 million at December 31, 2012. | ||||||||||||
We have established an escrow account for $0.6 million related to a vendor dispute, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013, and December 31, 2012. This amount will remain in the escrow account until the dispute has been resolved. We also have an escrow account for approximately $1.2 million related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013. These funds will be held in escrow for a period up to twenty-four months, ending February 28, 2015, pending certain closing conditions. | ||||||||||||
Acquisition_And_Divestiture
Acquisition And Divestiture | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Acquisition And Divestiture [Abstract] | ' | |||||||||||
Acquisition And Divestiture | ' | |||||||||||
3. ACQUISITION AND DIVESTITURE | ||||||||||||
Sale of Robinson’s Bend Field Assets | ||||||||||||
On February 28, 2013, we sold our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments. We recorded a loss on the sale of approximately $3.1 million in the three months ended March 31, 2013. | ||||||||||||
Acquisition of Oil, Natural Gas and Natural Gas Liquids Properties From SEP I | ||||||||||||
On August 9, 2013, we acquired oil, natural gas and natural gas liquids assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million. In conjunction with the acquisition, SEP I received $20.1 million in cash; 1,130,512 Class A units, which represents 70.0% of the total Class A units and 4,724,407 Class B units, which represents 16.6% of the total Class B. The cash portion of the transaction was financed with cash on hand and a borrowing of $16.7 million under our reserve-based credit facility. | ||||||||||||
The acquired assets include 67 producing wells in Texas and Louisiana. The primary factors considered by management in acquiring the Sep I properties include the belief that these wells provide an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus of increasing our oil-weighted assets. The SEP I properties also provide us with access to exploitation and development potential. | ||||||||||||
The following allocation of the purchase price is preliminary and includes estimates. This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas. Management has not yet had the opportunity to complete its assessment of fair values of the assets acquired. In addition, the purchase price could change materially as management finalizes adjustments to the purchase price provided for by the purchase and sale agreement. Accordingly, the allocation may change materially as additional information becomes available and is assessed by management. | ||||||||||||
The following table summarizes the estimated values of assets acquired and liabilities assumed effective August 1, 2013 (in thousands): | ||||||||||||
1-Aug-13 | ||||||||||||
Oil and natural gas properties, equipment and facilities | $ | 30,409 | ||||||||||
Asset retirement obligation | -1,088 | |||||||||||
Net assets acquired | $ | 29,321 | ||||||||||
We will finalize the purchase price allocation within one year of the acquisition date. | ||||||||||||
We have accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of the acquisition date. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. | ||||||||||||
Results of Operations and Pro Forma Information | ||||||||||||
The following table sets forth revenues and lease operating expenses attributable to the SEP I properties acquired (in thousands): | ||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Revenue | $ | 3,936 | $ | 4,516 | $ | 12,764 | $ | 15,904 | ||||
Lease Operating Expenses | $ | 797 | $ | 1,184 | $ | 3,018 | $ | 3,795 | ||||
We have determined that the presentation of net income attributable to the SEP I properties is impracticable due to the integration of the related operations upon acquisition. | ||||||||||||
The following supplemental pro forma information presents consolidated results of operations as if the acquisition of the SEP I properties had occurred on January 1, 2012. The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of operations of SEP I. This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2012, nor is such information indicative of any expected future results of operations. | ||||||||||||
Pro Forma | Pro Forma | |||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
(In thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||
Revenue | $ | 16,067 | $ | 7,793 | $ | 45,383 | $ | 48,994 | ||||
Net Loss | $ | -1,433 | $ | -8,370 | $ | -8,569 | $ | -186 | ||||
Basic loss per unit | $ | -0.05 | $ | -0.28 | $ | -0.29 | $ | -0.01 | ||||
Diluted loss per unit | $ | -0.05 | $ | -0.28 | $ | -0.29 | $ | -0.01 | ||||
Fair_Value_Messurements
Fair Value Messurements | 9 Months Ended | ||||||||||||||
Sep. 30, 2013 | |||||||||||||||
Fair Value Measurements [Abstract] | ' | ||||||||||||||
Fair Value Measurements | ' | ||||||||||||||
4. FAIR VALUE MEASUREMENTS | |||||||||||||||
We measure certain financial assets and liabilities at fair value. Fair value is defined as an “exit price” which represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in valuing an asset or liability. The accounting guidance also requires the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize the use of unobservable inputs. As a basis for considering such assumptions and inputs, a fair value hierarchy has been established which identifies and prioritizes three levels of inputs to be used in measuring fair value. | |||||||||||||||
The three levels of the fair value hierarchy are as follows: | |||||||||||||||
Level 1 – Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities. | |||||||||||||||
Level 2 – Inputs other than the quoted prices in active markets that are observable either directly or indirectly, including: quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data. | |||||||||||||||
Level 3 – Unobservable inputs that are supported by little or no market data and require the reporting entity to develop its own assumptions. | |||||||||||||||
As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. | |||||||||||||||
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 (in thousands): | |||||||||||||||
Fair Value Measurements at September 30, 2013 | |||||||||||||||
Quoted Prices in | Significant other | ||||||||||||||
Active Markets for | Observable | Significant | |||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 30-Sep-13 | |||||||||||
Risk Mgmt Assets | $ | — | $ | 18,225 | $ | — | $ | -1,625 | $ | 16,600 | |||||
Risk Mgmt Liabilities | — | -1,625 | — | 1,625 | — | ||||||||||
Total Net Assets and Liabilities | $ | — | $ | 16,600 | $ | — | $ | — | $ | 16,600 | |||||
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 2012 | |||||||||||||||
Quoted Prices in | Significant other | ||||||||||||||
Active Markets for | Observable | Significant | |||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 31-Dec-12 | |||||||||||
Risk Mgmt Assets | $ | — | $ | 31,030 | $ | — | $ | -5,634 | $ | 25,396 | |||||
Risk Mgmt Liabilities | — | -6,794 | — | 5,634 | -1,160 | ||||||||||
Total Net Assets and Liabilities | $ | — | $ | 24,236 | $ | — | $ | — | $ | 24,236 | |||||
As of September 30, 2013, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature. | |||||||||||||||
Fair Value of Financial Instruments | |||||||||||||||
Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. | |||||||||||||||
Reserve-Based Credit Facility – We believe that the carrying value of long-term debt for our reserve-based credit facility approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. Our reserve-based credit facility is discussed further in Note 7. | |||||||||||||||
Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value. | |||||||||||||||
Derivative_And_Financial_Instr
Derivative And Financial Instruments | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Derivative And Financial Instruments [Abstract] | ' | ||||||||||||||||||||||||
Derivative And Financial Instruments | ' | ||||||||||||||||||||||||
5. DERIVATIVE AND FINANCIAL INSTRUMENTS | |||||||||||||||||||||||||
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes. | |||||||||||||||||||||||||
Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have elected to designate only a portion of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations. | |||||||||||||||||||||||||
As of September 30, 2013, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: | |||||||||||||||||||||||||
MTM Fixed Price Swaps—NYMEX (Henry Hub) | |||||||||||||||||||||||||
For the quarter ended (in MMBtu) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Average | Average | Average | Average | Average | |||||||||||||||||||||
Volume | Price | Volume | Price | Volume | Price | Volume | Price | Volume | Price | ||||||||||||||||
2013 | 1,691,540 | $ | 6.18 | 1,691,540 | $ | 6.18 | |||||||||||||||||||
2014 | 1,575,000 | $ | 5.75 | 1,592,500 | $ | 5.75 | 1,610,000 | $ | 5.75 | 1,610,000 | $ | 5.75 | 6,387,500 | $ | 5.75 | ||||||||||
2015 | 1,011,055 | $ | 4.27 | 971,604 | $ | 4.27 | 938,968 | $ | 4.27 | 908,492 | $ | 4.27 | 3,830,119 | $ | 4.27 | ||||||||||
2016 | 441,492 | $ | 4.31 | 426,825 | $ | 4.31 | 414,329 | $ | 4.31 | 403,684 | $ | 4.31 | 1,686,330 | $ | 4.31 | ||||||||||
13,595,489 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps– CenterPoint Energy Gas Transmission (East), ONEOK Gas Transportation (Oklahoma), or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas) | |||||||||||||||||||||||||
For the quarter ended (in MMBtu) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Weighted | Weighted | Weighted | Weighted | Weighted | |||||||||||||||||||||
Volume | Average $ | Volume | Average $ | Volume | Average $ | Volume | Average $ | Volume | Average $ | ||||||||||||||||
2013 | 1,223,985 | $ | 0.39 | 1,223,985 | $ | 0.39 | |||||||||||||||||||
2014 | 1,178,422 | $ | 0.39 | 1,133,022 | $ | 0.39 | 1,084,270 | $ | 0.39 | 1,047,963 | $ | 0.39 | 4,443,677 | $ | 0.39 | ||||||||||
5,667,662 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps–West Texas Intermediate (WTI) | |||||||||||||||||||||||||
For the quarter ended (in Bbls) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Average | Average | Average | Average | Average | |||||||||||||||||||||
Volume | Price | Volume | Price | Volume | Price | Volume | Price | Volume | Price | ||||||||||||||||
2013 | 65,256 | $ | 99.93 | 65,256 | $ | 99.93 | |||||||||||||||||||
2014 | 60,928 | $ | 94.64 | 57,154 | $ | 94.67 | 53,797 | $ | 94.72 | 50,597 | $ | 94.80 | 222,476 | $ | 94.70 | ||||||||||
2015 | 47,747 | $ | 90.95 | 45,065 | $ | 91.00 | 42,672 | $ | 91.04 | 40,329 | $ | 91.10 | 175,813 | $ | 91.02 | ||||||||||
2016 | 17,957 | $ | 85.50 | 16,985 | $ | 85.50 | 16,048 | $ | 85.50 | 15,127 | $ | 85.50 | 66,117 | $ | 85.50 | ||||||||||
529,662 | |||||||||||||||||||||||||
The table below outlines the classification of our derivative financial instruments on the condensed consolidated balance sheet (in thousands): | |||||||||||||||||||||||||
Fair Value of Asset/(Liability) | |||||||||||||||||||||||||
Location of Asset/(Liability) | On Balance Sheet | ||||||||||||||||||||||||
Derivative Type | On Balance Sheet | 30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets - current | $ | 13,581 | $ | 19,005 | ||||||||||||||||||||
Commodity – MTM | Risk management assets - non-current | 4,644 | 12,025 | ||||||||||||||||||||||
Total gross assets | 18,225 | 31,030 | |||||||||||||||||||||||
Commodity – MTM | Risk management assets – current | -1,385 | -1,040 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets – non-current | -240 | -946 | ||||||||||||||||||||||
Commodity – MTM | Rick management liabilities – current | — | -523 | ||||||||||||||||||||||
Commodity – MTM | Risk management liabilities – non-current | — | -637 | ||||||||||||||||||||||
Interest Rate - MTM | Risk management assets – non-current | — | -3,648 | ||||||||||||||||||||||
Total gross liabilities | -1,625 | -6,794 | |||||||||||||||||||||||
Total net assets and liabilities | $ | 16,600 | $ | 24,236 | |||||||||||||||||||||
The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): | |||||||||||||||||||||||||
Amount of Gain/(Loss) in Income | |||||||||||||||||||||||||
Location of Gain/(Loss) | For the Three Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – MTM – Unrealized | Natural gas sales | $ | -2,995 | $ | -8,746 | ||||||||||||||||||||
Commodity – MTM – Unrealized | Oil and liquids sales | -1,350 | -1,412 | ||||||||||||||||||||||
Commodity – MTM – Realized | Natural gas sales | 4,174 | 5,934 | ||||||||||||||||||||||
Commodity – MTM – Realized | Oil and liquids sales | -235 | 302 | ||||||||||||||||||||||
Interest Rate – MTM – Unrealized | Interest expense | — | 92 | ||||||||||||||||||||||
Interest Rate – MTM - Realized | Interest expense | — | -460 | ||||||||||||||||||||||
Total | $ | -406 | $ | -4,290 | |||||||||||||||||||||
Amount of Gain/(Loss) in Income | |||||||||||||||||||||||||
Location of Gain/(Loss) | For the Nine Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – MTM – Unrealized | Natural gas sales | $ | -10,124 | $ | -9,329 | ||||||||||||||||||||
Commodity – MTM – Unrealized | Oil and liquids sales | -1,160 | 876 | ||||||||||||||||||||||
Commodity – MTM – Realized | Natural gas sales | 11,448 | 19,200 | ||||||||||||||||||||||
Commodity – MTM – Realized | Oil and liquids sales | 272 | 426 | ||||||||||||||||||||||
Interest Rate – MTM – Unrealized | Interest expense | 3,648 | 697 | ||||||||||||||||||||||
Interest Rate – MTM - Realized | Interest expense | -3,713 | -1,746 | ||||||||||||||||||||||
Total | $ | 371 | $ | 10,124 | |||||||||||||||||||||
Amount of Gain/(Loss) Reclassified from | |||||||||||||||||||||||||
Location of Gain/(Loss) for | AOCI into Income – Effective | ||||||||||||||||||||||||
Effective and Ineffective | For the Three Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | Portion of Derivative in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – Cash Flow | Natural gas sales | $ | — | $ | 1,722 | ||||||||||||||||||||
Total | $ | — | $ | 1,722 | |||||||||||||||||||||
Amount of Gain/(Loss) Reclassified from | |||||||||||||||||||||||||
Location of Gain/(Loss) for | AOCI into Income – Effective | ||||||||||||||||||||||||
Effective and Ineffective | For the Nine Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | Portion of Derivative in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – Cash Flow | Natural gas sales | $ | — | $ | 4,367 | ||||||||||||||||||||
Total | $ | — | $ | 4,367 | |||||||||||||||||||||
Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with two counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. | |||||||||||||||||||||||||
We monitor the creditworthiness of our counterparties; however, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, if such changes are sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our counterparties not perform, we may not realize the benefit of some of our derivative instruments with lower commodity prices and may incur losses. We include a measure of counterparty credit risk in our estimates of the fair values of the derivative instruments in an asset position. | |||||||||||||||||||||||||
We currently use our reserve-based credit facility to provide credit support for our derivative transactions. As a result, we do not post cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with our counterparties. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from counterparties. At September 30, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant. At September 30, 2012, the impact of non-performance credit risk on the valuation of our net assets from counterparties was $0.2 million, of which $0.1 million was reflected as a decrease to our non-cash mark-to-market gain and $0.1 million was reflected in our accumulated other comprehensive loss. | |||||||||||||||||||||||||
Under the terms of our reserve-based credit facility, we have agreed to hedge 100% of our reasonably estimated projected natural gas production for 2015 and 2016. All of the required 2015 hedges are in place, and we have agreed to enter into the remaining 2016 hedges on or before December 31, 2013. In the event that the 2016 hedges are not in place by December 31, 2013, our borrowing base will automatically be reduced by the shortfall of actual hedges as compared to 50% of the reasonably estimated projected natural gas production, not to exceed an amount equal to $3.0 million times the calculated percentage of hedging shortfall. We expect to enter into the 2016 hedges prior to December 31, 2013. | |||||||||||||||||||||||||
Hedge Liquidation, Repositioning and Novation | |||||||||||||||||||||||||
In the first quarter of 2013, we liquidated or repositioned certain of our hedges. In connection with the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, we liquidated 395,218 MMbtu of NYMEX swaps in 2013 and 1,634,530 MMbtu of NYMEX swaps in 2014 at a cost of $0.3 million. In addition, we reduced our outstanding NYMEX swap positions in 2013 by 1,041,814 MMbtu by executing offsetting trades with one of our counterparties at a fixed price of $3.66. These transactions ensure that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods. We also amended a 2014 to 2015 oil trade with one of our hedge counterparties to lower the stated swap price from $98.10 to $93.50, on a total of 58,157 barrels of oil. We received proceeds of approximately $0.2 million upon execution of the amendment. The proceeds were used for working capital purposes. | |||||||||||||||||||||||||
In March 2013, we reduced our outstanding interest rate swaps that fix our LIBOR rate through 2014 to $30 million, which increased our interest rate swap settlements by $2.1 million. This position was terminated in May 2013 resulting in an offsetting non-cash gain in our mark-to-market interest swap activities. | |||||||||||||||||||||||||
Oil_And_Natural_Gas_Properties
Oil And Natural Gas Properties | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Oil And Natural Gas Properties [Abstract] | ' | |||||
Oil And Natural Gas Properties | ' | |||||
6. OIL AND NATURAL GAS PROPERTIES | ||||||
Oil and natural gas properties consisted of the following (in thousands): | ||||||
September 30, 2013 | December 31, 2012 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property (acreage) costs | ||||||
Proved property | $ | 635,993 | $ | 591,889 | ||
Unproved property | 1,487 | 1,380 | ||||
Total property costs | 637,480 | 593,269 | ||||
Materials and supplies | 846 | 771 | ||||
Land | 751 | 751 | ||||
Total | 639,077 | 594,791 | ||||
Less: Accumulated depreciation, depletion, amortization and | ||||||
impairments | -489,083 | -474,669 | ||||
Oil and natural gas properties and equipment, net | $ | 149,994 | $ | 120,122 | ||
Depletion, depreciation, amortization and impairments consisted of the following (in thousands): | ||||||
Nine Months Ended September 30, | ||||||
2013 | 2012 | |||||
DD&A of oil and natural gas-related assets | $ | 15,056 | $ | 7,078 | ||
Asset Impairments | — | 107 | ||||
Total | $ | 15,056 | $ | 7,185 | ||
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets | ||||||
For the three months ended September 30, 2013, we did not have an impairment to record. In March 2012, we recorded a total non-cash impairment charge of approximately $0.1 million to impair certain of our wells in the Woodford Shale. This impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs in the fair value hierarchy. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected oil and natural gas prices and basis differentials, anticipated production declines and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates for the properties of 10.0%. The impairment was primarily caused by the impact of lower future expected oil and natural gas prices on future expected cash flows during the first quarter of 2012. After the impairments, the remaining net capitalized costs subject to impairment in the Woodford Shale was approximately $3.6 million. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future oil and natural gas prices. These asset impairments have no impact on our cash flows, liquidity position, or debt covenants. | ||||||
Asset Sales | ||||||
On February 28, 2013, we sold our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments, and recorded a loss on the sale of approximately $3.1 million. These assets were classified as discontinued operations in the first quarter of 2013. In July 2013, we paid the purchaser $1.1 million based on the final settlement statement. See Note 13 for additional information. | ||||||
In the nine months ended September 30, 2013, we also sold miscellaneous surplus equipment for less than $0.1 million resulting in an immaterial gain on the asset sale. In the nine months ended September 30, 2012, we sold our interests in 14 gross non-operated oil wells in Kansas and Nebraska for approximately $1.4 million in cash, resulting in an immaterial loss on the asset sale. | ||||||
Debt
Debt | 9 Months Ended |
Sep. 30, 2013 | |
Debt [Abstract] | ' |
Debt | ' |
7. DEBT | |
Reserve-Based Credit Facility | |
In May 2013, we amended our existing reserve-based credit facility. This amendment increased our borrowing capacity, extended the maturity date and changed the lenders participating in the facility. | |
At September 30, 2013, we had a $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders. This reserve-based credit facility had a borrowing base of $55.0 million and matures on May 30, 2017. At September 30, 2013, we had $50.7 million in borrowings outstanding, which is reflected as a non-current liability on our balance sheet. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The lenders and their percentage commitments in the reserve-based credit facility are Societe Generale (36.36%), OneWest Bank, FSB (36.36%), and BOKF NA, dba Bank of Oklahoma (27.28%). | |
At our election, interest for borrowings is determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date. | |
The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets and make certain loans, acquisitions, capital expenditures and investments. The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production and the interest rate on our borrowings. | |
Debt Issue Costs | |
During the nine months ended September 30, 2013, we accelerated the amortization of approximately $0.7 million of debt issue costs as a result of amendments to our reserve-based credit facility. Accelerated amortization of the debt issue costs was required as the syndicate of lenders participating in the reserve-based credit facility changed. As of September 30, 2013, our unamortized debt issue costs were approximately $0.9 million. These costs are being amortized over the life of our reserve-based credit facility. | |
Funds Available for Borrowing | |
As of September 30, 2013 and 2012, we had $50.7 million and $88.4 million, respectively, in outstanding debt under our reserve-based credit facility. As of September 30, 2013, we had $4.3 million borrowing capacity available under our reserve-based credit facility. | |
Compliance with Debt Covenants | |
At September 30, 2013, we were in compliance with the financial covenants contained in our reserve-based credit facility. | |
Asset_Retirement_Obligation
Asset Retirement Obligation | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Asset Retirement Obligation [Abstract] | ' | |||||
Asset Retirement Obligations | ' | |||||
8. ASSET RETIREMENT OBLIGATION | ||||||
We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities. | ||||||
Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance. The following table is a reconciliation of the ARO (in thousands): | ||||||
September 30, | December 31, | |||||
2013 | 2012 | |||||
Asset retirement obligation, beginning balance | $ | 7,665 | $ | 7,052 | ||
Liabilities incurred | 1,254 | 162 | ||||
Liabilities settled | -3 | -8 | ||||
Accretion expense | 409 | 459 | ||||
Asset retirement obligation, ending balance | $ | 9,325 | $ | 7,665 | ||
Additional asset retirement obligations increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligations. At September 30, 2013, and December 31, 2012, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations. | ||||||
Commitments_And_Contingencies
Commitments And Contingencies | 9 Months Ended |
Sep. 30, 2013 | |
Commitments And Contingencies [Abstract] | ' |
Commitments And Contingencies | ' |
9. COMMITMENTS AND CONTINGENCIES | |
On August 30, 2013, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPM, Gary M. Pittman and John R. Collins against the Company, certain of its officers and managers, SOG and SEP I in connection with the Company’s closing on August 9, 2013 of the purchase of oil and gas properties from SEP I and the issuance of units in connection therewith. The plaintiffs contend, among other things, that the issuance of the units to SEP I in connection with the acquisition was not permitted under the Company’s operating agreement, that Messrs. Pittman and Collins should not have been removed as the Class A managers of the Company’s board of managers, and that SEP I, SOG and our current Class A managers participated in the bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs allege claims against the Company and certain of its managers and officers relating to breach of contract, breach of the duty of good faith, and breach of the implied covenant of good faith and fair dealing; the plaintiffs also allege aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers. The plaintiffs seek, among other things, declaratory relief reappointing Messrs. Pittman and Collins to the Company’s board of managers and removing our current Class A managers therefrom, and an injunction against the Company taking any further action outside the ordinary course of business during the pendency of the litigation, declaratory relief rescinding the units issued by the Company to SEP I, declaratory relief that CEPM has sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers have breached fiduciary and contractual duties and are not entitled to indemnification from the Company as a result thereof, and monetary damages. The lawsuit is currently in the discovery phase with a hearing on the plaintiff’s application for an injunction seeking to enjoin the Company’s December 5, 2013 annual meeting of unitholders scheduled for December 2, 2013, and the trial scheduled for December 16, 17 and18 in Wilmington, Delaware. The Company believes that the allegations contained in the lawsuit are without merit and intends to vigorously defend itself and its officers and managers against the claims raised in the complaint. | |
Related_Party_Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2013 | |
Related Party Transactions [Abstract] | ' |
Related Party Transations | ' |
10. RELATED PARTY TRANSACTIONS | |
Unit Ownership | |
PostRock, Exelon and SOG, through subsidiaries, own a portion of our outstanding units. As of September 30, 2013, CEPM, a subsidiary of PostRock, owned 484,505 of our Class A units and 5,918,894 of our Class B common units. CEPH, a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests as of September 30, 2013. SEP I, a subsidiary of SOG, owned 1,130,512, or 70%, of our Class A units and 4,724,407 of our Class B common units. | |
Class C Management Incentive Interests | |
CEPH, a subsidiary of Exelon, held all of the Class C management incentive interests in CEP as of September 30, 2013. These management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the Target Distribution (as defined in our operating agreement) has been achieved and certain other tests have been met. None of these applicable tests have yet to be met and CEPH has not been entitled to receive any management incentive interest distributions. | |
Compensation
Compensation | 9 Months Ended |
Sep. 30, 2013 | |
Compensation [Abstract] | ' |
Compensation | ' |
11. COMPENSATION | |
We recognized approximately $0.8 million and $1.2 million of non-cash compensation expense related to our unit-based compensation plans in the nine months ended September 30, 2013, and September 30, 2012, respectively. As of September 30, 2013, we had approximately $0.6 million in unrecognized compensation expense related to our unit-based non-cash compensation plans expected to be recognized through the first quarter of 2015. | |
In the nine months ended September 30, 2013, we incurred one-time severance costs of approximately $1.0 million. This one-time charge was reflected as general and administrative expenses and was composed of approximately $0.8 million in cash compensation expense and approximately $0.2 million in non-cash compensation expense related to accelerated vesting under our unit-based compensation plans. | |
Distributions_To_Unitholders
Distributions To Unitholders | 9 Months Ended |
Sep. 30, 2013 | |
Distributions To Unitholders [Abstract] | ' |
Distributions To Unitholders | ' |
12. DISTRIBUTIONS TO UNITHOLDERS | |
Beginning in June 2009, we suspended our quarterly distributions to unitholders. For each of the quarterly periods since June 2009, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions. | |
Members_Equity
Members' Equity | 9 Months Ended |
Sep. 30, 2013 | |
Members' Equity [Abstract] | ' |
Members' Equity | ' |
13. MEMBERS’ EQUITY | |
2013 Equity | |
At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our Long-Term Incentive Plan and 342,803 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan. | |
At September 30, 2013, we had granted 346,734 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 302,958 have vested. | |
At September 30, 2013, we had granted 1,368,227 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 1,025,424 have vested. | |
For the nine months ended September 30, 2013, 139,810 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants. | |
2012 Equity | |
At September 30, 2012, we had 483,304 Class A units and 23,681,878 Class B common units outstanding, which included 94,914 unvested restricted common units issued under our Long-Term Incentive Plan and 665,840 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan. | |
At September 30, 2012, we had granted 336,599 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 241,685 have vested. We also granted an additional 76,046 performance units under our Long-Term Incentive Plan that are subject to performance conditions which vested on January 2, 2013. | |
At September 30, 2012, we had granted 1,320,901 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 655,061 have vested. We also granted an additional 323,194 performance units under our 2009 Omnibus Incentive Compensation Plan that are subject to performance conditions which vested on January 1, 2013. | |
For the nine months ended September 30, 2012, 89,271 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants. | |
Discontinued_Operations
Discontinued Operations | 9 Months Ended |
Sep. 30, 2013 | |
Discontinued Operations [Abstract] | ' |
Discontinued Operations | ' |
14. DISCONTINUED OPERATIONS | |
On January 31, 2013, our Board of Managers authorized the sale of the two entities that owned all of our natural gas properties and inventory in the Robinson’s Bend Field in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments. On February 28, 2013, we sold all of our operations in Alabama, including our interests in 596 operated natural gas wells and all of our inventory and equipment. We received approximately $60.0 million in net cash proceeds from the buyer, subject to additional post-closing working capital and other customary adjustments. Of this amount, approximately $1.2 million is being held in escrow for a period of 24 months pending certain closing conditions, and $50.0 million was used to reduce our outstanding debt under our reserve-based credit facility. In July 2013, we paid the purchaser $1.1 million, based on post-closing adjustments. | |
During the nine months ended September 30, 2013, our discontinued operations had a net loss of $2.7 million consisting of revenues of $2.3 million, offset by expenses of $1.9 million and a loss on sale of $3.1 million. During the nine months ended September 30, 2012, our discontinued operations had a net loss of $3.0 million consisting of revenues of $9.0 million offset by expenses of $12.0 million. During the three months ended September 30, 2012, our discontinued operations had a net loss of $0.9 million consisting of revenues of $3.2 million offset by expenses of $4.1 million. At December 31, 2012, our discontinued operations had current assets of $1.9 million, long-term assets of $67.4 million, current liabilities of $1.6 million and long-term liabilities of $7.7 million. The current assets primarily represented accounts receivable for natural gas sales and the current liabilities primarily represented accounts payable and accrued liabilities. Long-term assets represented natural gas properties, equipment and facilities and the long-term liabilities represented asset retirement obligations. | |
Subsequent_Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2013 | |
Subsequent Events [Abstract] | ' |
Subsequent Events | ' |
15. SUBSEQUENT EVENTS | |
We evaluated subsequent events through the time of filing this Quarterly Report on Form 10-Q. No subsequent events occurred subsequent to the balance sheet or prior to the filing of this report that would have a material impact on our consolidated financial statements or results of operations. | |
Organization_And_Basis_Of_Pres1
Organization And Basis Of Presentation (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Organization And Basis Of Presentation [Abstract] | ' |
Basis Of Presentation | ' |
Basis of Presentation | |
These unaudited condensed consolidated financial statements include the accounts of CEP and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties. | |
These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP), have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP. | |
These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 11, 2013, and amended by Amendment No. 1 thereto filed with the SEC on April 18, 2013. | |
Use Of Estimates | ' |
Use of Estimates | |
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. | |
Reclassification | ' |
Reclassifications | |
Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no impact on the previously reported net income (loss) for any periods. | |
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policies) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Summary Of Significant Accounting Policies [Abstract] | ' | |||||||||||
Earnings per Unit | ' | |||||||||||
Earnings per Unit | ||||||||||||
Basic earnings per unit (EPU) are computed by dividing net income attributable to unitholders by the weighted average number of units outstanding during each period. At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding. Of the Class B common units, 386,579 units are restricted unvested common units granted and outstanding. | ||||||||||||
The following table presents earnings per common unit amounts (in thousands, except per unit data): | ||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Numerator: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -3,257 | $ | -10,269 | $ | -12,791 | $ | -7,262 | ||||
Loss from discontinued operations allocable to unitholders | — | -894 | -2,686 | -3,026 | ||||||||
Loss allocable to unitholders | $ | -3,257 | $ | -11,163 | $ | -15,477 | $ | -10,288 | ||||
Denominator: | ||||||||||||
Weighted average units outstanding | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 | ||||||||
Net earnings per unit: | ||||||||||||
Basic: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Diluted: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Cash | ' | |||||||||||
Cash | ||||||||||||
All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit reported in accounts payable at September 30, 2013, and our checks-in-transit reported in accounts payable were $0.5 million at December 31, 2012. | ||||||||||||
We have established an escrow account for $0.6 million related to a vendor dispute, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013, and December 31, 2012. This amount will remain in the escrow account until the dispute has been resolved. | ||||||||||||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Summary Of Significant Accounting Policies [Abstract] | ' | |||||||||||
Earnings Per Common Unit Amounts | ' | |||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Numerator: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -3,257 | $ | -10,269 | $ | -12,791 | $ | -7,262 | ||||
Loss from discontinued operations allocable to unitholders | — | -894 | -2,686 | -3,026 | ||||||||
Loss allocable to unitholders | $ | -3,257 | $ | -11,163 | $ | -15,477 | $ | -10,288 | ||||
Denominator: | ||||||||||||
Weighted average units outstanding | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 | ||||||||
Net earnings per unit: | ||||||||||||
Basic: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Diluted: | ||||||||||||
Loss from continuing operations allocable to unitholders | $ | -0.12 | $ | -0.42 | $ | -0.51 | $ | -0.3 | ||||
Loss from discontinued operations allocable to unitholders | — | -0.04 | -0.11 | -0.13 | ||||||||
Loss allocable to unitholders | $ | -0.12 | $ | -0.46 | $ | -0.62 | $ | -0.43 | ||||
Acquisition_And_Divestiture_Ta
Acquisition And Divestiture (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Acquisition And Divestiture [Abstract] | ' | |||||||||||
Estimated Values Of Assets Acquired | ' | |||||||||||
1-Aug-13 | ||||||||||||
Oil and natural gas properties, equipment and facilities | $ | 30,409 | ||||||||||
Asset retirement obligation | -1,088 | |||||||||||
Net assets acquired | $ | 29,321 | ||||||||||
Revenues And Lease Operating Expenses | ' | |||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Revenue | $ | 3,936 | $ | 4,516 | $ | 12,764 | $ | 15,904 | ||||
Lease Operating Expenses | $ | 797 | $ | 1,184 | $ | 3,018 | $ | 3,795 | ||||
Supplemental Pro Forma Information | ' | |||||||||||
Pro Forma | Pro Forma | |||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
(In thousands) | 2013 | 2012 | 2013 | 2012 | ||||||||
Revenue | $ | 16,067 | $ | 7,793 | $ | 45,383 | $ | 48,994 | ||||
Net Loss | $ | -1,433 | $ | -8,370 | $ | -8,569 | $ | -186 | ||||
Basic loss per unit | $ | -0.05 | $ | -0.28 | $ | -0.29 | $ | -0.01 | ||||
Diluted loss per unit | $ | -0.05 | $ | -0.28 | $ | -0.29 | $ | -0.01 | ||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 9 Months Ended | ||||||||||||||
Sep. 30, 2013 | |||||||||||||||
Fair Value Measurements [Abstract] | ' | ||||||||||||||
Fair Value Of Assets And Liabilities On A Recurring Basis | ' | ||||||||||||||
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 (in thousands): | |||||||||||||||
Fair Value Measurements at September 30, 2013 | |||||||||||||||
Quoted Prices in | Significant other | ||||||||||||||
Active Markets for | Observable | Significant | |||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 30-Sep-13 | |||||||||||
Risk Mgmt Assets | $ | — | $ | 18,225 | $ | — | $ | -1,625 | $ | 16,600 | |||||
Risk Mgmt Liabilities | — | -1,625 | — | 1,625 | — | ||||||||||
Total Net Assets and Liabilities | $ | — | $ | 16,600 | $ | — | $ | — | $ | 16,600 | |||||
The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 2012 | |||||||||||||||
Quoted Prices in | Significant other | ||||||||||||||
Active Markets for | Observable | Significant | |||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 31-Dec-12 | |||||||||||
Risk Mgmt Assets | $ | — | $ | 31,030 | $ | — | $ | -5,634 | $ | 25,396 | |||||
Risk Mgmt Liabilities | — | -6,794 | — | 5,634 | -1,160 | ||||||||||
Total Net Assets and Liabilities | $ | — | $ | 24,236 | $ | — | $ | — | $ | 24,236 | |||||
Derivative_And_Financial_Instr1
Derivative And Financial Instruments (Tables) | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Derivative And Financial Instruments [Abstract] | ' | ||||||||||||||||||||||||
Summary Of Hedges In Place | ' | ||||||||||||||||||||||||
MTM Fixed Price Swaps—NYMEX (Henry Hub) | |||||||||||||||||||||||||
For the quarter ended (in MMBtu) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Average | Average | Average | Average | Average | |||||||||||||||||||||
Volume | Price | Volume | Price | Volume | Price | Volume | Price | Volume | Price | ||||||||||||||||
2013 | 1,691,540 | $ | 6.18 | 1,691,540 | $ | 6.18 | |||||||||||||||||||
2014 | 1,575,000 | $ | 5.75 | 1,592,500 | $ | 5.75 | 1,610,000 | $ | 5.75 | 1,610,000 | $ | 5.75 | 6,387,500 | $ | 5.75 | ||||||||||
2015 | 1,011,055 | $ | 4.27 | 971,604 | $ | 4.27 | 938,968 | $ | 4.27 | 908,492 | $ | 4.27 | 3,830,119 | $ | 4.27 | ||||||||||
2016 | 441,492 | $ | 4.31 | 426,825 | $ | 4.31 | 414,329 | $ | 4.31 | 403,684 | $ | 4.31 | 1,686,330 | $ | 4.31 | ||||||||||
13,595,489 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps– CenterPoint Energy Gas Transmission (East), ONEOK Gas Transportation (Oklahoma), or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas) | |||||||||||||||||||||||||
For the quarter ended (in MMBtu) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Weighted | Weighted | Weighted | Weighted | Weighted | |||||||||||||||||||||
Volume | Average $ | Volume | Average $ | Volume | Average $ | Volume | Average $ | Volume | Average $ | ||||||||||||||||
2013 | 1,223,985 | $ | 0.39 | 1,223,985 | $ | 0.39 | |||||||||||||||||||
2014 | 1,178,422 | $ | 0.39 | 1,133,022 | $ | 0.39 | 1,084,270 | $ | 0.39 | 1,047,963 | $ | 0.39 | 4,443,677 | $ | 0.39 | ||||||||||
5,667,662 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps–West Texas Intermediate (WTI) | |||||||||||||||||||||||||
For the quarter ended (in Bbls) | |||||||||||||||||||||||||
March 31, | June 30, | September 30, | December 31, | Total | |||||||||||||||||||||
Average | Average | Average | Average | Average | |||||||||||||||||||||
Volume | Price | Volume | Price | Volume | Price | Volume | Price | Volume | Price | ||||||||||||||||
2013 | 65,256 | $ | 99.93 | 65,256 | $ | 99.93 | |||||||||||||||||||
2014 | 60,928 | $ | 94.64 | 57,154 | $ | 94.67 | 53,797 | $ | 94.72 | 50,597 | $ | 94.80 | 222,476 | $ | 94.70 | ||||||||||
2015 | 47,747 | $ | 90.95 | 45,065 | $ | 91.00 | 42,672 | $ | 91.04 | 40,329 | $ | 91.10 | 175,813 | $ | 91.02 | ||||||||||
2016 | 17,957 | $ | 85.50 | 16,985 | $ | 85.50 | 16,048 | $ | 85.50 | 15,127 | $ | 85.50 | 66,117 | $ | 85.50 | ||||||||||
529,662 | |||||||||||||||||||||||||
Fair Value for Risk Management Assets and Liabilities | ' | ||||||||||||||||||||||||
Fair Value of Asset/(Liability) | |||||||||||||||||||||||||
Location of Asset/(Liability) | On Balance Sheet | ||||||||||||||||||||||||
Derivative Type | On Balance Sheet | 30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets - current | $ | 13,581 | $ | 19,005 | ||||||||||||||||||||
Commodity – MTM | Risk management assets - non-current | 4,644 | 12,025 | ||||||||||||||||||||||
Total gross assets | 18,225 | 31,030 | |||||||||||||||||||||||
Commodity – MTM | Risk management assets – current | -1,385 | -1,040 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets – non-current | -240 | -946 | ||||||||||||||||||||||
Commodity – MTM | Rick management liabilities – current | — | -523 | ||||||||||||||||||||||
Commodity – MTM | Risk management liabilities – non-current | — | -637 | ||||||||||||||||||||||
Interest Rate - MTM | Risk management assets – non-current | — | -3,648 | ||||||||||||||||||||||
Total gross liabilities | -1,625 | -6,794 | |||||||||||||||||||||||
Total net assets and liabilities | $ | 16,600 | $ | 24,236 | |||||||||||||||||||||
Schedule Of Effect Of Derivative Instruments On Condensed Consolidated Statements Of Operations | ' | ||||||||||||||||||||||||
Amount of Gain/(Loss) in Income | |||||||||||||||||||||||||
Location of Gain/(Loss) | For the Three Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – MTM – Unrealized | Natural gas sales | $ | -2,995 | $ | -8,746 | ||||||||||||||||||||
Commodity – MTM – Unrealized | Oil and liquids sales | -1,350 | -1,412 | ||||||||||||||||||||||
Commodity – MTM – Realized | Natural gas sales | 4,174 | 5,934 | ||||||||||||||||||||||
Commodity – MTM – Realized | Oil and liquids sales | -235 | 302 | ||||||||||||||||||||||
Interest Rate – MTM – Unrealized | Interest expense | — | 92 | ||||||||||||||||||||||
Interest Rate – MTM - Realized | Interest expense | — | -460 | ||||||||||||||||||||||
Total | $ | -406 | $ | -4,290 | |||||||||||||||||||||
Amount of Gain/(Loss) in Income | |||||||||||||||||||||||||
Location of Gain/(Loss) | For the Nine Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – MTM – Unrealized | Natural gas sales | $ | -10,124 | $ | -9,329 | ||||||||||||||||||||
Commodity – MTM – Unrealized | Oil and liquids sales | -1,160 | 876 | ||||||||||||||||||||||
Commodity – MTM – Realized | Natural gas sales | 11,448 | 19,200 | ||||||||||||||||||||||
Commodity – MTM – Realized | Oil and liquids sales | 272 | 426 | ||||||||||||||||||||||
Interest Rate – MTM – Unrealized | Interest expense | 3,648 | 697 | ||||||||||||||||||||||
Interest Rate – MTM - Realized | Interest expense | -3,713 | -1,746 | ||||||||||||||||||||||
Total | $ | 371 | $ | 10,124 | |||||||||||||||||||||
Amount of Gain/(Loss) Reclassified from | |||||||||||||||||||||||||
Location of Gain/(Loss) for | AOCI into Income – Effective | ||||||||||||||||||||||||
Effective and Ineffective | For the Three Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | Portion of Derivative in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – Cash Flow | Natural gas sales | $ | — | $ | 1,722 | ||||||||||||||||||||
Total | $ | — | $ | 1,722 | |||||||||||||||||||||
Amount of Gain/(Loss) Reclassified from | |||||||||||||||||||||||||
Location of Gain/(Loss) for | AOCI into Income – Effective | ||||||||||||||||||||||||
Effective and Ineffective | For the Nine Months Ended September 30, | ||||||||||||||||||||||||
Derivative Type | Portion of Derivative in Income | 2013 | 2012 | ||||||||||||||||||||||
Commodity – Cash Flow | Natural gas sales | $ | — | $ | 4,367 | ||||||||||||||||||||
Total | $ | — | $ | 4,367 | |||||||||||||||||||||
Oil_And_Natural_Gas_Properties1
Oil And Natural Gas Properties (Tables) | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Oil And Natural Gas Properties [Abstract] | ' | |||||
Oil and Natural Gas Properties | ' | |||||
September 30, 2013 | December 31, 2012 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property (acreage) costs | ||||||
Proved property | $ | 635,993 | $ | 591,889 | ||
Unproved property | 1,487 | 1,380 | ||||
Total property costs | 637,480 | 593,269 | ||||
Materials and supplies | 846 | 771 | ||||
Land | 751 | 751 | ||||
Total | 639,077 | 594,791 | ||||
Less: Accumulated depreciation, depletion, amortization and | ||||||
impairments | -489,083 | -474,669 | ||||
Oil and natural gas properties and equipment, net | $ | 149,994 | $ | 120,122 | ||
Depletion, Depreciation, Amortization and Impairments | ' | |||||
Nine Months Ended September 30, | ||||||
2013 | 2012 | |||||
DD&A of oil and natural gas-related assets | $ | 15,056 | $ | 7,078 | ||
Asset Impairments | — | 107 | ||||
Total | $ | 15,056 | $ | 7,185 | ||
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 9 Months Ended | |||||
Sep. 30, 2013 | ||||||
Asset Retirement Obligation [Abstract] | ' | |||||
Reconciliation of Asset Retirement Obligation | ' | |||||
September 30, | December 31, | |||||
2013 | 2012 | |||||
Asset retirement obligation, beginning balance | $ | 7,665 | $ | 7,052 | ||
Liabilities incurred | 1,254 | 162 | ||||
Liabilities settled | -3 | -8 | ||||
Accretion expense | 409 | 459 | ||||
Asset retirement obligation, ending balance | $ | 9,325 | $ | 7,665 | ||
Recovered_Sheet1
Organization and Basis of Presentation (Details) | 0 Months Ended | 9 Months Ended |
Aug. 09, 2013 | Sep. 30, 2013 | |
Organization [Line Items] | ' | ' |
Number of business segments | ' | 1 |
Constellation Energy Partners Management [Member] | Common Class A | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | ' | 484,505 |
Constellation Energy Partners Management [Member] | Common Class B | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | ' | 5,918,894 |
Sanchez Energy Partners I [Member] | Common Class A | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | 1,130,512 | 1,130,512 |
Units owned by third party, percentage of total shares | 70.00% | 70.00% |
Sanchez Energy Partners I [Member] | Common Class B | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | 4,724,407 | 4,724,407 |
Units owned by third party, percentage of total shares | 16.60% | ' |
Recovered_Sheet2
Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 9 Months Ended | |||||||
In Millions, except Share data, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 |
Common Class A | Common Class A | Common Class A | Common Class B | Common Class B | Common Class B | |||
Class of Stock [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Common units outstanding | ' | ' | 1,615,017 | 483,418 | 483,304 | 28,463,746 | 23,687,507 | 23,681,878 |
Restricted unvested common units granted and outstanding | ' | ' | ' | ' | ' | 386,579 | ' | ' |
Checks-in-transit reported in accounts payable | $0 | $0.50 | ' | ' | ' | ' | ' | ' |
Escrow account related to vendor dispute | 0.6 | 0.6 | ' | ' | ' | ' | ' | ' |
Escrow account | $1.20 | ' | ' | ' | ' | ' | ' | ' |
Period for funds held in escrow | '24 months | ' | ' | ' | ' | ' | ' | ' |
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Summary Of Significant Accounting Policies [Abstract] | ' | ' | ' | ' |
Loss from continuing operations allocable to unitholders | ($3,257) | ($10,269) | ($12,791) | ($7,262) |
Loss from discontinued operations allocable to unitholders | ' | -894 | -2,686 | -3,026 |
Net loss | ($3,257) | ($11,163) | ($15,477) | ($10,288) |
Weighted average units outstanding | 26,888,303 | 24,169,012 | 24,840,502 | 24,171,669 |
Loss from continuing operations allocable to unitholders | ($0.12) | ($0.42) | ($0.51) | ($0.30) |
Loss from discontinued operation allocable to unitholders | ' | ($0.04) | ($0.11) | ($0.13) |
Net loss per unit-Basic | ($0.12) | ($0.46) | ($0.62) | ($0.43) |
Loss from continuing operations allocable to unitholders | ($0.12) | ($0.42) | ($0.51) | ($0.30) |
Loss from discontinued operations allocable to unitholders | ' | ($0.04) | ($0.11) | ($0.13) |
Net loss per unit-Diluted | ($0.12) | ($0.46) | ($0.62) | ($0.43) |
Acquisition_And_Divestitures_N
Acquisition And Divestitures (Narrative) (Details) (USD $) | 0 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Feb. 28, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Sep. 30, 2013 | Aug. 09, 2013 | Sep. 30, 2013 |
item | Sanchez Oil And Gas Properties [Member] | Sanchez Energy Partners I [Member] | Sanchez Energy Partners I [Member] | Sanchez Energy Partners I [Member] | Sanchez Energy Partners I [Member] | Sanchez Energy Partners I [Member] | ||||
Common Class A | Common Class A | Common Class B | Common Class B | |||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from sale of business | $63 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (Loss) on sale of business | ' | -3.1 | -3.1 | ' | ' | ' | ' | ' | ' | ' |
Purchase price for acquisition | ' | ' | ' | ' | ' | 30.4 | ' | ' | ' | ' |
Cash paid to SEP I | ' | ' | ' | ' | ' | 20.1 | ' | ' | ' | ' |
Units owned by third party | ' | ' | ' | ' | ' | ' | 1,130,512 | 1,130,512 | 4,724,407 | 4,724,407 |
Units owned by third party, percentage of total shares | ' | ' | ' | ' | ' | ' | 70.00% | 70.00% | 16.60% | ' |
Amount borrowed from reserve based credit facility | ' | ' | ' | ' | $16.70 | ' | ' | ' | ' | ' |
Number of wells acquired | ' | ' | ' | 67 | ' | ' | ' | ' | ' | ' |
Acquisition_And_Divestiture_Es
Acquisition And Divestiture (Estimated Values Of Assets Acquired) (Details) (USD $) | Sep. 30, 2013 | Aug. 01, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Acquisition And Divestiture [Abstract] | ' | ' | ' |
Oil and natural gas properties, equipment and facilities | $638,231 | $30,409 | $594,020 |
Asset retirement obligation | -9,325 | -1,088 | -7,665 |
Net assets acquired | ' | $29,321 | ' |
Acquisition_And_Divestiture_Re
Acquisition And Divestiture (Revenues And Lease Operating Expenses) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Business Acquisition [Line Items] | ' | ' | ' | ' |
Revenues | $12,131 | $3,277 | $32,619 | $33,090 |
Lease Operating Expenses | 5,191 | 4,869 | 13,332 | 14,727 |
Sanchez Oil And Gas Properties [Member] | ' | ' | ' | ' |
Business Acquisition [Line Items] | ' | ' | ' | ' |
Revenues | 3,936 | 4,516 | 12,764 | 15,904 |
Lease Operating Expenses | $797 | $1,184 | $3,018 | $3,795 |
Acquisition_And_Divestiture_Su
Acquisition And Divestiture (Supplemental Pro Forma Information) (Details) (Sanchez Oil And Gas Properties [Member], USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Sanchez Oil And Gas Properties [Member] | ' | ' | ' | ' |
Business Acquisition [Line Items] | ' | ' | ' | ' |
Revenue | $16,067 | $7,793 | $45,383 | $48,994 |
Net Loss | ($1,433) | ($8,370) | ($8,569) | ($186) |
Basic loss per unit | ($0.05) | ($0.28) | ($0.29) | ($0.01) |
Diluted loss per unit | ($0.05) | ($0.28) | ($0.29) | ($0.01) |
Fair_Value_Measurements_Fair_V
Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | $16,600 | $25,396 |
Risk Mgmt Liabilities | ' | -1,160 |
Total Net Assets and Liabilities | 16,600 | 24,236 |
Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | 18,225 | 31,030 |
Risk Mgmt Liabilities | -1,625 | -6,794 |
Total Net Assets and Liabilities | 16,600 | 24,236 |
Netting Cash And Collateral [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | -1,625 | -5,634 |
Risk Mgmt Liabilities | $1,625 | $5,634 |
Derivative_And_Financial_Instr2
Derivative And Financial Instruments (Narrative) (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2013 | Mar. 31, 2013 | Sep. 30, 2013 |
bbl | MMBTU | item | |
Derivative [Line Items] | ' | ' | ' |
Number of counterparties | ' | ' | 2 |
Impact of non-performance credit risk | ' | ' | $0.20 |
Decrease in non-cash mark-to-market gain | ' | ' | 0.1 |
Reduction in accumulated other comprehensive income | ' | ' | 0.1 |
Percentage of hedge of anticipated production volume, 2015 | ' | ' | 100.00% |
Estimated projected natural gas production | ' | ' | 3 |
Cost to liquidate derivative hedge | ' | 0.3 | ' |
Amount reduced from outstanding swap positions | ' | 1,041,814 | ' |
Derivative contract swap, fixed price | 3.66 | 3.66 | ' |
Reduction in outstanding interest rate swaps | 30 | 30 | ' |
Increase in interest rate swap settlement | 2.1 | ' | ' |
Number of barrels of oil | 58,157 | ' | ' |
Execution of amendment | $0.20 | ' | ' |
Swaps Covering 2013 NYMEX | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative swaps liquidated | ' | 395,218 | ' |
Swaps Covering 2014 NYMEX | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Derivative swaps liquidated | ' | 1,634,530 | ' |
2014 Oil Trade [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Stated swap price | 98.1 | 98.1 | ' |
2015 Oil Trade [Member] | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' |
Stated swap price | 93.5 | 93.5 | ' |
Derivative_And_Financial_Instr3
Derivative And Financial Instruments (Summary Of Hedges In Place) (Details) | 9 Months Ended |
Sep. 30, 2013 | |
MMBTU | |
NYMEX 2013 [Member] | ' |
Volume | 1,691,540 |
Average Price | 6.18 |
NYMEX 2014 [Member] | ' |
Volume | 6,387,500 |
Average Price | 5.75 |
NYMEX 2015 [Member] | ' |
Volume | 3,830,119 |
Average Price | 4.27 |
NYMEX 2016 [Member] | ' |
Volume | 1,686,330 |
Average Price | 4.31 |
NYMEX [Member] | ' |
Volume | 13,595,489 |
Centerpoint, ONEOK, Or Southern Star 2013 [Member] | ' |
Volume | 1,223,985 |
Average Price | 0.39 |
Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Volume | 4,443,677 |
Average Price | 0.39 |
Centerpoint, ONEOK, Or Southern Star [Member] | ' |
Volume | 5,667,662 |
West Texas Intermediate 2013 [Member] | ' |
Volume | 65,256 |
Average Price | 99.93 |
West Texas Intermediate 2014 [Member] | ' |
Volume | 222,476 |
Average Price | 94.7 |
West Texas Intermediate 2015 [Member] | ' |
Volume | 175,813 |
Average Price | 91.02 |
West Texas Intermediate 2016 [Member] | ' |
Volume | 66,117 |
Average Price | 85.5 |
West Texas Intermediate [Member] | ' |
Volume | 529,662 |
First Quarter [Member] | NYMEX 2014 [Member] | ' |
Volume | 1,575,000 |
Average Price | 5.75 |
First Quarter [Member] | NYMEX 2015 [Member] | ' |
Volume | 1,011,055 |
Average Price | 4.27 |
First Quarter [Member] | NYMEX 2016 [Member] | ' |
Volume | 441,492 |
Average Price | 4.31 |
First Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Volume | 1,178,422 |
Average Price | 0.39 |
First Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Volume | 60,928 |
Average Price | 94.64 |
First Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Volume | 47,747 |
Average Price | 90.95 |
First Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Volume | 17,957 |
Average Price | 85.5 |
Second Quarter [Member] | NYMEX 2014 [Member] | ' |
Volume | 1,592,500 |
Average Price | 5.75 |
Second Quarter [Member] | NYMEX 2015 [Member] | ' |
Volume | 971,604 |
Average Price | 4.27 |
Second Quarter [Member] | NYMEX 2016 [Member] | ' |
Volume | 426,825 |
Average Price | 4.31 |
Second Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Volume | 1,133,022 |
Average Price | 0.39 |
Second Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Volume | 57,154 |
Average Price | 94.67 |
Second Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Volume | 45,065 |
Average Price | 91 |
Second Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Volume | 16,985 |
Average Price | 85.5 |
Third Quarter [Member] | NYMEX 2014 [Member] | ' |
Volume | 1,610,000 |
Average Price | 5.75 |
Third Quarter [Member] | NYMEX 2015 [Member] | ' |
Volume | 938,968 |
Average Price | 4.27 |
Third Quarter [Member] | NYMEX 2016 [Member] | ' |
Volume | 414,329 |
Average Price | 4.31 |
Third Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Volume | 1,084,270 |
Average Price | 0.39 |
Third Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Volume | 53,797 |
Average Price | 94.72 |
Third Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Volume | 42,672 |
Average Price | 91.04 |
Third Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Volume | 16,048 |
Average Price | 85.5 |
Fourth Quarter [Member] | NYMEX 2013 [Member] | ' |
Volume | 1,691,540 |
Average Price | 6.18 |
Fourth Quarter [Member] | NYMEX 2014 [Member] | ' |
Volume | 1,610,000 |
Average Price | 5.75 |
Fourth Quarter [Member] | NYMEX 2015 [Member] | ' |
Volume | 908,492 |
Average Price | 4.27 |
Fourth Quarter [Member] | NYMEX 2016 [Member] | ' |
Volume | 403,684 |
Average Price | 4.31 |
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2013 [Member] | ' |
Volume | 1,223,985 |
Average Price | 0.39 |
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Volume | 1,047,963 |
Average Price | 0.39 |
Fourth Quarter [Member] | West Texas Intermediate 2013 [Member] | ' |
Volume | 65,256 |
Average Price | 99.93 |
Fourth Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Volume | 50,597 |
Average Price | 94.8 |
Fourth Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Volume | 40,329 |
Average Price | 91.1 |
Fourth Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Volume | 15,127 |
Average Price | 85.5 |
Derivative_And_Financial_Instr4
Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management assets-current | $12,196 | $17,965 |
Risk management assets-non-current | 4,404 | 7,431 |
Total gross assets | 18,225 | 31,030 |
Risk management liabilities-current | ' | -523 |
Risk management liabilities-non-current | ' | -637 |
Total gross liabilities | -1,625 | -6,794 |
Total net assets and liabilities | 16,600 | 24,236 |
Risk Management Commodity [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management assets-current | 13,581 | 19,005 |
Risk management assets-non-current | 4,644 | 12,025 |
Risk management liabilities-current | ' | -523 |
Risk management liabilities-non-current | ' | -637 |
Current Assets [Member] | Risk Management Commodity [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management liabilities-current | -1,385 | -1,040 |
Noncurrent Assets [Member] | Risk Management Commodity [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management liabilities-non-current | -240 | -946 |
Noncurrent Assets [Member] | Risk Management Interest Rate [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management liabilities-non-current | ' | ($3,648) |
Derivative_And_Financial_Instr5
Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | ($406) | ($4,290) | $371 | $10,124 |
Natural Gas Sales [Member] | Unrealized Commodity [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | -2,995 | -8,746 | -10,124 | -9,329 |
Natural Gas Sales [Member] | Realized Commodity [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | 4,174 | 5,934 | 11,448 | 19,200 |
Oil And Liquids Sales [Member] | Unrealized Commodity [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | -1,350 | -1,412 | -1,160 | 876 |
Oil And Liquids Sales [Member] | Realized Commodity [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | -235 | 302 | 272 | 426 |
Interest Expense [Member] | Unrealized Interest Rate [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | ' | 92 | 3,648 | 697 |
Interest Expense [Member] | Realized Interest Rate [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Derivative gains (losses) recognized in income | ' | ($460) | ($3,713) | ($1,746) |
Derivative_And_Financial_Instr6
Derivative And Financial Instruments (Fair Value Disclosures Applicable to Income Statement Reclassified) (Details) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ' | ' | ' | ' |
Amount of gain/ (loss) Reclassified from AOCI Income | '$- | '$1,722 | '$- | '$4,367 |
Commodity - Cash Flow [Member] | Natural Gas Sales [Member] | ' | ' | ' | ' |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ' | ' | ' | ' |
Amount of gain/ (loss) Reclassified from AOCI Income | '$- | '$1,722 | '$- | '$4,367 |
Recovered_Sheet3
Oil and Natural Gas Properties (Narrative) (Details) (USD $) | 0 Months Ended | 3 Months Ended | 9 Months Ended | 1 Months Ended | 0 Months Ended | ||
Feb. 28, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Mar. 31, 2012 | Feb. 28, 2013 | Jul. 31, 2013 | |
item | Woodford Shale | Robinson's Bend Field [Member] | Robinson's Bend Field [Member] | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Asset impairments | ' | ' | ' | $107,000 | ' | ' | ' |
Non-cash impairment charges | ' | ' | ' | ' | 100,000 | ' | ' |
Cash flow estimates of discount rate | ' | ' | ' | ' | 10.00% | ' | ' |
Capitalized cost subject to impairment | ' | ' | ' | ' | 3,600,000 | ' | ' |
Proceeds from sale of business | 63,000,000 | ' | ' | ' | ' | 63,000,000 | ' |
Gain (Loss) on sale | ' | -3,100,000 | -3,100,000 | ' | ' | -3,100,000 | ' |
Amount paid to purchased based on final settlement statement | ' | ' | ' | ' | ' | 1,200,000 | 1,100,000 |
Proceeds from sale of assets | ' | ' | 100,000 | ' | ' | ' | ' |
Number of gross non-operated oil wells sold | ' | ' | ' | 14 | ' | ' | ' |
Proceed from sale of interest of non-operated oil wells | ' | ' | ' | $1,400,000 | ' | ' | ' |
Recovered_Sheet4
Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Oil And Natural Gas Properties [Abstract] | ' | ' |
Proved property | $635,993 | $591,889 |
Unproved property | 1,487 | 1,380 |
Total property costs | 637,480 | 593,269 |
Materials and supplies | 846 | 771 |
Land | 751 | 751 |
Total | 639,077 | 594,791 |
Less: Accumulated depreciation, depletion, amortization and impairments | -489,083 | -474,669 |
Oil and natural gas properties and equipment, net | $149,994 | $120,122 |
Oil_And_Natural_Gas_Properties2
Oil And Natural Gas Properties (Depletion, Depreciation, Amortization and Impairments) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Oil And Natural Gas Properties [Abstract] | ' | ' | ' | ' |
DD&A of oil and natural gas-related assets | $5,491 | $2,373 | $15,056 | $7,078 |
Asset Impairments | ' | ' | ' | 107 |
Total | ' | ' | $15,056 | $7,185 |
Debt_Details
Debt (Details) (USD $) | 9 Months Ended | ||
Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | |
Line of Credit Facility [Line Items] | ' | ' | ' |
Commitment fee on unutilized borrowing base | 0.50% | ' | ' |
Amortization of Debt Issuance Costs | $700,000 | ' | ' |
Unamortized debt issue costs | 900,000 | ' | ' |
Outstanding debt under reserve-based credit facility | 50,700,000 | 34,000,000 | 88,400,000 |
Remaining borrowing capacity | 4,300,000 | ' | ' |
Societe Generale [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
Reserve based credit facility maximum borrowing capacity | 350,000,000 | ' | ' |
Borrowing base amount | 55,000,000 | ' | ' |
Maturity date of reserve-based credit facility | 30-May-17 | ' | ' |
Outstanding debt on our reserve based credit facility | $50,700,000 | ' | ' |
Commitment fee percentage | 36.36% | ' | ' |
OneWest Bank [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
Commitment fee percentage | 36.36% | ' | ' |
Bank of Oklahoma [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
Commitment fee percentage | 27.28% | ' | ' |
Minimum | London Interbank Offered Rate (LIBOR) [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
LIBOR limit | 2.50% | ' | ' |
Minimum | ABR [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
LIBOR limit | 1.50% | ' | ' |
Maximum | London Interbank Offered Rate (LIBOR) [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
LIBOR limit | 3.50% | ' | ' |
Maximum | ABR [Member] | ' | ' | ' |
Line of Credit Facility [Line Items] | ' | ' | ' |
LIBOR limit | 2.50% | ' | ' |
Asset_Retirement_Obligation_Na
Asset Retirement Obligation (Narrative) (Details) (USD $) | 9 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation [Abstract] | ' | ' |
Expenditures for abandonment | $0 | $0 |
Legally restricted assets | $0 | $0 |
Asset_Retirement_Obligation_Re
Asset Retirement Obligation (Reconciliation of Asset Retirement Obligation) (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Asset Retirement Obligation [Abstract] | ' | ' | ' | ' | ' |
Asset retirement obligation, beginning balance | ' | ' | $7,665 | $7,052 | $7,052 |
Liabilities incurred | ' | ' | 1,254 | ' | 162 |
Liabilities settled | ' | ' | -3 | ' | -8 |
Accretion expense | 163 | 116 | 409 | 345 | 459 |
Asset retirement obligation, ending balance | $9,325 | ' | $9,325 | ' | $7,665 |
Related_Party_Transactions_Det
Related Party Transactions (Details) | 0 Months Ended | 9 Months Ended |
Aug. 09, 2013 | Sep. 30, 2013 | |
Related Party Transaction [Line Items] | ' | ' |
Incentive interest received as percentage of quarterly distributions | ' | 15.00% |
Constellation Energy Partners Management [Member] | Common Class A | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Units owned by third party | ' | 484,505 |
Constellation Energy Partners Management [Member] | Common Class B | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Units owned by third party | ' | 5,918,894 |
Sanchez Energy Partners I [Member] | Common Class A | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Units owned by third party | 1,130,512 | 1,130,512 |
Units owned by third party, percentage of total shares | 70.00% | 70.00% |
Sanchez Energy Partners I [Member] | Common Class B | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Units owned by third party | 4,724,407 | 4,724,407 |
Units owned by third party, percentage of total shares | 16.60% | ' |
Compensation_Details
Compensation (Details) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ' | ' |
Non-cash compensation expense | $0.80 | $1.20 |
Unrecognized portion of share based compensation expense | 0.6 | ' |
Severance costs | 1 | ' |
General and Administrative Expense [Member] | ' | ' |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | ' | ' |
Non-cash compensation expense | 0.2 | ' |
Cash compensation expense | $0.80 | ' |
Members_Equity_Details
Members' Equity (Details) (USD $) | 9 Months Ended | |||||||||||
In Thousands, except Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 |
Long Term Incentive Plan | Long Term Incentive Plan | 2009 Omnibus Incentive Compensation Plan | 2009 Omnibus Incentive Compensation Plan | Common Class A | Common Class A | Common Class A | Common Class B | Common Class B | Common Class B | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares units outstanding | ' | ' | ' | ' | ' | ' | 1,615,017 | 483,418 | 483,304 | 28,463,746 | 23,687,507 | 23,681,878 |
Unvested restricted common stock issued | ' | ' | 43,776 | 94,914 | 342,803 | 665,840 | ' | ' | ' | ' | ' | ' |
Common units granted | ' | ' | 346,734 | 336,599 | 1,368,227 | 1,320,901 | ' | ' | ' | ' | ' | ' |
Common units available under incentive plan | ' | ' | 450,000 | 450,000 | 1,650,000 | 1,650,000 | ' | ' | ' | ' | ' | ' |
Common units vested | ' | ' | 302,958 | 241,685 | 1,025,424 | 655,061 | ' | ' | ' | ' | ' | ' |
Additional units granted | ' | ' | ' | 76,046 | ' | 323,194 | ' | ' | ' | ' | ' | ' |
Common units tendered for tax withholding purpose | 139,810 | 89,271 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Units tendered by employees for tax withholding, cost | $185 | $200 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Discontinued_Operations_Detail
Discontinued Operations (Details) (USD $) | 0 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | ||||||
Feb. 28, 2013 | Mar. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Aug. 09, 2013 | Dec. 31, 2012 | Feb. 28, 2013 | Jul. 31, 2013 | Jan. 31, 2013 | |
item | Robinson's Bend Field [Member] | Robinson's Bend Field [Member] | Robinson's Bend Field [Member] | |||||||
item | entity | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of entities sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 |
Proceeds from sale of business | $63,000,000 | ' | ' | ' | ' | ' | ' | $63,000,000 | ' | ' |
Net cash proceeds from sale of business | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' |
Number of operated natural gas wells | ' | ' | ' | ' | ' | 67 | ' | 596 | ' | ' |
Amount held in escrow | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | 1,100,000 | ' |
Escrow period | ' | ' | ' | ' | ' | ' | ' | '24 months | ' | ' |
Amount held in escrow used to reduce the debt under reserve based credit facility | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' |
Discontinued operations net loss | ' | ' | -894,000 | -2,686,000 | -3,026,000 | ' | ' | ' | ' | ' |
Discontinued operations, revenues | ' | ' | 3,200,000 | 2,300,000 | 9,000,000 | ' | ' | ' | ' | ' |
Discontinued operations, expenses | ' | ' | 4,100,000 | 1,900,000 | 12,000,000 | ' | ' | ' | ' | ' |
Gain (Loss) on sale | ' | -3,100,000 | ' | -3,100,000 | ' | ' | ' | -3,100,000 | ' | ' |
Discontinued operations, Current Assets | ' | ' | ' | ' | ' | ' | 1,886,000 | ' | ' | ' |
Discontinued operations, Long-term assets | ' | ' | ' | ' | ' | ' | 67,373,000 | ' | ' | ' |
Discontinued operations, Current Liabilities | ' | ' | ' | ' | ' | ' | 1,578,000 | ' | ' | ' |
Discontinued operations, Long term liabilities | ' | ' | ' | ' | ' | ' | $7,692,000 | ' | ' | ' |