Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2014 | 9-May-14 | |
Document And Entity Information [Abstract] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 31-Mar-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
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_Stateme
Condensed Consolidated Statements Of Operations And Comprehensive Income (Loss) (USD $) | 3 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Revenues | ' | ' |
Natural gas sales | $6,024 | $1,392 |
Oil and liquids sales | 5,717 | 3,708 |
Total revenues (See Note 5) | 11,741 | 5,100 |
Operating expenses: | ' | ' |
Lease operating expenses | 5,120 | 4,236 |
Cost of sales | 360 | 420 |
Production taxes | 772 | 487 |
General and administrative | 3,571 | 4,404 |
Gain on sale of assets | -7 | -6 |
Depreciation, depletion and amortization | 4,050 | 4,798 |
Asset impairments | 149 | ' |
Accretion expense | 150 | 123 |
Total operating expenses | 14,165 | 14,462 |
Other expense (income) | ' | ' |
Interest expense | 525 | 1,352 |
Other income | -10 | -68 |
Total other expenses | 515 | 1,284 |
Total expenses | 14,680 | 15,746 |
Loss from continuing operations | -2,939 | -10,646 |
Loss from discontinued operations | ' | -2,686 |
Net loss | -2,939 | -13,332 |
Weighted Average Units Outstanding | ' | ' |
Weighted Average Units Outstanding - Basic and diluted | 29,829,121 | 24,250,662 |
Distributions declared and paid per unit | ' | ' |
Common Class A [Member] | ' | ' |
Other expense (income) | ' | ' |
Loss from continuing operations | ' | -213 |
Loss from discontinued operations | ' | -54 |
Net loss | -59 | -267 |
Loss from continuing operations per unit | ' | ' |
Loss from continuing operations per unit - Basic and diluted | ($0.04) | ($0.44) |
Discontinued operations per unit | ' | ' |
Discontinued operations per unit - Basic and diluted | ' | ($0.11) |
Net loss per unit | ' | ' |
Net loss per unit - Basic and diluted | ($0.04) | ($0.55) |
Weighted Average Units Outstanding | ' | ' |
Weighted Average Units Outstanding - Basic and diluted | 1,615,017 | 484,396 |
Common Class B [Member] | ' | ' |
Other expense (income) | ' | ' |
Loss from continuing operations | ' | -10,433 |
Loss from discontinued operations | ' | -2,632 |
Net loss | ($2,880) | ($13,065) |
Loss from continuing operations per unit | ' | ' |
Loss from continuing operations per unit - Basic and diluted | ($0.10) | ($0.44) |
Discontinued operations per unit | ' | ' |
Discontinued operations per unit - Basic and diluted | ' | ($0.11) |
Net loss per unit | ' | ' |
Net loss per unit - Basic and diluted | ($0.10) | ($0.55) |
Weighted Average Units Outstanding | ' | ' |
Weighted Average Units Outstanding - Basic and diluted | 28,214,104 | 23,766,266 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets | ' | ' |
Cash and cash equivalents | $8,626 | $4,894 |
Restricted cash (See Note 2) | 1,748 | ' |
Accounts receivable, net (See Note 2) | 9,715 | 6,678 |
Prepaid expenses | 1,169 | 2,547 |
Risk management assets (See Note 5) | 4,444 | 9,141 |
Total current assets | 25,702 | 23,260 |
Oil and natural gas properties (See Note 6) | ' | ' |
Oil and natural gas properties, equipment and facilities | 641,540 | 639,156 |
Material and supplies | 1,057 | 1,054 |
Less accumulated depreciation, depletion, amortization, and impairments | -499,321 | -495,215 |
Net oil and natural gas properties | 143,276 | 144,995 |
Other assets | ' | ' |
Debt issue costs (net of accumulated amortization of $9,062 and $9,003, respectively) | 765 | 824 |
Risk management assets (See Note 5) | 1,161 | 1,461 |
Restricted cash (See Note 2) | ' | 1,748 |
Other non-current assets | 2,062 | 2,245 |
Total assets | 172,966 | 174,533 |
Current liabilities | ' | ' |
Accounts payable | 453 | 12 |
Accrued liabilities | 14,137 | 12,763 |
Royalty payable | 1,505 | 1,242 |
Total current liabilities | 16,095 | 14,017 |
Other liabilities | ' | ' |
Asset retirement obligation | 9,681 | 9,513 |
Other non-current liabilities | 1,398 | 1,398 |
Debt (See Note 7) | 50,700 | 50,700 |
Total other liabilities | 61,779 | 61,611 |
Total liabilities | 77,874 | 75,628 |
Commitments and contingencies (See Note 9) | ' | ' |
Members' equity | ' | ' |
Total members' equity | 95,092 | 98,905 |
Total liabilities and members' equity | 172,966 | 174,533 |
Common Class A [Member] | ' | ' |
Members' equity | ' | ' |
Limited partners' capital account | 1,714 | 2,591 |
Common Class B [Member] | ' | ' |
Members' equity | ' | ' |
Limited partners' capital account | $93,378 | $96,314 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Debt issue costs, accumulated amortization | $9,062 | $9,003 |
Common Class A [Member] | ' | ' |
Share units authorized | 1,615,017 | 1,615,017 |
Share units issued | 1,615,017 | 1,615,017 |
Shares units outstanding | 1,615,017 | 1,615,017 |
Common Class B [Member] | ' | ' |
Share units authorized | 28,848,785 | 28,848,785 |
Share units issued | 28,399,502 | 28,462,185 |
Shares units outstanding | 28,399,502 | 28,462,185 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements Of Cash Flows (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Cash flows from operating activities: | ' | ' |
Net loss | ($2,939) | ($13,332) |
Adjustments to reconcile net loss to cash provided by operating activities | ' | ' |
Depreciation, depletion and amortization | 4,050 | 4,798 |
Asset impairments (See Note 6) | 149 | ' |
Amortization of debt issuance costs | 59 | 646 |
Accretion expense | 150 | 123 |
Equity earnings in affiliate | -12 | -68 |
Gain from disposition of property and equipment | -7 | -6 |
Bad debt expense | 93 | ' |
Mark-to-market on derivatives: | ' | ' |
Total gains | 4,074 | 4,625 |
Cash settlements | 923 | 1,996 |
Unit-based compensation programs | 101 | 401 |
Discontinued operations | ' | 2,686 |
Changes in Assets and Liabilities: | ' | ' |
(Increase) decrease in accounts receivable | -3,181 | 1,168 |
Decrease in prepaid expenses | 1,378 | 163 |
(Increase) decrease in other assets | 2 | -1,149 |
Increase (decrease) in accounts payable | 441 | -429 |
Increase (decrease) in accrued liabilities | 918 | -2,060 |
Increase (decrease) in royalty payable | 263 | -220 |
Increase in other liabilities | ' | 1,113 |
Net cash provided by continuing operations | 6,462 | 455 |
Net cash provided by discontinued operations | ' | 1,062 |
Net cash provided by operating activities | 6,462 | 1,517 |
Cash flows from investing activities: | ' | ' |
Cash paid for acquisitions, net of cash acquired | ' | -130 |
Development of oil and natural gas properties | -2,731 | -2,353 |
Proceeds from sale of assets | 58 | 58,892 |
Distributions from equity affiliate | 100 | 20 |
Net cash provided by (used in) continuing operations | -2,573 | 56,429 |
Net cash used in discontinued operations | ' | ' |
Net cash provided by (used in) investing activities | -2,573 | 56,429 |
Cash flows from financing activities: | ' | ' |
Proceeds from issuance of debt | ' | 194 |
Repayment of debt | ' | -50,194 |
Units tendered by employees for tax withholdings | -157 | -185 |
Debt issue costs | ' | -42 |
Net cash used in continuing operations | -157 | -50,227 |
Net cash used in discontinued operations | ' | ' |
Net cash used in financing activities | -157 | -50,227 |
Net increase in cash and cash equivalents | 3,732 | 7,719 |
Cash and cash equivalents, beginning of period | 4,894 | 1,959 |
Cash and cash equivalents, end of period | 8,626 | 9,678 |
Supplemental disclosures of cash flow information: | ' | ' |
Change in accrued capital expenditures | -361 | -1,321 |
Accrual for cancellation of Class A units | 818 | ' |
Cash paid during the period for interest | -478 | -678 |
Cash paid during the period for income taxes | ($2) | ' |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements of Changes In Members' Equity (USD $) | Common Class A [Member] | Common Class B [Member] | Accumulated Other Comprehensive Income [Member] | Total |
In Thousands, except Share data | ||||
Beginning Balance at Dec. 31, 2013 | $2,591 | $96,314 | ' | $98,905 |
Beginning Balance (in shares) at Dec. 31, 2013 | 1,615,017 | 28,462,185 | ' | ' |
Distributions | ' | ' | ' | ' |
Units tendered by employees for tax withholding (in shares) | ' | -62,683 | ' | ' |
Units tendered by employees for tax withholding | ' | -157 | ' | -157 |
Unit-based compensation programs | ' | 101 | ' | 101 |
Cancellation of units (See Note 9) | -818 | ' | ' | -818 |
Net loss | -59 | -2,880 | ' | -2,939 |
Ending Balance at Mar. 31, 2014 | $1,714 | $93,378 | ' | $95,092 |
Ending Balance (in shares) at Mar. 31, 2014 | 1,615,017 | 28,399,502 | ' | ' |
Organization_And_Basis_Of_Pres
Organization And Basis Of Presentation | 3 Months Ended |
Mar. 31, 2014 | |
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 March 31, 2014, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 484,505, or 30%, 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, 2013, which was filed with the SEC on March 27, 2014. | |
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 reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities. | |
Discontinued Operations | |
In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama. The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the three months ended March 31, 2013. Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 3. Acquisition and Divestiture. | |
New Accounting Pronouncements | |
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. | |
In December 2011, the 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 | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
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, 2013. | ||||||||||
Earnings per Unit | ||||||||||
Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) is allocated to each class with the Class A units receiving 2% and the Class B units receiving 98%. | ||||||||||
As of March 31, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities. These units will be considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities. | ||||||||||
The following table presents our calculation of basic and diluted units outstanding for the periods indicated: | ||||||||||
Three Months Ended March 31, | ||||||||||
2014 | 2013 | |||||||||
Weighted average units outstanding during period: | ||||||||||
Class A units - Basic and Diluted | 1,615,017 | 484,396 | ||||||||
Class B Common units - Basic and Diluted | 28,214,104 | 23,766,266 | ||||||||
29,829,121 | 24,250,662 | |||||||||
At March 31, 2014, we had 129,537 Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number. | ||||||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2014 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -2,939 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed net loss to be allocated | $ | -2,939 | $ | -59 | $ | -2,880 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.1 | ||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2013 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -10,646 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed allocation of loss from continuing operations | -10,646 | -213 | -10,433 | |||||||
Discontinued operations | -2,686 | -54 | -2,632 | |||||||
Assumed net loss to be allocated | $ | -13,332 | $ | -267 | $ | -13,065 | ||||
Basic and diluted loss from continuing operations per unit | $ | -0.44 | $ | -0.44 | ||||||
Basic and diluted loss from discontinued operations per unit | $ | -0.11 | $ | -0.11 | ||||||
Basic and diluted loss per unit | $ | -0.55 | $ | -0.55 | ||||||
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 March 31, 2014 and December 31, 2013. | ||||||||||
Restricted Cash | ||||||||||
Restricted cash, at March 31, 2014 and December 31, 2013, of $1.7 million was being held in escrow. Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. These funds will remain in escrow for a period ending February 28, 2015, pending certain post-closing conditions. The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at March 31, 2014, based on the conditions of the cash held in the account. | ||||||||||
Accounts Receivable, Net | ||||||||||
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. At March 31, 2014 and 2013, we had an allowance for doubtful accounts receivable of $0.2 million and $0.1 million, respectively. | ||||||||||
Acquisition_And_Divestiture
Acquisition And Divestiture | 3 Months Ended | |||
Mar. 31, 2014 | ||||
Acquisition And Divestiture [Abstract] | ' | |||
Acquisition And Divestiture | ' | |||
3. ACQUISITION AND DIVESTITURE | ||||
Sale of Robinson’s Bend Field Assets | ||||
On February 28, 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments that amounted to approximately $4.0 million. We recorded a loss on the sale of approximately $3.1 million in the three months ended March 31, 2013. The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt. | ||||
The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the condensed consolidated statements of operations for the three months ended March 31, 2013 (in thousands): | ||||
Three Months Ended | ||||
31-Mar-13 | ||||
Revenues | $ | 2,304 | ||
Loss from discontinued operations | $ | -2,686 | ||
See Note 2 for information regarding earnings per unit, including earnings per unit data relating to loss from discontinued operations. | ||||
The condensed consolidated statements of cash flows reflect discontinued operations for 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 NGLs 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 represented 70.0% of the total Class A units outstanding as of such date, and 4,724,407 Class B units, which represented 16.6% of the total Class B units outstanding as of such date. 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. | ||||
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 | $ | 31,497 | ||
Asset retirement obligation | -1,088 | |||
Net assets acquired | $ | 30,409 | ||
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. | ||||
Pro Forma Information | ||||
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, 2013. 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, 2013, nor is such information indicative of any expected future results of operations. | ||||
Pro Forma | ||||
Three Months Ended | ||||
(In thousands) | 31-Mar-13 | |||
Revenue | $ | 9,648 | ||
Loss from continuing operations | $ | -7,729 | ||
Discontinued operations | $ | -2,686 | ||
Net Loss | $ | -10,415 | ||
Loss from continuing operations per unit | ||||
Class A units - Basic and diluted | $ | -0.1 | ||
Class B units - Basic and diluted | $ | -0.27 | ||
Discontinued operations per unit | ||||
Class A units - Basic and diluted | $ | -0.03 | ||
Class B units - Basic and diluted | $ | -0.09 | ||
Net loss per unit | ||||
Class A units - Basic and diluted | $ | -0.13 | ||
Class B units - Basic and diluted | $ | -0.36 | ||
Weighted average units outstanding | ||||
Class A units - Basic and diluted | 1,614,908 | |||
Class B units - Basic and diluted | 28,490,673 | |||
Fair_Value_Messurements
Fair Value Messurements | 3 Months Ended | ||||||||||||||
Mar. 31, 2014 | |||||||||||||||
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 March 31, 2014 (in thousands): | |||||||||||||||
Fair Value Measurements at March 31, 2014 | |||||||||||||||
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-Mar-14 | |||||||||||
Risk Management Assets | $ | - | $ | 7,144 | $ | - | $ | -1,539 | $ | 5,605 | |||||
Risk Management Liabilities | - | -1,539 | - | 1,539 | - | ||||||||||
Total Net Assets and Liabilities | $ | - | $ | 5,605 | $ | - | $ | - | $ | 5,605 | |||||
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, 2013 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 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 | 31-Dec-13 | |||||||||||
Risk Management Assets | $ | - | $ | 11,577 | $ | - | $ | -975 | $ | 10,602 | |||||
Risk Management Liabilities | - | -975 | - | 975 | - | ||||||||||
Total Net Assets and Liabilities | $ | - | $ | 10,602 | $ | - | $ | - | $ | 10,602 | |||||
As of March 31, 2014, 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 | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
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 not elected to designate any 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 March 31, 2014, 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 | ||||||||||||||||
2014 | 1,592,500 | $ | 5.75 | 1,610,000 | $ | 5.75 | 1,610,000 | $ | 5.75 | 4,812,500 | $ | 5.75 | |||||||||||||
2015 | 1,215,420 | $ | 4.25 | 1,153,487 | $ | 4.25 | 1,096,023 | $ | 4.26 | 1,050,219 | $ | 4.26 | 4,515,149 | $ | 4.25 | ||||||||||
2016 | 1,010,633 | $ | 4.21 | 967,290 | $ | 4.21 | 923,541 | $ | 4.21 | 893,568 | $ | 4.22 | 3,795,032 | $ | 4.21 | ||||||||||
13,122,681 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps– Enable Gas Transmission, LLC (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 $ | ||||||||||||||||
2014 | 1,133,022 | $ | 0.39 | 1,084,270 | $ | 0.39 | 1,047,963 | $ | 0.39 | 3,265,255 | $ | 0.39 | |||||||||||||
3,265,255 | |||||||||||||||||||||||||
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 | ||||||||||||||||
2014 | 57,154 | $ | 94.67 | 53,797 | $ | 94.72 | 50,597 | $ | 94.80 | 161,548 | $ | 94.73 | |||||||||||||
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 | ||||||||||
403,478 | |||||||||||||||||||||||||
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 | 31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets - current | $ | 5,837 | $ | 10,043 | ||||||||||||||||||||
Commodity – MTM | Risk management assets - non-current | 1,308 | 1,534 | ||||||||||||||||||||||
Total gross assets | 7,145 | 11,577 | |||||||||||||||||||||||
Commodity – MTM | Risk management assets – current | -1,393 | -902 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets – non-current | -147 | -73 | ||||||||||||||||||||||
Total gross liabilities | -1,540 | -975 | |||||||||||||||||||||||
Total net assets and liabilities | $ | 5,605 | $ | 10,602 | |||||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||
Derivative Type | in Income | 2014 | 2013 | ||||||||||||||||||||||
Commodity – Mark-to-Market | Oil and natural gas sales | $ | -4,074 | $ | -4,580 | ||||||||||||||||||||
Interest Rate – Mark-to-Market | Interest expense | - | -45 | ||||||||||||||||||||||
Total | $ | -4,074 | $ | -4,625 | |||||||||||||||||||||
There were no gains or losses reclassified from accumulated other comprehensive income into income during the three months ended March 31, 2014 or 2013. | |||||||||||||||||||||||||
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 March 31, 2014 and December 31, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant, and the entire amount was reflected as a decrease to our non-cash mark-to-market gain, respectively. | |||||||||||||||||||||||||
We entered into new swap agreements to hedge an additional portion of our future oil production on April 29, 2014. See Note 14 for further discussion. | |||||||||||||||||||||||||
Hedge Liquidation and Repositioning | |||||||||||||||||||||||||
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 per Mcf. 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 per barrel, 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 | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
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): | ||||||
March 31, 2014 | December 31, 2013 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property (acreage) costs | ||||||
Proved property | $ | 639,141 | $ | 636,816 | ||
Unproved property | 1,648 | 1,589 | ||||
Total property costs | 640,789 | 638,405 | ||||
Materials and supplies | 1,057 | 1,054 | ||||
Land | 751 | 751 | ||||
Total | 642,597 | 640,210 | ||||
Less: Accumulated depreciation, depletion, amortization and impairments | -499,321 | -495,215 | ||||
Oil and natural gas properties and equipment, net | $ | 143,276 | $ | 144,995 | ||
Depreciation, depletion, amortization and impairments consisted of the following (in thousands): | ||||||
Three Months Ended March 31, | ||||||
2014 | 2013 | |||||
DD&A of oil and natural gas-related assets | $ | 4,050 | $ | 4,798 | ||
Asset Impairments | 149 | - | ||||
Total | $ | 4,199 | $ | 4,798 | ||
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets | ||||||
For the three months ended March 31, 2014, our non-cash impairment charges were approximately $0.1 million to impair the value of our oil and natural gas fields in Texas and Louisiana, and for the three months ended March 31, 2013, we did not have an impairment to record. The 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. | ||||||
Asset Sales | ||||||
During each of the three-month periods ended March 31, 2014 and March 31, 2013, we sold miscellaneous surplus equipment for less than $0.1 million resulting in an immaterial gain on the asset sales. | ||||||
Useful Lives | ||||||
Our furniture, fixtures and equipment are depreciated over a life of one to seven years, buildings are depreciated over a life of 20 years and pipeline and gathering systems are depreciated over a life of 25 to 40 years. | ||||||
Exploration and Dry Hole Costs | ||||||
We recorded no exploration and dry hole costs for the three months ended March 31, 2014 and 2013, respectively. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties. | ||||||
Debt
Debt | 3 Months Ended |
Mar. 31, 2014 | |
Debt [Abstract] | ' |
Debt | ' |
7. DEBT | |
Reserve-Based Credit Facility | |
In May 2013, we refinanced our $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders, extending its maturity to May 30, 2017 and increasing our borrowing base from $37.5 million to $55.0 million. On May 6, 2014, our borrowing base under the reserve-based credit facility was increased to $70.0 million. 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 amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of March 31, 2014, we had borrowed $50.7 million under our reserve-based credit facility and our borrowing base was $55.0 million. At March 31, 2014, the lenders and their percentage commitments in the reserve-based credit facility were Societe Generale (36.36%), OneWest Bank, FSB (36.36%) and BOKF NA, dba Bank of Oklahoma (27.28%). | |
Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes. The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit. As of March 31, 2014, no letters of credit were outstanding. | |
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, as discussed below, and the interest rate on our borrowings. | |
In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents and cash reserves of the Company)) to Adjusted EBITDA (generally, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives and other similar charges) of not more than 3.5 to 1.0; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than 1.0 to 1.0, all calculated pursuant to the requirements under Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging; ASC Topic 410, Asset Retirement and Environmental Obligations and ASC Topic 360, Property, Plant and Equipment. All financial covenants are calculated using our consolidated financial information and are discussed below. | |
The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control. A change of control is generally defined as the occurrence of both of the following events: (i) wholly-owned subsidiaries of Constellation Energy Group, Inc. are the owner of 20% or less of an interest in us (which has now occurred) and (ii) any person or group of persons acting in concert are the owner of more than 35% of an interest in us. These events have not both occurred, so a change in control had not occurred as of March 31, 2014. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies. The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable. | |
The reserve-based credit facility limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of our borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of March 31, 2014, 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. | |
The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve-month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money. | |
The reserve-based credit facility contains no covenants related to PostRock’s, Exelon’s or SOG’s ownership in us. | |
Compliance with Debt Covenants | |
At March 31, 2014, we were in compliance with the financial covenants contained in our reserve-based credit facility. We monitor compliance on an on-going basis. | |
If we are unable to remain in compliance with the financial covenants contained in our reserve-based credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of our reserve-based credit facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated covenants from the lenders, but there is no assurance that such waivers would be granted. | |
The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of March 31, 2014, our borrowing base was $55.0 million. The borrowing base is re-determined semi-annually, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. | |
Funds Available for Borrowing | |
As of March 31, 2014 and 2013, we had $50.7 million and $34.0 million, respectively, in outstanding debt under our reserve-based credit facility. As of March 31, 2014, we had $4.3 million available under our reserve-based credit facility. | |
Subsequent to March 31, 2014, we had the following activity on our reserve-based credit facility. On April 1, 2014, in connection with the PostRock litigation settlement, we borrowed $2.5 million. On April 4, 2014, we borrowed an additional $1.25 million in connection with the purchase of assets in LaSalle Parish, Louisiana. We repaid $2.5 million of the borrowings on May 1, 2014. On May 6, 2014, our borrowing base under our reserve-based credit facility was increased from $55.0 million to $70.0 million. On May 13, 2014, we borrowed an additional $2.0 million, which was repaid on May 15, 2014, resulting in a borrowing capacity of approximately $18.0 million available under our reserve-based credit facility as of that date. | |
Debt Issue Costs | |
As of March 31, 2014, our unamortized debt issue costs were approximately $0.8 million. These costs are being amortized over the life of our reserve-based credit facility. At December 31, 2013, our unamortized debt issue costs were approximately $0.8 million. | |
Asset_Retirement_Obligation
Asset Retirement Obligation | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
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): | ||||||
March 31, | December 31, | |||||
2014 | 2013 | |||||
Asset retirement obligation, beginning balance | $ | 9,513 | $ | 7,665 | ||
Liabilities added from acquisitions | - | 1,088 | ||||
Liabilities added from drilling | 18 | 244 | ||||
Settlements | - | -3 | ||||
Accretion expense | 150 | 519 | ||||
Asset retirement obligation, ending balance | $ | 9,681 | $ | 9,513 | ||
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 March 31, 2014, and December 31, 2013, 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 | 3 Months Ended |
Mar. 31, 2014 | |
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 natural gas properties from SEP I and the issuance of units in connection therewith. The plaintiffs contended, 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 bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs alleged 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 alleged aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers. The plaintiffs sought, 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 had sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers breached fiduciary and contractual duties and were not entitled to indemnification from the Company as a result thereof, and monetary damages. On March 31, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed. As a result of the settlement, the Class A units acquired by SEP I in the August 2013 transaction will be returned to CEP and cancelled in exchange for $0.8 million; CEPM will transfer 100% of its Class A units to SEP I and 414,938 of CEP’s Class B units to SEP I in exchange for an aggregate payment of $1.0 million from SEP I, and CEP will pay $6.5 million to CEPM. In addition, pursuant to the terms of the settlement, CEPM agreed to sell its remaining Class B units over the next nine months, with SEP I providing up to a $5.0 million backstop payment to CEPM to the extent proceeds received by CEPM from such sale do not meet or exceed a specified amount. As a result of the settlement, the settling parties filed a stipulation in the Court of Chancery of the State of Delaware seeking to lift the preliminary injunction issued on December 3, 2013, and the litigation was dismissed with prejudice. The settlement also included mutual releases between the plaintiffs and defendants. In connection with the settlement, we received $1.25 million on April 10, 2014, under our directors and officers insurance policy. | |
On February 28, 2014, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPH against the Company (the Exelon Litigation) seeking repayment of suspended distributions in relation to the Class D Interests held by CEPH. In 2006, Constellation Holding, Inc (CHI), which merged with and into CEPH in December 2012, purchased the Company’s Class D Interests for $8.0 million. The $8.0 million was to be repaid to CEPH in quarterly distributions of $333,333.33 over a period of six years; however, these distributions could be temporarily suspended if a dispute arose over pricing formulas related to the sale of natural gas from the Robinson’s Bend properties. A dispute arose, so the distributions were suspended pursuant to the Company’s operating agreement and never reinstated. CEPH contends, among other things, that the Company breached its contract to pay the quarterly distributions, acted in bad faith and received unjust enrichment by suspending the quarterly distributions. The Company believes that the allegations contained in the lawsuit are without merit and is vigorously defending itself against the claims raised in the complaint. In conjunction with its defense in the Exelon Litigation, the Company anticipates that it will incur legal and other costs that may have a material effect on available cash which could impact CEP’s ability to make distributions. | |
Related_Party_Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2014 | |
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 March 31, 2014, CEPM, a subsidiary of PostRock, owned 484,505, or 30%, 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 March 31, 2014. 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 as of March 31, 2014. | |
PostRock-Related Announcements | |
In 2011, PostRock acquired certain of our Class A units and Class B common units in two separate transactions which represented a 21.3 % ownership interest in us at March 31, 2014. Approval of the purchase of these units was neither required nor given by our board of managers or conflicts committee. We believe PostRock is now an “interested unitholder” under Section 203 of the Delaware General Corporation Law, which is applicable to us pursuant to our operating agreement. Section 203, as it applies to us, prohibits an interested unitholder, defined as a person who owns 15% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder without the approval of our board of managers and the vote of 66 2/3% of our outstanding Class B common units, excluding those held by the interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. In addition to limiting our ability to enter into transactions with PostRock or its affiliates, this provision of our operating agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging takeover attempts that might result in a premium over the market price for our common units. We believe the Section 203 restrictions related to these unit purchases expire in December 2014. | |
Sanchez-Related Announcements | |
In August 2013, SOG acquired certain of our Class A units and Class B common units and one Class Z unit in one transaction which represented a 19.5% ownership interest in us at March 31, 2014. These units were issued to SOG, along with cash, in exchange for oil and natural gas properties located in Texas and Louisiana. | |
In August 2013, the Company also entered into a Registration Rights Agreement with SOG pursuant to which the Company granted to SOG certain registration rights related to the unit consideration thereunder. Under the Registration Rights Agreement, the Company granted SOG demand registration rights with respect to the preparation and filing with the SEC of one or more registration statements for the purpose of registering the resale of the securities that will be registered. | |
Class C Management Incentive Interests | |
CEPH, a subsidiary of Exelon, holds the Class C management incentive interests in CEP. 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 or share in distributions upon liquidation. | |
Class D Interest | |
The majority of our properties in the Robinson’s Bend Field were subject to a non-operated net profits interest (NPI) held by Torch Energy Royalty Trust (the Trust). Through the NPI, the Trust was entitled to a royalty payment, calculated as a percentage of the net revenue from specified wells in the Robinson’s Bend Field (the Trust Wells). | |
Under the terms of the NPI and related contractual arrangements, the royalty payment we were required to make to the Trust under the NPI was calculated using a sharing arrangement with a pricing formula that had resulted in below-market prices and had the effect of keeping our payments to the Trust significantly lower than if such payments had been calculated on then prevailing market prices. | |
In order to address the risks of early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI and the potential reduction in our revenues resulting therefrom, CHI contributed $8.0 million to us for all of our Class D interests. This contribution was potentially to be distributed to CHI in 24 distributions over a period of approximately six years if the sharing arrangement remained in effect during that period. If the amounts payable by us to the Trust were not calculated based on the continued applicability of the sharing arrangement through December 31, 2012, unless such change was approved in advance by our board of managers and our conflicts committee, the following would occur: the Class D interests would cease receiving the cash distributions; and the Class D interest would only be returned the remaining undistributed amount of the $8.0 million contribution under certain circumstances upon our liquidation. | |
No payments for the NPI were ever made to the Trust. On January 8, 2009, we were served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in the Circuit Court of Tuscaloosa County, Alabama (the Circuit Court). The lawsuit alleged, among other things, a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserted that above market rates for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit sought unspecified damages and an accounting of the NPI. The lawsuit was settled in June 2011. The settlement with Trust Venture, its successor and the Trust provided, among other things, that we pay $1.2 million to reimburse Trust Venture and its successor for their legal fees and expenses incurred in prosecuting the lawsuit and that we acquire the NPI from the Trust for $1.0 million. When the NPI was assigned to us by the Trust in the fourth quarter of 2011, the NPI was extinguished. We recognized a $1.0 million charge to impair the value of the extinguished NPI contract that was acquired. The finalization of this settlement impacted our Class D interests. | |
CEPH, a subsidiary of Exelon and the successor to CHI, holds all of our Class D interests. Due to their contingently redeemable feature, the Class D interests were treated as temporary equity. Since the NPI is no longer being paid based upon the sharing arrangement and we have suspended distributions since June 2009, there should be no further distributions required on the Class D interests. Accordingly, the Class D interests were moved from temporary equity to permanent equity (Class A and Class B) in the fourth quarter of 2011. The Class D interests will remain outstanding until the liquidation of CEP and could receive up to $6.7 million under certain circumstances at that time. | |
Class Z Unit | |
SOG holds the one Class Z unit of CEP. This one unit is a non-voting unit, except for voting as a separate class to approve the issuance of additional Company securities, other than Class B common units, prior to the issuance of such securities. The Class Z unit is a non-economic interest, without any right to participate in distributions or allocations. | |
UnitBased_Compensation
Unit-Based Compensation | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
Unit-Based Compensation [Abstract] | ' | |||||
Unit-Based Compensation | ' | |||||
11. UNIT-BASED COMPENSATION | ||||||
We have the following unit-based compensation plans: | ||||||
We have the 2009 Omnibus Incentive Compensation Plan (Omnibus Plan), which is a plan under which restricted common unit awards are granted to certain employees in Texas. The Omnibus Plan provides for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards. Awards under the Omnibus Plan may be paid in cash, units or any combination thereof as determined by the compensation committee of our board of managers. | ||||||
Restricted unit activity (number of units) under the Omnibus Plan was as follows: | ||||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2013 | 336,551 | $ | 3.29 | |||
Vested | -171,692 | 3.33 | ||||
Granted | - | - | ||||
Returned/Cancelled | -57,214 | 3.33 | ||||
Outstanding at March 31, 2014 | 107,645 | $ | 3.20 | |||
We have the Long-Term Incentive Plan (L-TIP), which is a plan under which restricted common unit awards are granted to certain field employees in Alabama, Kansas and Oklahoma and to certain employees in Texas. | ||||||
Restricted unit activity (number of units) under the L-TIP Plan was as follows: | ||||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2013 | 43,776 | $ | 2.87 | |||
Vested | -16,415 | 2.87 | ||||
Granted | - | - | ||||
Returned/Cancelled | -5,469 | 2.87 | ||||
Outstanding at March 31, 2014 | 21,892 | $ | 2.87 | |||
We recognized approximately $0.1 million and $0.4 million of non-cash compensation expense related to our unit-based compensation plans in the three months ended March 31, 2014, and March 31, 2013, respectively. As of March 31, 2014, we had approximately $0.4 million in unrecognized compensation expense related to our unit-based non-cash compensation plans expected to be recognized through the first quarter of 2015. | ||||||
Distributions_To_Unitholders
Distributions To Unitholders | 3 Months Ended |
Mar. 31, 2014 | |
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 | 3 Months Ended |
Mar. 31, 2014 | |
Members' Equity [Abstract] | ' |
Members' Equity | ' |
13. MEMBERS’ EQUITY | |
2014 Equity | |
At March 31, 2014, we had 1,615,017 Class A units and 28,399,502 Class B common units outstanding, which included 129,537 unvested restricted common units issued under our L-TIP Plan and 342,803 unvested restricted common units issued under our Omnibus Plan. | |
At March 31, 2014, we had granted 341,265 common units of the 450,000 common units available under our L-TIP Plan. Of these grants, 319,373 have vested. | |
At March 31, 2014, we had granted 1,309,452 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,201,807 have vested. | |
For the three months ended March 31, 2014, 62,683 common units were tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, were returned to their respective plan and are available for future grants. | |
2013 Equity | |
At December 31, 2013, we had 1,615,017 Class A units and 28,462,185 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our L-TIP Plan and 336,551 unvested restricted common units issued under our Omnibus Plan. | |
At December 31, 2013, we had granted 346,734 common units of the 450,000 common units available under our L-TIP Plan. Of these grants, 302,958 have vested. | |
At December 31, 2013, we had granted 1,366,666 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,030,115 have vested. | |
For the three months ended December 31, 2013, 139,810 common units were tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, were returned to their respective plan and are available for future grants. | |
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2014 | |
Subsequent Events [Abstract] | ' |
Subsequent Events | ' |
14. SUBSEQUENT EVENTS | |
The following events have occurred subsequent to the date of the balance sheet and prior to the filing of this Quarterly Report on Form 10-Q that could have a material impact on our consolidated financial statements or results of operations: | |
Acquisition of Properties | |
On April 9, 2014, we acquired a 20% working interest in 9 producing wells and other assets for $1.4 million. These assets are located in LaSalle Parish, Louisiana and are operated by SOG. This purchase became effective May 1, 2014. | |
Settlement of PostRock Litigation | |
In connection with the settlement of the PostRock litigation settlement, discussed in Note 9, we received $1.25 million on April 10, 2014, under our directors and officers insurance policy. This amount has been reflected as a reduction in general and administrative expense for the three months ended March 31, 2014, and included in accounts receivable, net at March 31, 2014. | |
Derivative Transactions | |
We entered into three new commodities swap transactions on April 29, 2014. Under these swap transactions we hedged 52,243 barrels of oil for the period May 2014 through December 2014 at a fixed price of $98.01 per barrel; 83,017 barrels of oil for the period January 2015 through December 2015 at a fixed price of $91.07 per barrel and 148,853 barrels of oil for the period January 2016 through December 2016 at a price of $85.70 per barrel. | |
Increase in Reserve-Based Credit Facility Borrowing Capacity | |
On May 6, 2014, our borrowing base under our reserve-based credit facility was increased from $55.0 million to $70.0 million. The lenders and their percentage commitments in the reserve-based credit facility remained the same. | |
Shared Services Agreement | |
On May 8, 2014, the Company and SP Holdings, LLC (the Manager), an affiliate of SOG, entered into a Shared Services Agreement (the Services Agreement) pursuant to which Manager will provide all services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager will receive compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of the Company’s properties other than its assets located in the Mid-Continent region, (ii) a $1,000,000 administrative fee, with $500,000 paid on May 8, 2014 and $500,000 to be paid on the date that Manager provides notice of its commitment to provide services under the Shared Services Agreement (the In-Service Date), (iii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iv) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, will be paid in cash unless Manager elects for such fee to be paid in equity by the Company. In addition, upon the first acquisition of assets from an affiliate of Manager, the Company is required to amend its operating agreement and issue a new class of incentive distribution rights to Manager. | |
The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both Manager and the Company provide notice to terminate the agreement. The Services Agreement can be terminated early (i) by either party at any time after 24 months from the In-Service Date with six months’ notice to the other party, (ii) by either party if there is an uncured material breach thereunder by the other party or (iii) by the Company if there is a change in control of Manager and the Company pays the termination payment discussed below. If there is a termination of the Services Agreement other than by either party at the end of the agreement’s term, by the Company for a breach by Manager, by Manager because the conditions precedent to the In-Service Date have not been satisfied or by either party because the In-Service Date has not occurred by December 31, 2014, then the Company will owe a termination payment to Manager equal to $5,000,000 plus 5% of the transaction value of all asset acquisitions theretofore consummated; if the Company terminates after the 24-month anniversary of the In-Service Date upon six months’ notice, the Company will also owe to Manager all costs and expenses of Manager that result from such termination. | |
Contract Operating Agreement | |
On May 8, 2014, the Company and SOG entered into a Contract Operating Agreement (the Operating Agreement) pursuant to which SOG has agreed either to provide all services to operate, develop and produce the Company’s oil and natural gas properties or to engage a third-party operator to do so, other than with respect to the Company’s properties in the Mid-Continent region. In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges incurred under COPAS. | |
Transition and Assistance Agreement | |
On May 8, 1014, the Company, Manager and SOG entered into a Transition and Assistance Agreement (the Transition Agreement) pursuant to which the Company has agreed to make available to Manager and SOG certain of the Company’s employees for SOG or Manager to provide services under the Services Agreement and Operating Agreement. No compensation is paid by any party for the provision or use of employees under the Transition Agreement. All employees remain under the day-to-day control of the Company, and the Company retains the right to terminate employees and has no obligation to hire new employees. SOG has the right to hire any Company employees and thereafter, SOG will be responsible for all costs and expenses for such employees. | |
Seismic License Agreement | |
On May 8, 2014, the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the License Agreement) pursuant to which SOG provides to the Company a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to the Company’s oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. | |
Compensation Awards | |
On May 6, 2014, the Compensation Committee of the Company’s Board of Managers awarded retention awards of notional or phantom units to certain employees of the Company, including the Chief Executive Officer and Chief Financial Officer, to induce them to remain employed with the Company for a certain period of time. The awards were granted under the Company’s Omnibus Plan and L-TIP Plan. Under the terms of the awards, the notional or phantom units will fully vest on the earliest to occur of March 15, 2015, the occurrence of the In-Service Date or the consummation of a change of control, as defined in the applicable award agreement. Any notional or phantom units that are unvested on the date on which the recipient’s employment with the Company is terminated shall be forfeited. | |
Organization_And_Basis_Of_Pres1
Organization And Basis Of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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, 2013, which was filed with the SEC on March 27, 2014. | |
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. | |
Reclassifications | ' |
Reclassifications | |
Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities. | |
Discontinued Operations | ' |
Discontinued Operations | |
In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama. The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the three months ended March 31, 2013. Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 3. Acquisition and Divestiture. | |
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policies) | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ' | |||||||||
Earnings Per Unit | ' | |||||||||
Earnings per Unit | ||||||||||
Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) is allocated to each class with the Class A units receiving 2% and the Class B units receiving 98%. | ||||||||||
As of March 31, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities. These units will be considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities. | ||||||||||
The following table presents our calculation of basic and diluted units outstanding for the periods indicated: | ||||||||||
Three Months Ended March 31, | ||||||||||
2014 | 2013 | |||||||||
Weighted average units outstanding during period: | ||||||||||
Class A units - Basic and Diluted | 1,615,017 | 484,396 | ||||||||
Class B Common units - Basic and Diluted | 28,214,104 | 23,766,266 | ||||||||
29,829,121 | 24,250,662 | |||||||||
At March 31, 2014, we had 129,537 Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number. | ||||||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2014 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -2,939 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed net loss to be allocated | $ | -2,939 | $ | -59 | $ | -2,880 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.1 | ||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2013 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -10,646 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed allocation of loss from continuing operations | -10,646 | -213 | -10,433 | |||||||
Discontinued operations | -2,686 | -54 | -2,632 | |||||||
Assumed net loss to be allocated | $ | -13,332 | $ | -267 | $ | -13,065 | ||||
Basic and diluted loss from continuing operations per unit | $ | -0.44 | $ | -0.44 | ||||||
Basic and diluted loss from discontinued operations per unit | $ | -0.11 | $ | -0.11 | ||||||
Basic and diluted loss per unit | $ | -0.55 | $ | -0.55 | ||||||
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 March 31, 2014 and December 31, 2013. | ||||||||||
Restricted Cash | ' | |||||||||
Restricted Cash | ||||||||||
Restricted cash, at March 31, 2014 and December 31, 2013, of $1.7 million was being held in escrow. Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. These funds will remain in escrow for a period ending February 28, 2015, pending certain post-closing conditions. The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at March 31, 2014, based on the conditions of the cash held in the account. | ||||||||||
Accounts Receivable, Net | ' | |||||||||
Accounts Receivable, Net | ||||||||||
Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. At March 31, 2014 and 2013, we had an allowance for doubtful accounts receivable of $0.2 million and $0.1 million, respectively. | ||||||||||
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
Summary Of Significant Accounting Policies [Abstract] | ' | |||||||||
Schedule Of Weighted Average Units Outstanding | ' | |||||||||
Three Months Ended March 31, | ||||||||||
2014 | 2013 | |||||||||
Weighted average units outstanding during period: | ||||||||||
Class A units - Basic and Diluted | 1,615,017 | 484,396 | ||||||||
Class B Common units - Basic and Diluted | 28,214,104 | 23,766,266 | ||||||||
29,829,121 | 24,250,662 | |||||||||
Earnings Per Common Unit Amounts | ' | |||||||||
At March 31, 2014, we had 129,537 Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number. | ||||||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2014 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -2,939 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed net loss to be allocated | $ | -2,939 | $ | -59 | $ | -2,880 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.1 | ||||||
The following table presents our basic and diluted loss per unit for the three months ended March 31, 2013 (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Loss from continuing operations | $ | -10,646 | ||||||||
Distributions | - | $ | - | $ | - | |||||
Assumed allocation of loss from continuing operations | -10,646 | -213 | -10,433 | |||||||
Discontinued operations | -2,686 | -54 | -2,632 | |||||||
Assumed net loss to be allocated | $ | -13,332 | $ | -267 | $ | -13,065 | ||||
Basic and diluted loss from continuing operations per unit | $ | -0.44 | $ | -0.44 | ||||||
Basic and diluted loss from discontinued operations per unit | $ | -0.11 | $ | -0.11 | ||||||
Basic and diluted loss per unit | $ | -0.55 | $ | -0.55 | ||||||
Acquisition_And_Divestiture_Ta
Acquisition And Divestiture (Tables) | 3 Months Ended | |||
Mar. 31, 2014 | ||||
Acquisition And Divestiture [Abstract] | ' | |||
Schedule Of Discontinued Operations | ' | |||
Three Months Ended | ||||
31-Mar-13 | ||||
Revenues | $ | 2,304 | ||
Loss from discontinued operations | $ | -2,686 | ||
Estimated Values Of Assets Acquired And Liabilities Assumed | ' | |||
1-Aug-13 | ||||
Oil and natural gas properties, equipment and facilities | $ | 31,497 | ||
Asset retirement obligation | -1,088 | |||
Net assets acquired | $ | 30,409 | ||
Supplemental Pro Forma Information | ' | |||
Pro Forma | ||||
Three Months Ended | ||||
(In thousands) | 31-Mar-13 | |||
Revenue | $ | 9,648 | ||
Loss from continuing operations | $ | -7,729 | ||
Discontinued operations | $ | -2,686 | ||
Net Loss | $ | -10,415 | ||
Loss from continuing operations per unit | ||||
Class A units - Basic and diluted | $ | -0.1 | ||
Class B units - Basic and diluted | $ | -0.27 | ||
Discontinued operations per unit | ||||
Class A units - Basic and diluted | $ | -0.03 | ||
Class B units - Basic and diluted | $ | -0.09 | ||
Net loss per unit | ||||
Class A units - Basic and diluted | $ | -0.13 | ||
Class B units - Basic and diluted | $ | -0.36 | ||
Weighted average units outstanding | ||||
Class A units - Basic and diluted | 1,614,908 | |||
Class B units - Basic and diluted | 28,490,673 | |||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 3 Months Ended | ||||||||||||||
Mar. 31, 2014 | |||||||||||||||
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 March 31, 2014 (in thousands): | |||||||||||||||
Fair Value Measurements at March 31, 2014 | |||||||||||||||
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-Mar-14 | |||||||||||
Risk Management Assets | $ | - | $ | 7,144 | $ | - | $ | -1,539 | $ | 5,605 | |||||
Risk Management Liabilities | - | -1,539 | - | 1,539 | - | ||||||||||
Total Net Assets and Liabilities | $ | - | $ | 5,605 | $ | - | $ | - | $ | 5,605 | |||||
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, 2013 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 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 | 31-Dec-13 | |||||||||||
Risk Management Assets | $ | - | $ | 11,577 | $ | - | $ | -975 | $ | 10,602 | |||||
Risk Management Liabilities | - | -975 | - | 975 | - | ||||||||||
Total Net Assets and Liabilities | $ | - | $ | 10,602 | $ | - | $ | - | $ | 10,602 | |||||
Derivative_And_Financial_Instr1
Derivative And Financial Instruments (Tables) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
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 | ||||||||||||||||
2014 | 1,592,500 | $ | 5.75 | 1,610,000 | $ | 5.75 | 1,610,000 | $ | 5.75 | 4,812,500 | $ | 5.75 | |||||||||||||
2015 | 1,215,420 | $ | 4.25 | 1,153,487 | $ | 4.25 | 1,096,023 | $ | 4.26 | 1,050,219 | $ | 4.26 | 4,515,149 | $ | 4.25 | ||||||||||
2016 | 1,010,633 | $ | 4.21 | 967,290 | $ | 4.21 | 923,541 | $ | 4.21 | 893,568 | $ | 4.22 | 3,795,032 | $ | 4.21 | ||||||||||
13,122,681 | |||||||||||||||||||||||||
MTM Fixed Price Basis Swaps– Enable Gas Transmission, LLC (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 $ | ||||||||||||||||
2014 | 1,133,022 | $ | 0.39 | 1,084,270 | $ | 0.39 | 1,047,963 | $ | 0.39 | 3,265,255 | $ | 0.39 | |||||||||||||
3,265,255 | |||||||||||||||||||||||||
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 | ||||||||||||||||
2014 | 57,154 | $ | 94.67 | 53,797 | $ | 94.72 | 50,597 | $ | 94.80 | 161,548 | $ | 94.73 | |||||||||||||
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 | ||||||||||
403,478 | |||||||||||||||||||||||||
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 | 31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets - current | $ | 5,837 | $ | 10,043 | ||||||||||||||||||||
Commodity – MTM | Risk management assets - non-current | 1,308 | 1,534 | ||||||||||||||||||||||
Total gross assets | 7,145 | 11,577 | |||||||||||||||||||||||
Commodity – MTM | Risk management assets – current | -1,393 | -902 | ||||||||||||||||||||||
Commodity – MTM | Risk management assets – non-current | -147 | -73 | ||||||||||||||||||||||
Total gross liabilities | -1,540 | -975 | |||||||||||||||||||||||
Total net assets and liabilities | $ | 5,605 | $ | 10,602 | |||||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||
Derivative Type | in Income | 2014 | 2013 | ||||||||||||||||||||||
Commodity – Mark-to-Market | Oil and natural gas sales | $ | -4,074 | $ | -4,580 | ||||||||||||||||||||
Interest Rate – Mark-to-Market | Interest expense | - | -45 | ||||||||||||||||||||||
Total | $ | -4,074 | $ | -4,625 | |||||||||||||||||||||
Oil_And_Natural_Gas_Properties1
Oil And Natural Gas Properties (Tables) | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
Oil And Natural Gas Properties [Abstract] | ' | |||||
Oil and Natural Gas Properties | ' | |||||
March 31, 2014 | December 31, 2013 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property (acreage) costs | ||||||
Proved property | $ | 639,141 | $ | 636,816 | ||
Unproved property | 1,648 | 1,589 | ||||
Total property costs | 640,789 | 638,405 | ||||
Materials and supplies | 1,057 | 1,054 | ||||
Land | 751 | 751 | ||||
Total | 642,597 | 640,210 | ||||
Less: Accumulated depreciation, depletion, amortization and impairments | -499,321 | -495,215 | ||||
Oil and natural gas properties and equipment, net | $ | 143,276 | $ | 144,995 | ||
Depletion, Depreciation, Amortization and Impairments | ' | |||||
Three Months Ended March 31, | ||||||
2014 | 2013 | |||||
DD&A of oil and natural gas-related assets | $ | 4,050 | $ | 4,798 | ||
Asset Impairments | 149 | - | ||||
Total | $ | 4,199 | $ | 4,798 | ||
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
Asset Retirement Obligation [Abstract] | ' | |||||
Reconciliation of Asset Retirement Obligation | ' | |||||
March 31, | December 31, | |||||
2014 | 2013 | |||||
Asset retirement obligation, beginning balance | $ | 9,513 | $ | 7,665 | ||
Liabilities added from acquisitions | - | 1,088 | ||||
Liabilities added from drilling | 18 | 244 | ||||
Settlements | - | -3 | ||||
Accretion expense | 150 | 519 | ||||
Asset retirement obligation, ending balance | $ | 9,681 | $ | 9,513 | ||
UnitBased_Compensation_Tables
Unit-Based Compensation (Tables) | 3 Months Ended | |||||
Mar. 31, 2014 | ||||||
2009 Omnibus Incentive Compensation Plan [Member] | ' | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | |||||
Schedule Of Units Granted | ' | |||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2013 | 336,551 | $ | 3.29 | |||
Vested | -171,692 | 3.33 | ||||
Granted | - | - | ||||
Returned/Cancelled | -57,214 | 3.33 | ||||
Outstanding at March 31, 2014 | 107,645 | $ | 3.20 | |||
Long Term Incentive Plan [Member] | ' | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | |||||
Schedule Of Units Granted | ' | |||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2013 | 43,776 | $ | 2.87 | |||
Vested | -16,415 | 2.87 | ||||
Granted | - | - | ||||
Returned/Cancelled | -5,469 | 2.87 | ||||
Outstanding at March 31, 2014 | 21,892 | $ | 2.87 | |||
Recovered_Sheet1
Organization and Basis of Presentation (Details) | 0 Months Ended | 3 Months Ended |
Aug. 09, 2013 | Mar. 31, 2014 | |
Organization [Line Items] | ' | ' |
Number of business segments | ' | 1 |
Constellation Energy Partners Management [Member] | Common Class A [Member] | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | ' | 484,505 |
Units owned by third party, percentage of total shares | ' | 30.00% |
Constellation Energy Partners Management [Member] | Common Class B [Member] | ' | ' |
Organization [Line Items] | ' | ' |
Units owned by third party | ' | 5,918,894 |
Sanchez Energy Partners I [Member] | Common Class A [Member] | ' | ' |
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 [Member] | ' | ' |
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 $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 |
Common Class A [Member] | Common Class B [Member] | ||||
Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Net income (loss) alloxation | ' | ' | ' | 2.00% | 98.00% |
Restricted unvested common units granted and outstanding | ' | ' | ' | ' | 129,537 |
Restricted cash (See Note 2) | ' | $1,748,000 | ' | ' | ' |
Restricted cash held in escrow | 1,700,000 | 1,700,000 | ' | ' | ' |
Escrow account related to vendor dispute | 600,000 | ' | ' | ' | ' |
Escrow account | 1,100,000 | ' | ' | ' | ' |
Allowance for doubtful accounts | $200,000 | ' | $100,000 | ' | ' |
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Schedule Of Weighted Average Units Outstanding) (Details) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Class Of Stock [Line Items] | ' | ' |
Weighted average units outstanding - Basic and Diluted | 29,829,121 | 24,250,662 |
Common Class A [Member] | ' | ' |
Class Of Stock [Line Items] | ' | ' |
Weighted average units outstanding - Basic and Diluted | 1,615,017 | 484,396 |
Common Class B [Member] | ' | ' |
Class Of Stock [Line Items] | ' | ' |
Weighted average units outstanding - Basic and Diluted | 28,214,104 | 23,766,266 |
Summary_Of_Significant_Account4
Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Class Of Stock [Line Items] | ' | ' |
Loss from continuing operations | ($2,939) | ($10,646) |
Loss from continuing operations | -2,939 | -10,646 |
Discontinued operations | ' | -2,686 |
Net loss | -2,939 | -13,332 |
Common Class A [Member] | ' | ' |
Class Of Stock [Line Items] | ' | ' |
Loss from continuing operations | ' | -213 |
Discontinued operations | ' | -54 |
Net loss | -59 | -267 |
Basic and diluted loss from continuing operations per unit | ($0.04) | ($0.44) |
Basic and diluted loss from discontinued operations per unit | ' | ($0.11) |
Basic and diluted loss per unit | ($0.04) | ($0.55) |
Common Class B [Member] | ' | ' |
Class Of Stock [Line Items] | ' | ' |
Loss from continuing operations | ' | -10,433 |
Discontinued operations | ' | -2,632 |
Net loss | ($2,880) | ($13,065) |
Basic and diluted loss from continuing operations per unit | ($0.10) | ($0.44) |
Basic and diluted loss from discontinued operations per unit | ' | ($0.11) |
Basic and diluted loss per unit | ($0.10) | ($0.55) |
Acquisition_And_Divestiture_Na
Acquisition And Divestiture (Narrative) (Details) (USD $) | 0 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Feb. 28, 2013 | Mar. 31, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Aug. 09, 2013 | Mar. 31, 2014 | Aug. 09, 2013 | Mar. 31, 2014 |
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 [Member] | Common Class A [Member] | Common Class B [Member] | Common Class B [Member] | ||||||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from sale of business | $63 | ' | ' | ' | ' | ' | ' | ' | ' |
Post-closing adjustments | 4 | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (Loss) on sale of business | ' | -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_Sc
Acquisition And Divestiture (Schedule Of Discontinued Operations) (Details) (USD $) | 3 Months Ended |
In Thousands, unless otherwise specified | Mar. 31, 2013 |
Discontinued Operations [Abstract] | ' |
Revenues | $2,304 |
Loss from discontinued operations | ($2,686) |
Acquisition_And_Divestiture_Es
Acquisition And Divestiture (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Aug. 01, 2013 |
In Thousands, unless otherwise specified | |||
Acquisition And Divestiture [Abstract] | ' | ' | ' |
Oil and natural gas properties, equipment and facilities | $641,540 | $639,156 | $31,497 |
Asset retirement obligation | -9,681 | -9,513 | -1,088 |
Net assets acquired | ' | ' | $30,409 |
Acquisition_And_Divestiture_Su
Acquisition And Divestiture (Supplemental Pro Forma Information) (Details) (USD $) | 3 Months Ended |
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2013 |
Business Acquisition [Line Items] | ' |
Revenue | $9,648 |
Loss from continuing operations | -7,729 |
Discontinued operations | -2,686 |
Net Loss | ($10,415) |
Common Class A [Member] | ' |
Business Acquisition [Line Items] | ' |
Loss from continuing operations per unit - Basic and diluted | ($0.10) |
Discontinued operations per unit - Basic and diluted | ($0.03) |
Net loss per unit - Basic and diluted | ($0.13) |
Weighted average units outstanding - Basic and diluted | 1,614,908 |
Common Class B [Member] | ' |
Business Acquisition [Line Items] | ' |
Loss from continuing operations per unit - Basic and diluted | ($0.27) |
Discontinued operations per unit - Basic and diluted | ($0.09) |
Net loss per unit - Basic and diluted | ($0.36) |
Weighted average units outstanding - Basic and diluted | 28,490,673 |
Fair_Value_Measurements_Fair_V
Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | $5,605 | $10,602 |
Total Net Assets and Liabilities | 5,605 | 10,602 |
Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | 7,144 | 11,577 |
Risk Mgmt Liabilities | -1,539 | -975 |
Total Net Assets and Liabilities | 5,605 | 10,602 |
Netting Cash And Collateral [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
Risk Mgmt Assets | -1,539 | -975 |
Risk Mgmt Liabilities | $1,539 | $975 |
Derivative_And_Financial_Instr2
Derivative And Financial Instruments (Narrative) (Details) (USD $) | 1 Months Ended | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 |
MMBTU | item | ||
bbl | |||
Derivative [Line Items] | ' | ' | ' |
Number of counterparties | ' | ' | 2 |
Cost to liquidate derivative hedge | ' | $0.30 | ' |
Amount reduced from outstanding swap positions | ' | 1,041,814 | ' |
Derivative contract swap, fixed price | 3.66 | 3.66 | ' |
Number of barrels of oil | ' | 58,157 | ' |
Execution of amendment | 0.2 | ' | ' |
Outstanding debt | 30 | 30 | ' |
Increase in interest rate swap settlement | $2.10 | ' | ' |
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) | 3 Months Ended |
Mar. 31, 2014 | |
MMBTU | |
NYMEX 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 4,812,500 |
Average Price | 5.75 |
NYMEX 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 4,515,149 |
Average Price | 4.25 |
NYMEX 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 3,795,032 |
Average Price | 4.21 |
NYMEX [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 13,122,681 |
Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 3,265,255 |
Average Price | 0.39 |
Centerpoint, ONEOK, Or Southern Star [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 3,265,255 |
West Texas Intermediate 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 161,548 |
Average Price | 94.73 |
West Texas Intermediate 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 175,813 |
Average Price | 91.02 |
West Texas Intermediate 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 66,117 |
Average Price | 85.5 |
West Texas Intermediate [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 403,478 |
First Quarter [Member] | NYMEX 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,215,420 |
Average Price | 4.25 |
First Quarter [Member] | NYMEX 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,010,633 |
Average Price | 4.21 |
First Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 47,747 |
Average Price | 90.95 |
First Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 17,957 |
Average Price | 85.5 |
Second Quarter [Member] | NYMEX 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,592,500 |
Average Price | 5.75 |
Second Quarter [Member] | NYMEX 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,153,487 |
Average Price | 4.25 |
Second Quarter [Member] | NYMEX 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 967,290 |
Average Price | 4.21 |
Second Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,133,022 |
Average Price | 0.39 |
Second Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 57,154 |
Average Price | 94.67 |
Second Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 45,065 |
Average Price | 91 |
Second Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 16,985 |
Average Price | 85.5 |
Third Quarter [Member] | NYMEX 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,610,000 |
Average Price | 5.75 |
Third Quarter [Member] | NYMEX 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,096,023 |
Average Price | 4.26 |
Third Quarter [Member] | NYMEX 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 923,541 |
Average Price | 4.21 |
Third Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,084,270 |
Average Price | 0.39 |
Third Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 53,797 |
Average Price | 94.72 |
Third Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 42,672 |
Average Price | 91.04 |
Third Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 16,048 |
Average Price | 85.5 |
Fourth Quarter [Member] | NYMEX 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,610,000 |
Average Price | 5.75 |
Fourth Quarter [Member] | NYMEX 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,050,219 |
Average Price | 4.26 |
Fourth Quarter [Member] | NYMEX 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 893,568 |
Average Price | 4.22 |
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 1,047,963 |
Average Price | 0.39 |
Fourth Quarter [Member] | West Texas Intermediate 2014 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 50,597 |
Average Price | 94.8 |
Fourth Quarter [Member] | West Texas Intermediate 2015 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 40,329 |
Average Price | 91.1 |
Fourth Quarter [Member] | West Texas Intermediate 2016 [Member] | ' |
Derivatives, Fair Value [Line Items] | ' |
Volume (in MMBtu) | 15,127 |
Average Price | 85.5 |
Derivative_And_Financial_Instr4
Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management assets-current | $4,444 | $9,141 |
Risk management assets-non-current | 1,161 | 1,461 |
Total gross assets | 7,145 | 11,577 |
Total gross liabilities | -1,540 | -975 |
Total net assets and liabilities | 5,605 | 10,602 |
Current Assets [Member] | Risk Management Commodity [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management assets-current | 5,837 | 10,043 |
Risk management liabilities-current | -1,393 | -902 |
Noncurrent Assets [Member] | Risk Management Commodity [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Risk management assets-non-current | 1,308 | 1,534 |
Risk management liabilities-non-current | ($147) | ($73) |
Derivative_And_Financial_Instr5
Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' |
Derivative gains (losses) recognized in income | ($4,074) | ($4,625) |
Oil And Natural Gas Sales [Member] | Unrealized Commodity [Member] | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' |
Derivative gains (losses) recognized in income | -4,074 | -4,580 |
Interest Expense [Member] | Realized Interest Rate [Member] | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' |
Derivative gains (losses) recognized in income | ' | ($45) |
Recovered_Sheet3
Oil and Natural Gas Properties (Narrative) (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Property, Plant and Equipment [Line Items] | ' | ' |
Proceeds from sale of miscellaneous equipment and surplus inventory | $0.10 | $0.10 |
Exploration costs | 0 | 0 |
Furniture, Fixtures And Equipment [Member] | Minimum [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Useful life | '1 year | ' |
Furniture, Fixtures And Equipment [Member] | Maximum [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Useful life | '7 years | ' |
Buildings | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Useful life | '20 years | ' |
Pipeline and Gathering Systems [Member] | Minimum [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Useful life | '25 years | ' |
Pipeline and Gathering Systems [Member] | Maximum [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Useful life | '40 years | ' |
Texas And Louisiana Oil And Natural Gas Fields [Member] | ' | ' |
Property, Plant and Equipment [Line Items] | ' | ' |
Non-cash impairment charges | $0.10 | ' |
Recovered_Sheet4
Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Oil And Natural Gas Properties [Abstract] | ' | ' |
Proved property | $639,141 | $636,816 |
Unproved property | 1,648 | 1,589 |
Total property costs | 640,789 | 638,405 |
Materials and supplies | 1,057 | 1,054 |
Land | 751 | 751 |
Total | 642,597 | 640,210 |
Less: Accumulated depreciation, depletion, amortization and impairments | -499,321 | -495,215 |
Oil and natural gas properties and equipment, net | $143,276 | $144,995 |
Oil_And_Natural_Gas_Properties2
Oil And Natural Gas Properties (Depletion, Depreciation, Amortization and Impairments) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Oil And Natural Gas Properties [Abstract] | ' | ' |
DD&A of oil and natural gas-related assets | $4,050 | $4,798 |
Asset Impairments | 149 | ' |
Total | $4,199 | $4,798 |
Debt_Details
Debt (Details) (USD $) | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 0 Months Ended | |||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | 31-May-13 | Apr. 30, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | 6-May-14 | 5-May-14 | 1-May-14 | 13-May-14 | 6-May-14 | Apr. 01, 2014 | Apr. 04, 2014 | |
Societe Generale [Member] | Societe Generale [Member] | Societe Generale [Member] | OneWest Bank [Member] | Bank of Oklahoma [Member] | Letter of Credit [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | La Salle Parrish Acquisition [Member] | ||||
London Interbank Offered Rate (LIBOR) [Member] | ABR [Member] | London Interbank Offered Rate (LIBOR) [Member] | ABR [Member] | Societe Generale [Member] | Reserve Based Credit Facility [Member] | Reserve Based Credit Facility [Member] | Reserve Based Credit Facility [Member] | Reserve Based Credit Facility [Member] | Subsequent Event [Member] | |||||||||||||
Reserve Based Credit Facility [Member] | ||||||||||||||||||||||
Line of Credit Facility [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reserve based credit facility maximum borrowing capacity | ' | ' | ' | ' | $350,000,000 | ' | ' | ' | $20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maturity date of reserve-based credit facility | ' | ' | ' | 30-May-17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Borrowing base amount | 55,000,000 | ' | ' | 55,000,000 | ' | 37,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | 70,000,000 | ' | ' | 70,000,000 | ' | ' |
Amount borrowed under credit facility | ' | ' | ' | 50,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | 2,500,000 | 1,250,000 |
Commitment fee percentage | ' | ' | ' | 36.36% | ' | ' | 36.36% | 27.28% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.50% | 1.50% | ' | 3.50% | 2.50% | ' | ' | ' | ' | ' | ' | ' |
Commitment fee on unutilized borrowing base | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total net debt adjusted to EBITDA | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 350.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash interest expense adjusted to EBITDA | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Consolidated current asset ratio | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ownership percentage by subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ownership percentage by person or group of persons | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exceeding of reserve-based credit facility over borrowing base | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Hedging of projected monthly production | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 115.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Heding of interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Outstanding debt under reserve-based credit facility | 50,700,000 | 34,000,000 | 50,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remaining borrowing capacity | 4,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | ' | ' |
Borrowing amount repaid | ' | 50,194,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500,000 | ' | ' | ' | ' |
Unamortized debt issue costs | $800,000 | ' | $800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset_Retirement_Obligation_Na
Asset Retirement Obligation (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 |
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 | 12 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Asset Retirement Obligation [Abstract] | ' | ' | ' |
Asset retirement obligation, beginning balance | $9,513 | $7,665 | $7,665 |
Liabilities added from acquisitions | ' | ' | 1,088 |
Liabilities added from drilling | 18 | ' | 244 |
Settlements | ' | ' | -3 |
Accretion expense | 150 | 123 | 519 |
Asset retirement obligation, ending balance | $9,681 | ' | $9,513 |
Commitments_And_Contingencies_
Commitments And Contingencies (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2006 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 10, 2014 | |
Constellation Energy Partners Management [Member] | CEPH [Member] | Common Class A [Member] | Common Class B [Member] | Subsequent Event [Member] | ||
Constellation Energy Partners Management [Member] | Constellation Energy Partners Management [Member] | |||||
Class Of Stock [Line Items] | ' | ' | ' | ' | ' | ' |
Percentage of shares to be transferred | ' | ' | ' | 100.00% | ' | ' |
Shares to be transferred | ' | ' | ' | ' | 414,938 | ' |
Amount received from units transferred | ' | ' | ' | $800,000 | $1,000,000 | ' |
Settlement payment | ' | ' | ' | ' | 6,500,000 | ' |
Maximum backstop payment | ' | 5,000,000 | ' | ' | ' | ' |
Amount received from directors and officers insurance policy | ' | ' | ' | ' | ' | 1,250,000 |
Proceeds from sales of shares | ' | ' | 8,000,000 | ' | ' | ' |
Quarterly dividend amount | ' | ' | $333,333.33 | ' | ' | ' |
Dividend payment period | ' | ' | '6 years | ' | ' | ' |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 1 Months Ended | 3 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | ||||
In Millions, except Share data, unless otherwise specified | Jun. 30, 2011 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Aug. 09, 2013 | Aug. 09, 2013 | Mar. 31, 2014 | Aug. 09, 2013 | Mar. 31, 2014 | Jun. 30, 2011 | Mar. 31, 2014 |
item | PostRock [Member] | Sanchez Oil And Gas Corporation [Member] | Common Class A [Member] | Common Class B [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] | NPI [Member] | Maximum [Member] | ||
Constellation Energy Partners Management [Member] | Constellation Energy Partners Management [Member] | Common Class A [Member] | Common Class A [Member] | Common Class B [Member] | Common Class B [Member] | ||||||||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Units owned by third party | ' | ' | ' | ' | 484,505 | 5,918,894 | ' | 1,130,512 | 1,130,512 | 4,724,407 | 4,724,407 | ' | ' |
Units owned by third party, percentage of total shares | ' | ' | ' | ' | 30.00% | ' | ' | 70.00% | 70.00% | 16.60% | ' | ' | ' |
Ownership percentage in company by related party | ' | ' | 21.30% | 19.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of outstanding common units owned by interest unitholder | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Voting percentage of Class B common units | ' | 66.66% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of quarterly dividends represented by Class C interestes helf by CPEH | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contributions from CHI | ' | $8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of distributions | ' | 24 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Distribution period | ' | '6 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Legal fee reimbursement | 1.2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Purchase price for acquisition | ' | ' | ' | ' | ' | ' | 30.4 | ' | ' | ' | ' | 1 | ' |
Impairment recognzied upon NPI acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' |
Maximum interest upon liquidation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6.70 |
UnitBased_Compensation_Details
Unit-Based Compensation (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Unit-Based Compensation [Abstract] | ' | ' |
Non-cash compensation expense | $0.10 | $0.40 |
Unrecognized portion of share based compensation expense | $0.40 | ' |
UnitBased_Compensation_Schedul
Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2014 | Dec. 31, 2013 | |
2009 Omnibus Incentive Compensation Plan [Member] | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' |
Number of Restricted Units, Outstanding | 336,551 | ' |
Number of Restricted Units, Vested | -1,201,807 | -1,030,115 |
Number of Restricted Units, Granted | 1,309,452 | 1,366,666 |
Number of Restricted Units, Outstanding | 342,803 | 336,551 |
Long Term Incentive Plan [Member] | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' |
Number of Restricted Units, Outstanding | 43,776 | ' |
Number of Restricted Units, Vested | -319,373 | -302,958 |
Number of Restricted Units, Granted | 341,265 | 346,734 |
Number of Restricted Units, Outstanding | 129,537 | 43,776 |
Restricted Stock Units (RSUs) [Member] | 2009 Omnibus Incentive Compensation Plan [Member] | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' |
Number of Restricted Units, Outstanding | 336,551 | ' |
Number of Restricted Units, Vested | -171,692 | ' |
Number of Restricted Units, Returned/Cancelled | -57,214 | ' |
Number of Restricted Units, Outstanding | 107,645 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | 3.29 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Vested | 3.33 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled | 3.33 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | 3.2 | ' |
Restricted Stock Units (RSUs) [Member] | Long Term Incentive Plan [Member] | ' | ' |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ' | ' |
Number of Restricted Units, Outstanding | 43,776 | ' |
Number of Restricted Units, Vested | -16,415 | ' |
Number of Restricted Units, Returned/Cancelled | -5,469 | ' |
Number of Restricted Units, Outstanding | 21,892 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | 2.87 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Vested | 2.87 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled | 2.87 | ' |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | 2.87 | ' |
Members_Equity_Details
Members' Equity (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 |
Long Term Incentive Plan [Member] | Long Term Incentive Plan [Member] | 2009 Omnibus Incentive Compensation Plan [Member] | 2009 Omnibus Incentive Compensation Plan [Member] | Common Class A [Member] | Common Class A [Member] | Common Class B [Member] | Common Class B [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Shares units outstanding | ' | ' | ' | ' | ' | ' | 1,615,017 | 1,615,017 | 28,399,502 | 28,462,185 |
Unvested restricted common stock issued | ' | ' | 129,537 | 43,776 | 342,803 | 336,551 | ' | ' | 129,537 | ' |
Common units granted | ' | ' | 341,265 | 346,734 | 1,309,452 | 1,366,666 | ' | ' | ' | ' |
Common units available under incentive plan | ' | ' | 450,000 | 450,000 | 1,650,000 | 1,650,000 | ' | ' | ' | ' |
Common units vested | ' | ' | 319,373 | 302,958 | 1,201,807 | 1,030,115 | ' | ' | ' | ' |
Common units tendered for tax withholding purpose | 62,683 | 139,810 | ' | ' | ' | ' | ' | ' | ' | ' |
Units tendered by employees for tax withholding, cost | $157 | $200 | ' | ' | ' | ' | ' | ' | ' | ' |
Subsequent_Events_Details
Subsequent Events (Details) (USD $) | 3 Months Ended | 0 Months Ended | 0 Months Ended | |||||||
Mar. 31, 2013 | Mar. 31, 2014 | 8-May-14 | 6-May-14 | Apr. 10, 2014 | Apr. 09, 2014 | Apr. 29, 2014 | Apr. 29, 2014 | Apr. 29, 2014 | 8-May-14 | |
bbl | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Maximum [Member] | ||
La Salle Parrish Acquisition [Member] | May 2014 Through December 2014 Swaps [Member] | January 2015 Through December 2015 Swaps [Member] | January 2016 Through December 2016 Swaps [Member] | Subsequent Event [Member] | ||||||
item | bbl | bbl | bbl | |||||||
Subsequent Event [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of assets acquired | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' |
Number of producing wells | ' | ' | ' | ' | ' | 9 | ' | ' | ' | ' |
Purchase price for acquisition | ' | ' | ' | ' | ' | $1,400,000 | ' | ' | ' | ' |
Amount received from directors and officers insurance policy | ' | ' | ' | ' | 1,250,000 | ' | ' | ' | ' | ' |
Number of barrels of oil | 58,157 | ' | ' | ' | ' | ' | 52,243 | 83,017 | 148,853 | ' |
Derivative contract swap, fixed price | 3.66 | ' | ' | ' | ' | ' | 98.01 | 91.07 | 85.7 | ' |
Borrowing base amount | ' | 55,000,000 | ' | 70,000,000 | ' | ' | ' | ' | ' | ' |
Percent of value of properties held used to compute quarterly fee | ' | ' | 0.38% | ' | ' | ' | ' | ' | ' | ' |
Administrative fee | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' |
Initial administrative fee | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' |
Contingent administrative fee | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' |
Maximum asset acquisition, disposition and financing fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% |
Term of Services Agreement | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' |
Term of Services Agreement renewal | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' |
Length of time after In-Service Date before Agreement can be terminated | ' | ' | '24 months | ' | ' | ' | ' | ' | ' | ' |
Termination notice period | ' | ' | '6 months | ' | ' | ' | ' | ' | ' | ' |
Termination fee | ' | ' | $5,000,000 | ' | ' | ' | ' | ' | ' | ' |
Transaction value, percentage | ' | ' | 5.00% | ' | ' | ' | ' | ' | ' | ' |