Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | 15-May-15 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | FALSE | |
Document Period End Date | 31-Mar-15 | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Trading Symbol | spp | |
Entity Registrant Name | Sanchez Production Partners LP | |
Entity Central Index Key | 1362705 | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 31,383,036 |
Condensed_Consolidated_Stateme
Condensed Consolidated Statements Of Operations (USD $) | 3 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Revenues | ||
Natural gas sales | $6,574 | $6,024 |
Oil and liquids sales | 5,350 | 5,717 |
Total revenues | 11,924 | 11,741 |
Operating expenses: | ||
Lease operating expenses | 4,900 | 5,120 |
Cost of sales | 205 | 360 |
Production taxes | 370 | 772 |
General and administrative | 9,547 | 3,571 |
Gain on sale of assets | -59 | -7 |
Depreciation, depletion and amortization | 3,120 | 4,050 |
Asset impairments | 82,865 | 149 |
Accretion expense | 253 | 150 |
Total operating expenses | 101,201 | 14,165 |
Other expenses (income) | ||
Interest expense | 646 | 525 |
Other expense (income) | 63 | -10 |
Total other expenses | 709 | 515 |
Total expenses | 101,910 | 14,680 |
Net loss | ($89,986) | ($2,939) |
Earnings Per Share Basic And Diluted After Conversion [Abstract] | ||
Common units - Basic and diluted | ($2.98) | |
Earnings Per Share Basic And Diluted Other Disclosures, After Conversion [Abstract] | ||
Common units - Basic and diluted | 29,928,009 | |
Common Class A [Member] | ||
Net loss per unit prior to conversion | ||
Net loss per unit - Basic and diluted | ($0.04) | ($0.04) |
Weighted Average Units Outstanding | ||
Weighted Average Units Outstanding - Basic and diluted | 484,505 | 1,615,017 |
Common Class B [Member] | ||
Net loss per unit prior to conversion | ||
Net loss per unit - Basic and diluted | ($0.03) | ($0.10) |
Weighted Average Units Outstanding | ||
Weighted Average Units Outstanding - Basic and diluted | 28,791,626 | 28,214,104 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Current assets | ||
Cash and cash equivalents | $2,235 | $4,238 |
Restricted cash | 600 | 1,748 |
Accounts receivable, net | 4,369 | 5,217 |
Prepaid expenses | 2,071 | 1,783 |
Fair value of derivative instruments | 16,001 | 14,671 |
Total current assets | 25,276 | 27,657 |
Oil and natural gas properties and related equipment (successful efforts method) | ||
Oil and natural gas properties, equipment and facilities | 733,391 | 651,493 |
Material and supplies | 1,056 | 1,056 |
Less accumulated depreciation, depletion, amortization, and impairments | -602,995 | -517,239 |
Oil and natural gas properties and equipment, net | 131,452 | 135,310 |
Other assets | ||
Debt issuance costs | 1,708 | 689 |
Fair value of derivative instruments | 9,504 | 8,158 |
Other non-current assets | 1,634 | 1,790 |
Total assets | 169,574 | 173,604 |
Current liabilities | ||
Accounts payable and accrued liabilities | 8,227 | 6,116 |
Royalty payable | 738 | 1,134 |
Total current liabilities | 8,965 | 7,250 |
Other liabilities | ||
Asset retirement obligation | 18,150 | 17,031 |
Long-term debt | 106,000 | 42,500 |
Total other liabilities | 124,150 | 59,531 |
Total liabilities | 133,115 | 66,781 |
Commitments and contingencies (See Note 9) | ||
Members' equity / Partners' capital | ||
Total members' equity/partners' capital | 36,459 | 106,823 |
Total liabilities and members' equity/partners' capital | 169,574 | 173,604 |
Common Class A [Member] | ||
Members' equity / Partners' capital | ||
General partners' capital account | 1,930 | |
Common Class B [Member] | ||
Members' equity / Partners' capital | ||
General partners' capital account | 104,893 | |
Class A Preferred Units [Member] | ||
Members' equity / Partners' capital | ||
Class A preferred units | 13,059 | |
Common Units [Member] | ||
Members' equity / Partners' capital | ||
LP common units | $23,400 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) | Mar. 31, 2015 | Dec. 31, 2014 |
Common units outstanding | 31,383,036 | |
Common Class A [Member] | ||
Share units issued | 0 | 484,505 |
Common units outstanding | 0 | 484,505 |
Common Class B [Member] | ||
Share units issued | 0 | 28,792,584 |
Common units outstanding | 0 | 28,792,584 |
Class A Preferred Units [Member] | ||
Preferred units issued | 10,625,000 | 0 |
Preferred units outstanding | 10,625,000 | 0 |
Common Units [Member] | ||
LP common units, issued | 31,383,036 | 0 |
LP common units, outstanding | 31,383,036 | 0 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements Of Cash Flows (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Cash flows from operating activities: | ||
Net loss | ($89,986) | ($2,939) |
Adjustments to reconcile net loss to cash provided by operating activities | ||
Depreciation, depletion and amortization | 3,120 | 4,050 |
Asset impairments | 82,865 | 149 |
Amortization of debt issuance costs | 239 | 59 |
Accretion expense | 253 | 150 |
Equity earnings in affiliate | 61 | -12 |
Gain from disposition of property and equipment | -59 | -7 |
Bad debt expense | 112 | 93 |
Total mark-to-market (gains) losses on commodity derivative contracts | -4,832 | 4,074 |
Cash mark-to-market settlements on commodity derivative contracts | 4,374 | 923 |
Unit-based compensation programs | 1,992 | 101 |
Changes in Operating Assets and Liabilities: | ||
(Increase) decrease in accounts receivable | 1,926 | -3,181 |
(Increase) decrease in prepaid expenses | -288 | 1,378 |
Decrease in other assets | 2 | 2 |
Increase in accounts payable and accrued liabilities | 2,173 | 1,359 |
Increase (decrease) in royalty payable | -396 | 263 |
Net cash provided by (used in) operating activities | 1,556 | 6,462 |
Cash flows from investing activities: | ||
Cash paid for acquisitions | -81,602 | |
Development of natural gas properties | -954 | -2,731 |
Proceeds from sale of property and equipment | 84 | 58 |
Distributions from equity affiliate | 100 | |
Net cash used in investing activities | -82,472 | -2,573 |
Cash flows from financing activities: | ||
Proceeds from issuance of preferred units | 17,000 | |
Proceeds from issuance of debt | 106,000 | |
Repayment of debt | -42,500 | |
Units tendered by employees for tax withholdings | -618 | -157 |
Debt issuance costs | -969 | |
Net cash provided by (used in) financing activities | 78,913 | -157 |
Net increase/decrease in cash and cash equivalents | -2,003 | 3,732 |
Cash and cash equivalents, beginning of period | 4,238 | 4,894 |
Cash and cash equivalents, end of period | 2,235 | 8,626 |
Supplemental disclosures of cash flow information: | ||
Change in accrued capital expenditures | -149 | -361 |
Accrual for cancellation of Class A units | 818 | |
Acquisitions of oil and natural gas properties in exchange for common units | 2,000 | |
Cash paid during the period for interest | -405 | -478 |
Cash paid during the period for income taxes | ($2) | ($2) |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements Of Changes In Members' Equity (USD $) | Common Class A [Member] | Common Class A [Member] | Common Class B [Member] | Common Class B [Member] | Class A Preferred Units [Member] | Common Units [Member] | Total |
In Thousands, except Share data | Common Units [Member] | Common Units [Member] | |||||
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 | |||||
Units tendered by employees for tax withholding (in shares) | -160,182 | ||||||
Units tendered by employees for tax withholding, cost | -415 | -415 | |||||
Unit-based compensation programs (in shares) | 490,581 | ||||||
Unit-based compensation programs | 1,298 | 1,298 | |||||
Cancellation of units (in shares) (See Note 9) | -1,130,512 | ||||||
Cancellation of units | -851 | -1,617 | -2,468 | ||||
Net income (loss) | 190 | 9,313 | 9,503 | ||||
Ending Balance at Dec. 31, 2014 | 1,930 | 104,893 | 106,823 | ||||
Ending Balance (in shares) at Dec. 31, 2014 | 484,505 | 28,792,584 | |||||
Units tendered by employees for tax withholding (in shares) | -15,570 | ||||||
Units tendered by employees for tax withholding, cost | 21 | 21 | |||||
Net income (loss) | -18 | -905 | -923 | ||||
Ending Balance at Mar. 05, 2015 | 1,912 | 103,967 | 105,879 | ||||
Ending Balance (in shares) at Mar. 05, 2015 | 484,505 | 28,777,014 | |||||
Units tendered by employees for tax withholding (in shares) | -322,692 | ||||||
Units tendered by employees for tax withholding, cost | -597 | -597 | |||||
Unit-based compensation programs (in shares) | 1,288,796 | ||||||
Unit-based compensation programs | 1,993 | 1,993 | |||||
Private placement of Class A Preferred Units (in shares) | 10,625,000 | ||||||
Private placement of Class A Preferred Units | 16,247 | 16,247 | |||||
Beneficial conversion feature of Class A Preferred Units | -3,188 | 3,188 | |||||
Units converted to LP Common Units upon limited partnerships (in shares) | 587,286 | -484,505 | 28,777,014 | -28,777,014 | |||
Units converted to LP Common Units upon limited partnerships | 1,912 | -1,912 | 103,967 | -103,967 | |||
Unit issued for acquisition of properties (in shares) | 1,052,632 | ||||||
Unit issued for acquisition of properties | 2,000 | 2,000 | |||||
Net income (loss) | -89,063 | -89,063 | |||||
Ending Balance at Mar. 31, 2015 | $13,059 | $23,400 | $36,459 | ||||
Ending Balance (in shares) at Mar. 31, 2015 | 10,625,000 | 31,383,036 |
Organization_And_Basis_Of_Pres
Organization And Basis Of Presentation | 3 Months Ended |
Mar. 31, 2015 | |
Organization And Basis Of Presentation [Abstract] | |
Organization And Basis Of Presentation | 1. ORGANIZATION AND BASIS OF PRESENTATION |
Organization | |
Sanchez Production Partners LP, a Delaware limited partnership (“SPP”, “we”, “us”, “our” or the “Partnership”), is an oil and gas exploration and production limited partnership focused on the acquisition, development and production of oil and natural gas properties and other integrated assets. SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). In August 2013, Sanchez Energy Partners I, LP (“SEP I”), an affiliate of Sanchez Oil & Gas Corporation (“SOG”), contributed certain oil and natural gas properties in Texas and Louisiana to CEP in exchange for equity interests in CEP. On May 8, 2014, the Company and SP Holdings, LLC (the “Manager”), the sole member of our general partner, entered into a Shared Services Agreement (the “Services Agreement”) pursuant to which the Manager agreed to provide services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services. The Services Agreement became effective as of July 1, 2014. CEP’s name was subsequently changed to Sanchez Production Partners LLC and on March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. As of the March 6, 2015 conversion date, the Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.” | |
SOG is a private company engaged in the management of oil and natural gas properties on behalf of its related companies, with whom it has various service agreements encompassing a wide range of activities, including, but not limited to, management, administrative and operational services. SEP I and SP Holdings, LLC are related to SOG through services agreements, and SOG owns a 0.5% general partner interest in SEP I. Our proved reserves are currently located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana. | |
Basis of Presentation | |
These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries. All 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 condensed 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. | |
These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC on March 5, 2015. | |
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 on-going 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. | |
Recent Accounting Pronouncements | |
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“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 April 2015, FASB issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. | |
In February 2015, the FASB issued an ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we do not expect the impact to be material. | |
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. | |
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. | |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2015 | |
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, 2014. | |
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, 2015 and December 31, 2014. | |
Restricted Cash | |
Restricted cash, as of March 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of March 31, 2015 is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. | |
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, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively. | |
Acquisitions_And_Divestitures
Acquisitions And Divestitures | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Acquisitions And Divestitures [Abstract] | ||||||
Acquisitions And Divestitures | 3. ACQUISITIONS AND DIVESTITURES | |||||
Eagle Ford Acquisition | ||||||
On March 31, 2015, we completed our acquisition of wellbore interests in certain producing oil and natural gas properties in Gonzales County, Texas (the “Eagle Ford properties,” and such acquisition, the “Eagle Ford acquisition”) located in the Eagle Ford Shale in Gonzales County, Texas from Sanchez Energy Corporation (“SN”) for a purchase price of $85 million, subject to normal and customary closing adjustments. The effective date of the transaction was January 1, 2015. The acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for each year from 2016 through 2019, at which point, SPP’s interest in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets. | ||||||
The adjusted purchase price of $83.6 million was funded at closing with net proceeds from the private placement of 10,625,000 newly created Class A Preferred Units (the “Preferred Units”) which were issued for a cash purchase price of $1.60 per unit, resulting in gross proceeds to SPP of $17.0 million, the issuance of 1,052,632 common units to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 7, “Long-Term Debt”), and available cash. The purchase price allocation for the Eagle Ford acquisition is preliminary and is subject to further adjustments and the settlement of certain post-closing adjustments with the seller. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): | ||||||
Proved developed reserves | $ | 73,226 | ||||
Facilities | 8,039 | |||||
Fair value of hedges assumed | 3,408 | |||||
Fair value of assets acquired | 84,673 | |||||
Asset retirement obligations | -877 | |||||
Ad valorem tax liability | -194 | |||||
Fair value of net assets acquired | $ | 83,602 | ||||
Pro Forma Operating Results | ||||||
The following pro forma combined results for the three months ended March 31, 2015 and 2014 reflect the consolidated results of operations of the Partnership as if the Eagle Ford acquisition and related financing had occurred on January 1, 2014. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and paid-in-kind units issued in connection with the preferred units. | ||||||
The unaudited pro forma combined financial statements give effect to the events set forth below: | ||||||
• The Eagle Ford acquisition completed on March 31, 2015. | ||||||
• The increase in borrowings under the Credit Agreement to finance a portion of the Eagle Ford acquisition, and the related | ||||||
adjustments to interest expense. | ||||||
• Issuance of Class A Preferred Units to finance a portion of the Eagle Ford acquisition, and the related adjustments to preferred | ||||||
paid-in-kind distributions. | ||||||
• Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per | ||||||
common unit (in thousands, except per unit amounts). | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2015 | 2014 | |||||
Revenues | $ | 15,153 | $ | 25,013 | ||
Net income (loss) attributable to common unitholders | $ | -90,591 | $ | 4,348 | ||
Net income (loss) per unit prior to conversion | ||||||
Class A units - Basic and diluted | $ | -2.49 | $ | 0.05 | ||
Class B units - Basic and diluted | $ | -1.98 | $ | 0.15 | ||
Net loss per unit after conversion | ||||||
Common units - Basic and diluted | $ | -1.01 | $ | - | ||
The pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Partnership would have reported had the Eagle Ford acquisition and related financings been completed as of the date set forth in this pro forma combined financial information and should not be taken as indicative of the Partnership’s future combined results of operations. The actual results may differ significantly from that reflected in the pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the pro forma combined financial information and actual results. | ||||||
Fair_Value_Messurements
Fair Value Messurements | 3 Months Ended | ||||||||||||||
Mar. 31, 2015 | |||||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||||
Fair Value Measurements | 4. FAIR VALUE MEASUREMENTS | ||||||||||||||
Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: | |||||||||||||||
Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | |||||||||||||||
Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. | |||||||||||||||
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The valuation models used to value derivatives associated with the Partnership's oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. | |||||||||||||||
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's 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 tables summarize the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014 (in thousands): | |||||||||||||||
Fair Value Measurements at March 31, 2015 | |||||||||||||||
Active Markets for | Observable | ||||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 31-Mar-15 | |||||||||||
Derivative assets | $ | - | $ | 25,505 | $ | - | $ | - | $ | 25,505 | |||||
Derivative liabilities | - | - | - | - | - | ||||||||||
Total net assets | $ | - | $ | 25,505 | $ | - | $ | - | $ | 25,505 | |||||
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, 2014 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 2014 | |||||||||||||||
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-14 | |||||||||||
Derivative assets | $ | - | $ | 22,919 | $ | - | $ | -90 | $ | 22,829 | |||||
Derivative liabilities | - | -90 | - | 90 | - | ||||||||||
Total net assets | $ | - | $ | 22,829 | $ | - | $ | - | $ | 22,829 | |||||
As of March 31, 2015 and December 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 on a Non-Recurring Basis | |||||||||||||||
The Partnership follows the provisions of Accounting Standards Codification (“ASC”) Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. 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 under the fair value hierarchy. The fair values 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 average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Our purchase price allocation for the Eagle Ford acquisition is presented in Note 3, ‘‘Acquisitions and Divestitures.” A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 8, ‘‘Asset Retirement Obligations.’’ | |||||||||||||||
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. | |||||||||||||||
Credit Agreement – We believe that the carrying value of long-term debt for our Credit Agreement 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 Credit Agreement is discussed further in Note 7, “Long-Term Debt.” | |||||||||||||||
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 did not have any interest rate derivatives as of March 31, 2015. 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, 2015 | |||||||||||||||||||||||||
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 in natural gas sales and oil and liquids sales in the condensed consolidated statements of operations. | |||||||||||||||||||||||||
As of March 31, 2015, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: | |||||||||||||||||||||||||
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 | ||||||||||||||||
2015 | 128,712 | $ | 74.42 | 118,097 | $ | 75.10 | 109,582 | $ | 75.64 | 356,391 | $ | 75.02 | |||||||||||||
2016 | 121,005 | $ | 73.53 | 113,226 | $ | 73.77 | 106,483 | $ | 73.95 | 100,525 | $ | 74.10 | 441,239 | $ | 73.82 | ||||||||||
2017 | 57,953 | $ | 64.80 | 54,554 | $ | 64.80 | 51,570 | $ | 64.80 | 48,926 | $ | 64.80 | 213,003 | $ | 64.80 | ||||||||||
2018 | 56,798 | $ | 65.40 | 54,197 | $ | 65.40 | 51,851 | $ | 65.40 | 49,709 | $ | 65.40 | 212,555 | $ | 65.40 | ||||||||||
2019 | 52,760 | $ | 65.65 | 50,784 | $ | 65.65 | 48,960 | $ | 65.65 | 47,264 | $ | 65.65 | 199,768 | $ | 65.65 | ||||||||||
1,422,956 | |||||||||||||||||||||||||
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 | ||||||||||||||||
2015 | 1,239,273 | $ | 4.15 | 1,171,767 | $ | 4.16 | 1,118,334 | $ | 4.17 | 3,529,374 | $ | 4.16 | |||||||||||||
2016 | 1,098,689 | $ | 4.13 | 1,048,146 | $ | 4.14 | 998,394 | $ | 4.14 | 963,327 | $ | 4.14 | 4,108,556 | $ | 4.14 | ||||||||||
2017 | 80,563 | $ | 3.52 | 75,829 | $ | 3.52 | 71,672 | $ | 3.52 | 67,984 | $ | 3.52 | 296,048 | $ | 3.52 | ||||||||||
2018 | 79,042 | $ | 3.58 | 75,404 | $ | 3.58 | 72,115 | $ | 3.58 | 69,122 | $ | 3.58 | 295,683 | $ | 3.58 | ||||||||||
2019 | 73,432 | $ | 3.62 | 70,648 | $ | 3.62 | 68,088 | $ | 3.62 | 65,720 | $ | 3.62 | 277,888 | $ | 3.62 | ||||||||||
8,507,549 | |||||||||||||||||||||||||
The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the three months ended March 31, 2015 and the year ended December 31, 2014 (in thousands): | |||||||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||||||
Beginning fair value of commodity derivatives | $ | 22,829 | $ | 10,601 | |||||||||||||||||||||
Net gains on crude oil derivatives | 2,643 | 13,983 | |||||||||||||||||||||||
Net gains on natural gas derivatives | 2,189 | 5,871 | |||||||||||||||||||||||
Net settlements on derivative contracts: | |||||||||||||||||||||||||
Crude oil | -4,023 | 69 | |||||||||||||||||||||||
Natural gas | -1,541 | -7,695 | |||||||||||||||||||||||
Fair value of commodity derivatives received by novation: | |||||||||||||||||||||||||
Crude oil | 3,263 | - | |||||||||||||||||||||||
Natural gas | 145 | - | |||||||||||||||||||||||
Ending fair value of commodity derivatives | $ | 25,505 | $ | 22,829 | |||||||||||||||||||||
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 | 2015 | 2014 | ||||||||||||||||||||||
Commodity – Mark-to-Market | Oil and natural gas sales | $ | 4,832 | $ | -4,074 | ||||||||||||||||||||
Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with three 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 include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of March 31, 2015 and December 31, 2014, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. | |||||||||||||||||||||||||
Hedges Novated in the Eagle Ford Acquisition | |||||||||||||||||||||||||
As a part of the Eagle Ford acquisition, we received by novation from the seller certain hedges covering approximately 95%, 90%, 85%, 85% and 80% of estimated 2015, 2016, 2017, 2018 and 2019 oil and natural gas production from the acquired assets, respectively. The counterparty for the hedges is a lender in the Partnership’s Credit Agreement. The Partnership is responsible for all future periodic settlements of these transactions. As of March 31, 2015, the fair value of the hedges assumed resulted in a $3.4 million asset in our condensed consolidated balance sheet. | |||||||||||||||||||||||||
Oil_And_Natural_Gas_Properties
Oil And Natural Gas Properties | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
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, | December 31, | |||||
2015 | 2014 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property costs | ||||||
Proved property | $ | 731,308 | $ | 649,432 | ||
Unproved property | 1,582 | 1,560 | ||||
Land | 501 | 501 | ||||
Total property costs | 733,391 | 651,493 | ||||
Materials and supplies | 1,056 | 1,056 | ||||
Total | 734,447 | 652,549 | ||||
Less: Accumulated depreciation, depletion, amortization and impairments | -602,995 | -517,239 | ||||
Oil and natural gas properties and equipment, net | $ | 131,452 | $ | 135,310 | ||
Impairment of Oil and Natural Gas Properties and Other Non-Current Assets | ||||||
The Partnership evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. | ||||||
For the three months ended March 31, 2015, we recorded non-cash charges of $82.9 million to impair the value of our Cherokee Basin properties, Woodford Shale properties and our Texas and Louisiana properties acquired prior to the Eagle Ford acquisition. For the three months ended March 31, 2014, we recorded a non-cash charge of $0.1 million to impair the value of our Texas and Louisiana properties. The current impairment was primarily the result of a decline in commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. | ||||||
Exploration and Dry Hole Costs | ||||||
Exploration and dry hole 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. We recorded no exploration and dry hole costs for the three months ended March 31, 2015 and 2014. | ||||||
LongTerm_Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2015 | |
Long-Term Debt [Abstract] | |
Long-Term Debt | 7. LONG-TERM DEBT |
Credit Agreement | |
On March 31, 2015, the Partnership, as borrower, entered into a Third Amended and Restated Credit Agreement with Royal Bank of Canada, as administrative agent and collateral agent and the lenders party thereto, providing for a reserve-based credit facility with a maximum commitment of $500 million and a maturity date of March 31, 2020 (the “Credit Agreement”). The Partnership used $106.0 million in borrowings under the Credit Agreement on March 31, 2015 to finance the Eagle Ford acquisition, in part, and to repay $42.5 million due under the Second Amended and Restated Credit Agreement, with Societe Generale as administrative and collateral agent and a syndicate of lenders, which had a maximum commitment of $350 million and a borrowing base of $70.0 million immediately prior to its retirement. | |
Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that the Partnership and certain of its subsidiaries own as well as various security and pledge agreements among the Partnership and certain of its subsidiaries and the administrative agent. | |
The amount available for borrowing at any one time under the Credit Agreement is limited to the borrowing base for the Partnership’s oil and natural gas properties. Borrowings under the Credit Agreement are available for acquisition, exploration, operation, maintenance and development of oil and natural gas properties, payment of expenses incurred in connection with the Credit Agreement, working capital and general business purposes. The Credit Agreement has a sub-limit of $15 million which may be used for the issuance of letters of credit. The borrowing base as of March 31, 2015 was set at $110 million, of which we had $106 million outstanding. The borrowing base is re-determined semi-annually in the second and fourth quarters of the year, 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. | |
At the Partnership’s election, interest for borrowings under the Credit Agreement are determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum based on utilization plus (iii) a commitment fee between 0.375% and 0.500% 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 Credit Agreement contains various covenants that limit, among other things, the Partnership’s ability and certain of its subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of the Partnership’s assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions. Furthermore, the Credit Agreement contains financial covenants that require the Partnership to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 at all times and (ii) senior secured net debt to consolidated Adjusted EBITDA for the last twelve months of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter. | |
The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) the Partnership’s existing general partner (the “General Partner”) ceases to be the sole general partner of the Partnership or (ii) certain specified persons shall cease to own more than 50% of the equity interests of the General Partner or shall cease to control, directly or indirectly, such General Partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. | |
The Credit Agreement limits the Partnership’s ability to pay distributions to unitholders. The Partnership has the ability to pay distributions to unitholders from available cash, including cash from borrowings under the Credit Agreement, 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 Credit Agreement exceed 90% of the borrowing base, after giving effect to the proposed distribution. The Partnership’s available cash is reduced by any cash reserves established by the board of directors of the General Partner for the proper conduct of the Partnership’s business and the payment of fees and expenses. | |
The Credit Agreement permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twenty four-month period, the volumes of production hedged in any month may not exceed our projected monthly production from proved developed and producing reserves (or 90% of our projected monthly production from proved reserves); (b) for the immediately following twenty-four month period, volumes of production hedged in any month may not exceed 90% of our projected monthly production from proved developed and producing reserves (or 85% of our projected monthly production from proved reserves); (c) for the immediately following twelve month period, volumes of production hedged in any month may not exceed 85% our projected monthly production from proved developed and producing reserves (or 80% of our projected monthly production from proved reserves); and (d) no hedges may have a tenor beyond five years. The reserve-based credit facility also permits us to hedge the interest rate on up to 75% of the then-outstanding principal amounts of our indebtedness for borrowed money. | |
As of March 31, 2015, we were in compliance with the covenants of the Credit Agreement. We monitor compliance on an on-going basis. | |
Debt Issuance Costs | |
As of March 31, 2015, our unamortized debt issuance costs were $1.7 million. These costs are amortized to interest expense in our consolidated statement of operations over the life of our Credit Agreement. At December 31, 2014, our unamortized debt issuance costs were $0.7 million. | |
Asset_Retirement_Obligation
Asset Retirement Obligation | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
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 changes in the ARO for the three months ended March 31, 2015 and the year ended December 31, 2014 were as follows (in thousands): | ||||||
March 31, | December 31, | |||||
2015 | 2014 | |||||
Asset retirement obligation, beginning balance | $ | 17,031 | $ | 9,513 | ||
Liabilities added from acquisitions | 877 | 80 | ||||
Liabilities added from drilling | - | 59 | ||||
Sold | -11 | - | ||||
Revisions to cost estimates | - | 6,780 | ||||
Settlements | -5 | |||||
Accretion expense | 253 | 604 | ||||
Asset retirement obligation, ending balance | $ | 18,150 | $ | 17,031 | ||
Additional AROs 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 AROs. As of March 31, 2015 and December 31, 2014, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. | ||||||
Commitments_And_Contingencies
Commitments And Contingencies | 3 Months Ended |
Mar. 31, 2015 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | 9. COMMITMENTS AND CONTINGENCIES |
We did not have any material commitments and contingencies as of March 31, 2015. | |
Related_Party_Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transations | 10. RELATED PARTY TRANSACTIONS |
Unit Ownership | |
As of March 31, 2015, SEP I, an indirect subsidiary of SOG, owned 5,951,482, or 19.0%, of our common units and a subsidiary of SN owned 1,052,632, or 3.4%, of our common units. | |
Sanchez-Related Agreements | |
On May 8, 2014, the Company and the Manager, an affiliate of SOG, entered into the Services Agreement pursuant to which the Manager provides services that we require to operate our 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, the Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) a $1,000,000 administrative fee which was paid during 2014, (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 the Manager elects for such fee to be paid in our equity. | |
The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both the Manager and the Company provide notice to terminate the agreement. During the three months ended March 31, 2015, we paid $0.9 million to the Manager under the Services Agreement. | |
Additionally, as of March 31, 2015 and December 31, 2014, the Partnership had a net receivable from related parties of $0.2 million and $0.9 million, respectively, which are included in “Accounts receivable, net” and “Accounts payable and accrued liabilities” in the condensed consolidated balance sheets. The net receivables as of March 31, 2015 and December 31, 2014 consist primarily of revenues receivable from oil and natural gas production, offset by costs associated with that production and obligations for general and administrative costs. | |
In August 2013, the Company entered into a Registration Rights Agreement with SEP I and on May 8, 2014, the Company and SOG entered into a Contract Operating Agreement, the Company, the Manager and SOG entered into a Transition Agreement, and the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the “License Agreement”). For further discussion of these agreements, refer to our Annual Report on Form 10-K for the year ended December 31, 2014. | |
On March 6, 2015, amendments to the Services Agreement and License Agreement were executed in order to replace the Company with the Partnership as counterparty to the agreements. No other material amendments have been made to the agreements mentioned herein. The amendments are attached as exhibits to this Quarterly Report on Form 10-Q. | |
On March 31, 2015, the Partnership and SN entered into a Purchase and Sale Agreement for the acquisition of the Eagle Ford properties for a purchase price of $85 million. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.” | |
UnitBased_Compensation
Unit-Based Compensation | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Unit-Based Compensation [Abstract] | ||||||
Unit-Based Compensation | ||||||
11. UNIT-BASED COMPENSATION | ||||||
Prior to our conversion to a Delaware limited partnership on March 6, 2015, we granted restricted common unit awards to certain employees in Texas under the 2009 Omnibus Incentive Compensation Plan (the “Omnibus Plan”). The Omnibus Plan provided 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. Additionally, prior to March 6, 2015, we granted restricted common unit awards to certain field employees in Kansas and Oklahoma and to certain employees in Texas under our previous Long-Term Incentive Plan (the “Previous LTIP”). | ||||||
After the conversion to a limited partnership, both the Omnibus Plan and the Previous LTIP had no outstanding units remaining. Effective March 6, 2015, the Omnibus Plan was amended and restated and renamed the Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”). Restricted unit activity under the Omnibus Plan, the Previous LTIP, and the LTIP during the period is presented in the following table: | ||||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2014 | 100,825 | $ | 3.11 | |||
Granted | 1,288,796 | 1.7 | ||||
Vested | -794,949 | 1.86 | ||||
Returned/Cancelled | -338,262 | 1.73 | ||||
Outstanding at March 31, 2015 | 256,410 | $ | 1.65 | |||
The remaining unvested units as of March 31, 2015 belong to one employee of a subsidiary of the Partnership and are due upon request. As such, we have accelerated the recognition of the expense associated with these awards into the three months ended March 31, 2015. | ||||||
Distributions_To_Unitholders
Distributions To Unitholders | 3 Months Ended |
Mar. 31, 2015 | |
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 for the proper conduct of our business) from which to pay distributions. | |
Members_EquityPartners_Capital
Members' Equity/Partners' Capital | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Members' Equity/Partners' Capital [Abstract] | ||||||||||
Members' Equity/Partners' Capital | 13. MEMBERS’ EQUITY/PARTNERS’ CAPITAL | |||||||||
Outstanding Units | ||||||||||
As of March 31, 2015, we had 10,625,000 Class A preferred units outstanding and 31,383,036 common units outstanding, which included 256,410 unvested restricted common units issued under the LTIP. | ||||||||||
Conversion | ||||||||||
The Company’s board of managers approved a Plan of Conversion (the “Conversion”) providing for the Conversion of the Company from a limited liability company formed under the laws of the State of Delaware into Sanchez LP, a limited partnership formed under the laws of the State of Delaware. This plan was approved by the vote of the unitholders of the Company on March 6, 2015. After the Conversion, all of the rights, privileges and obligations of the Company prior to the Conversion were transferred and are now held by the Partnership. The Conversion converted each outstanding common unit of the Company into one common unit of the Partnership. The outstanding Class A units of the Company were converted into common units of the Partnership in a number equal to 2% of the Partnership’s common units outstanding immediately after the Conversion (after taking into account the conversion of such Class A units), and the outstanding Class Z unit of the Company was cancelled. In addition, a non-economic general partner interest in the Partnership was issued to our general partner, and the incentive distribution rights of the Partnership were issued to the Manager. | ||||||||||
Preferred Unit Issuance | ||||||||||
Class A Preferred Unit Offering: On March 31, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “Purchasers”), pursuant to which the Partnership sold, and the Purchasers purchased, 10,625,000 of the Partnership’s newly created Class A Preferred Units (the “Class A Preferred Units”) in a privately negotiated transaction (the “Private Placement”) for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross proceeds to the Partnership of $17 million. The Partnership used the net proceeds from this transaction, together with common units issued to SN, borrowings under the Credit Agreement, and available cash on hand, to pay the consideration in the Eagle Ford acquisition. | ||||||||||
Earnings per Unit | ||||||||||
For the period prior to our conversion, the basic net income per unit was computed from the two-class method 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 allocated net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) was allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period. | ||||||||||
Post conversion, net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the partnership agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. | ||||||||||
Our general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income. | ||||||||||
The following table presents the weighted average basic and diluted units outstanding for the periods indicated: | ||||||||||
March 6 - March 31 | January 1 - March 6 | March 31, | ||||||||
2015 | 2015 | 2014 | ||||||||
Class A units - Basic and diluted | - | 484,505 | 1,615,017 | |||||||
Class B Common units - Basic and diluted | - | 28,791,626 | 28,214,104 | |||||||
Common units - Basic and diluted | 29,928,009 | - | - | |||||||
Weighted Average basic and diluted units | 29,928,009 | 29,276,131 | 29,829,121 | |||||||
At March 31, 2015, we had 256,410 common units that were restricted unvested common units granted and outstanding. No losses were allocated to participating restricted unvested units because such securities do not have a contractual obligation to share in the Partnership’s losses. | ||||||||||
The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): | ||||||||||
Total | Class A Units | Class B Units | ||||||||
Assumed net loss to be allocated January 1 - March 6 | $ | -923 | $ | -18 | $ | -905 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.03 | ||||||
The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through March 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): | ||||||||||
Total | Common Units | |||||||||
Assumed net loss to be allocated March 6 - March 31 | $ | -89,063 | $ | -89,063 | ||||||
Basic and diluted loss per unit | $ | -2.98 | ||||||||
Net loss per unit increased significantly for the period from March 6, 2015 through March 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included a non-cash impairment charge of $82.9 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. | ||||||||||
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 | ||||||||
Assumed net loss to be allocated | $ | -2,939 | $ | -59 | $ | -2,880 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.1 | ||||||
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | 14. SUBSEQUENT EVENTS |
On April 15, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “April Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “ April Purchasers”), pursuant to which the Partnership sold, and the April Purchasers purchased, 234,375 of the Partnership’s Class A Preferred Units in a privately negotiated transaction for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross proceeds to the Partnership of $375,000. The Partnership plans to use the proceeds for general working capital purposes. | |
Organization_And_Basis_Of_Pres1
Organization And Basis Of Presentation (Policies) | 3 Months Ended |
Mar. 31, 2015 | |
Organization And Basis Of Presentation [Abstract] | |
Basis Of Presentation | Basis of Presentation |
These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries. All 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 condensed 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. | |
These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC on March 5, 2015. | |
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 on-going 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. | |
Recent Pronouncements And Accounting Changes | Recent Accounting Pronouncements |
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“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 April 2015, FASB issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. | |
In February 2015, the FASB issued an ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we do not expect the impact to be material. | |
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. | |
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. | |
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2015 | |
Summary Of Significant Accounting Policies [Abstract] | |
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, 2015 and December 31, 2014. | |
Restricted Cash | Restricted Cash |
Restricted cash, as of March 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of March 31, 2015 is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. | |
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, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively. | |
Acquisitions_And_Divestitures_
Acquisitions And Divestitures (Tables) | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Acquisitions And Divestitures [Abstract] | ||||||
Estimated Values Of Assets Acquired And Liabilities Assumed | ||||||
Proved developed reserves | $ | 73,226 | ||||
Facilities | 8,039 | |||||
Fair value of hedges assumed | 3,408 | |||||
Fair value of assets acquired | 84,673 | |||||
Asset retirement obligations | -877 | |||||
Ad valorem tax liability | -194 | |||||
Fair value of net assets acquired | $ | 83,602 | ||||
Supplemental Pro Forma Information | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2015 | 2014 | |||||
Revenues | $ | 15,153 | $ | 25,013 | ||
Net income (loss) attributable to common unitholders | $ | -90,591 | $ | 4,348 | ||
Net income (loss) per unit prior to conversion | ||||||
Class A units - Basic and diluted | $ | -2.49 | $ | 0.05 | ||
Class B units - Basic and diluted | $ | -1.98 | $ | 0.15 | ||
Net loss per unit after conversion | ||||||
Common units - Basic and diluted | $ | -1.01 | $ | - | ||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 3 Months Ended | ||||||||||||||
Mar. 31, 2015 | |||||||||||||||
Fair Value Measurements [Abstract] | |||||||||||||||
Fair Value Of Assets And Liabilities On A Recurring Basis | The following tables summarize the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2015 and December 31, 2014 (in thousands): | ||||||||||||||
Fair Value Measurements at March 31, 2015 | |||||||||||||||
Active Markets for | Observable | ||||||||||||||
Identical Assets | Inputs | Unobservable Inputs | Netting Cash and | Fair Value at | |||||||||||
(Level 1) | (Level 2) | (Level 3) | Collateral | 31-Mar-15 | |||||||||||
Derivative assets | $ | - | $ | 25,505 | $ | - | $ | - | $ | 25,505 | |||||
Derivative liabilities | - | - | - | - | - | ||||||||||
Total net assets | $ | - | $ | 25,505 | $ | - | $ | - | $ | 25,505 | |||||
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, 2014 (in thousands): | |||||||||||||||
Fair Value Measurements at December 31, 2014 | |||||||||||||||
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-14 | |||||||||||
Derivative assets | $ | - | $ | 22,919 | $ | - | $ | -90 | $ | 22,829 | |||||
Derivative liabilities | - | -90 | - | 90 | - | ||||||||||
Total net assets | $ | - | $ | 22,829 | $ | - | $ | - | $ | 22,829 | |||||
Derivative_And_Financial_Instr1
Derivative And Financial Instruments (Tables) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||
Derivative And Financial Instruments [Abstract] | |||||||||||||||||||||||||
Summary Of Hedges In Place | 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 | ||||||||||||||||
2015 | 128,712 | $ | 74.42 | 118,097 | $ | 75.10 | 109,582 | $ | 75.64 | 356,391 | $ | 75.02 | |||||||||||||
2016 | 121,005 | $ | 73.53 | 113,226 | $ | 73.77 | 106,483 | $ | 73.95 | 100,525 | $ | 74.10 | 441,239 | $ | 73.82 | ||||||||||
2017 | 57,953 | $ | 64.80 | 54,554 | $ | 64.80 | 51,570 | $ | 64.80 | 48,926 | $ | 64.80 | 213,003 | $ | 64.80 | ||||||||||
2018 | 56,798 | $ | 65.40 | 54,197 | $ | 65.40 | 51,851 | $ | 65.40 | 49,709 | $ | 65.40 | 212,555 | $ | 65.40 | ||||||||||
2019 | 52,760 | $ | 65.65 | 50,784 | $ | 65.65 | 48,960 | $ | 65.65 | 47,264 | $ | 65.65 | 199,768 | $ | 65.65 | ||||||||||
1,422,956 | |||||||||||||||||||||||||
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 | ||||||||||||||||
2015 | 1,239,273 | $ | 4.15 | 1,171,767 | $ | 4.16 | 1,118,334 | $ | 4.17 | 3,529,374 | $ | 4.16 | |||||||||||||
2016 | 1,098,689 | $ | 4.13 | 1,048,146 | $ | 4.14 | 998,394 | $ | 4.14 | 963,327 | $ | 4.14 | 4,108,556 | $ | 4.14 | ||||||||||
2017 | 80,563 | $ | 3.52 | 75,829 | $ | 3.52 | 71,672 | $ | 3.52 | 67,984 | $ | 3.52 | 296,048 | $ | 3.52 | ||||||||||
2018 | 79,042 | $ | 3.58 | 75,404 | $ | 3.58 | 72,115 | $ | 3.58 | 69,122 | $ | 3.58 | 295,683 | $ | 3.58 | ||||||||||
2019 | 73,432 | $ | 3.62 | 70,648 | $ | 3.62 | 68,088 | $ | 3.62 | 65,720 | $ | 3.62 | 277,888 | $ | 3.62 | ||||||||||
8,507,549 | |||||||||||||||||||||||||
Schedule Of Change In Commodity Derivatives Fair Value | |||||||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||||||
Beginning fair value of commodity derivatives | $ | 22,829 | $ | 10,601 | |||||||||||||||||||||
Net gains on crude oil derivatives | 2,643 | 13,983 | |||||||||||||||||||||||
Net gains on natural gas derivatives | 2,189 | 5,871 | |||||||||||||||||||||||
Net settlements on derivative contracts: | |||||||||||||||||||||||||
Crude oil | -4,023 | 69 | |||||||||||||||||||||||
Natural gas | -1,541 | -7,695 | |||||||||||||||||||||||
Fair value of commodity derivatives received by novation: | |||||||||||||||||||||||||
Crude oil | 3,263 | - | |||||||||||||||||||||||
Natural gas | 145 | - | |||||||||||||||||||||||
Ending fair value of commodity derivatives | $ | 25,505 | $ | 22,829 | |||||||||||||||||||||
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 | 2015 | 2014 | ||||||||||||||||||||||
Commodity – Mark-to-Market | Oil and natural gas sales | $ | 4,832 | $ | -4,074 | ||||||||||||||||||||
Oil_And_Natural_Gas_Properties1
Oil And Natural Gas Properties (Tables) | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Oil And Natural Gas Properties [Abstract] | ||||||
Oil and Natural Gas Properties | ||||||
March 31, | December 31, | |||||
2015 | 2014 | |||||
Oil and natural gas properties and related equipment | ||||||
(successful efforts method) | ||||||
Property costs | ||||||
Proved property | $ | 731,308 | $ | 649,432 | ||
Unproved property | 1,582 | 1,560 | ||||
Land | 501 | 501 | ||||
Total property costs | 733,391 | 651,493 | ||||
Materials and supplies | 1,056 | 1,056 | ||||
Total | 734,447 | 652,549 | ||||
Less: Accumulated depreciation, depletion, amortization and impairments | -602,995 | -517,239 | ||||
Oil and natural gas properties and equipment, net | $ | 131,452 | $ | 135,310 | ||
Asset_Retirement_Obligation_Ta
Asset Retirement Obligation (Tables) | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Asset Retirement Obligation [Abstract] | ||||||
Reconciliation of Asset Retirement Obligation | ||||||
March 31, | December 31, | |||||
2015 | 2014 | |||||
Asset retirement obligation, beginning balance | $ | 17,031 | $ | 9,513 | ||
Liabilities added from acquisitions | 877 | 80 | ||||
Liabilities added from drilling | - | 59 | ||||
Sold | -11 | - | ||||
Revisions to cost estimates | - | 6,780 | ||||
Settlements | -5 | |||||
Accretion expense | 253 | 604 | ||||
Asset retirement obligation, ending balance | $ | 18,150 | $ | 17,031 | ||
UnitBased_Compensation_Tables
Unit-Based Compensation (Tables) | 3 Months Ended | |||||
Mar. 31, 2015 | ||||||
Unit-Based Compensation [Abstract] | ||||||
Schedule Of Units Granted | ||||||
Weighted | ||||||
Average | ||||||
Number of | Grant Date | |||||
Restricted | Fair Value | |||||
Units | Per Unit | |||||
Outstanding at December 31, 2014 | 100,825 | $ | 3.11 | |||
Granted | 1,288,796 | 1.7 | ||||
Vested | -794,949 | 1.86 | ||||
Returned/Cancelled | -338,262 | 1.73 | ||||
Outstanding at March 31, 2015 | 256,410 | $ | 1.65 | |||
Members_EquityPartners_Capital1
Members' Equity/Partners' Capital (Tables) | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Members' Equity/Partners' Capital [Abstract] | ||||||||||
Schedule Of Weighted Average Units Outstanding | ||||||||||
March 6 - March 31 | January 1 - March 6 | March 31, | ||||||||
2015 | 2015 | 2014 | ||||||||
Class A units - Basic and diluted | - | 484,505 | 1,615,017 | |||||||
Class B Common units - Basic and diluted | - | 28,791,626 | 28,214,104 | |||||||
Common units - Basic and diluted | 29,928,009 | - | - | |||||||
Weighted Average basic and diluted units | 29,928,009 | 29,276,131 | 29,829,121 | |||||||
Earnings Per Common Unit Amounts | The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): | |||||||||
Total | Class A Units | Class B Units | ||||||||
Assumed net loss to be allocated January 1 - March 6 | $ | -923 | $ | -18 | $ | -905 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.03 | ||||||
The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through March 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): | ||||||||||
Total | Common Units | |||||||||
Assumed net loss to be allocated March 6 - March 31 | $ | -89,063 | $ | -89,063 | ||||||
Basic and diluted loss per unit | $ | -2.98 | ||||||||
Net loss per unit increased significantly for the period from March 6, 2015 through March 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included a non-cash impairment charge of $82.9 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. | ||||||||||
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 | ||||||||
Assumed net loss to be allocated | $ | -2,939 | $ | -59 | $ | -2,880 | ||||
Basic and diluted loss per unit | $ | -0.04 | $ | -0.1 | ||||||
Organization_And_Basis_Of_Pres2
Organization And Basis Of Presentation (Details) (Sanchez Energy Partners I [Member], Sanchez Oil And Gas Properties [Member]) | Mar. 31, 2015 |
Sanchez Energy Partners I [Member] | Sanchez Oil And Gas Properties [Member] | |
Organization [Line Items] | |
Ownership percentage | 0.50% |
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Summary Of Significant Accounting Policies [Abstract] | ||
Restricted cash held in escrow | $0.60 | $1.70 |
Allowance for doubtful accounts | $0.40 | $0.20 |
Acquisitions_And_Divestitures_1
Acquisitions And Divestitures (Narrative) (Details) (USD $) | 3 Months Ended | 0 Months Ended |
Mar. 31, 2015 | Mar. 31, 2015 | |
Business Acquisition [Line Items] | ||
Proceeds from issuance of preferred units | $17,000,000 | |
Eagle Ford [Member] | ||
Business Acquisition [Line Items] | ||
Purchase price | 84,673,000 | 84,673,000 |
Adjusted purchase price | 83,602,000 | 83,602,000 |
Eagle Ford [Member] | Class A Preferred Units [Member] | ||
Business Acquisition [Line Items] | ||
Shares issued | 10,625,000 | |
Value of shares issued to Seller | $1.60 | $1.60 |
SN [Member] | Eagle Ford [Member] | Class A Preferred Units [Member] | ||
Business Acquisition [Line Items] | ||
Shares issued | 1,052,632 |
Acquisitions_And_Divestitures_2
Acquisitions And Divestitures (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) (Eagle Ford [Member], USD $) | Mar. 31, 2015 |
In Thousands, unless otherwise specified | |
Eagle Ford [Member] | |
Business Acquisition [Line Items] | |
Proved developed reserves | $73,226 |
Facilities | 8,039 |
Fair value of hedges assumed | 3,408 |
Fair value of assets acquired | 84,673 |
Asset retirement obligations | -877 |
Fair value of net assets acquired | -194 |
Fair value of net assets acquired | $83,602 |
Acquisitions_And_Divestitures_3
Acquisitions And Divestitures (Supplemental Pro Forma Information) (Details) (USD $) | 3 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Business Acquisition [Line Items] | ||
Revenue | $15,153 | $25,013 |
Net income (loss) attributable to common unitholders | ($90,591) | $4,348 |
Net loss per unit after conversion | ($1.01) | |
Common Class A [Member] | ||
Business Acquisition [Line Items] | ||
Net income (loss) prior to conversion | ($2.49) | $0.05 |
Common Class B [Member] | ||
Business Acquisition [Line Items] | ||
Net income (loss) prior to conversion | ($1.98) | $0.15 |
Fair_Value_Measurements_Fair_V
Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | $25,505 | $22,829 |
Total net assets | 25,505 | 22,829 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | 25,505 | 22,919 |
Derivative liabilities | -90 | |
Total net assets | 25,505 | 22,829 |
Netting Cash And Collateral [Member] | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | -90 | |
Derivative liabilities | $90 |
Derivative_And_Financial_Instr2
Derivative And Financial Instruments (Narrative) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Oil and natural gas production, 2015 | 95.00% | |
Oil and natural gas production, 2016 | 90.00% | |
Oil and natural gas production, 2017 | 85.00% | |
Oil and natural gas production, 2018 | 85.00% | |
Oil and natural gas production, 2019 | 80.00% | |
Fair value of derivative instruments | $16,001 | $14,671 |
Eagle Ford [Member] | ||
Derivative [Line Items] | ||
Fair value of derivative instruments | $3,400 |
Derivative_And_Financial_Instr3
Derivative And Financial Instruments (Summary Of Hedges In Place) (Details) | 3 Months Ended |
Mar. 31, 2015 | |
bbl | |
West Texas Intermediate 2015 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 128,712 |
Average Price | 74.42 |
West Texas Intermediate 2015 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 118,097 |
Average Price | 75.1 |
West Texas Intermediate 2015 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 109,582 |
Average Price | 75.64 |
West Texas Intermediate 2015 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 356,391 |
Average Price | 75.02 |
West Texas Intermediate 2016 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 121,005 |
Average Price | 73.53 |
West Texas Intermediate 2016 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 113,226 |
Average Price | 73.77 |
West Texas Intermediate 2016 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 106,483 |
Average Price | 73.95 |
West Texas Intermediate 2016 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 100,525 |
Average Price | 74.1 |
West Texas Intermediate 2016 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 441,239 |
Average Price | 73.82 |
West Texas Intermediate 2017 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 57,953 |
Average Price | 64.8 |
West Texas Intermediate 2017 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 54,554 |
Average Price | 64.8 |
West Texas Intermediate 2017 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 51,570 |
Average Price | 64.8 |
West Texas Intermediate 2017 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 48,926 |
Average Price | 64.8 |
West Texas Intermediate 2017 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 213,003 |
Average Price | 64.8 |
West Texas Intermediate 2018 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 56,798 |
Average Price | 65.4 |
West Texas Intermediate 2018 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 54,197 |
Average Price | 65.4 |
West Texas Intermediate 2018 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 51,851 |
Average Price | 65.4 |
West Texas Intermediate 2018 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 49,709 |
Average Price | 65.4 |
West Texas Intermediate 2018 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 212,555 |
Average Price | 65.4 |
West Texas Intermediate 2019 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 52,760 |
Average Price | 65.65 |
West Texas Intermediate 2019 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 50,784 |
Average Price | 65.65 |
West Texas Intermediate 2019 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 48,960 |
Average Price | 65.65 |
West Texas Intermediate 2019 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 47,264 |
Average Price | 65.65 |
West Texas Intermediate 2019 [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 199,768 |
Average Price | 65.65 |
West Texas Intermediate [Member] | |
Derivative [Line Items] | |
Volume (in Bbls) | 1,422,956 |
NYMEX 2015 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 1,239,273 |
Average Price | 4.15 |
NYMEX 2015 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 1,171,767 |
Average Price | 4.16 |
NYMEX 2015 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 1,118,334 |
Average Price | 4.17 |
NYMEX 2015 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 3,529,374 |
Average Price | 4.16 |
NYMEX 2016 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 1,098,689 |
Average Price | 4.13 |
NYMEX 2016 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 1,048,146 |
Average Price | 4.14 |
NYMEX 2016 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 998,394 |
Average Price | 4.14 |
NYMEX 2016 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 963,327 |
Average Price | 4.14 |
NYMEX 2016 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 4,108,556 |
Average Price | 4.14 |
NYMEX 2017 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 80,563 |
Average Price | 3.52 |
NYMEX 2017 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 75,829 |
Average Price | 3.52 |
NYMEX 2017 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 71,672 |
Average Price | 3.52 |
NYMEX 2017 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 67,984 |
Average Price | 3.52 |
NYMEX 2017 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 296,048 |
Average Price | 3.52 |
NYMEX 2018 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 79,042 |
Average Price | 3.58 |
NYMEX 2018 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 75,404 |
Average Price | 3.58 |
NYMEX 2018 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 72,115 |
Average Price | 3.58 |
NYMEX 2018 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 69,122 |
Average Price | 3.58 |
NYMEX 2018 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 295,683 |
Average Price | 3.58 |
NYMEX 2019 Swap Quarter 1 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 73,432 |
Average Price | 3.62 |
NYMEX 2019 Swap Quarter 2 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 70,648 |
Average Price | 3.62 |
NYMEX 2019 Swap Quarter 3 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 68,088 |
Average Price | 3.62 |
NYMEX 2019 Swap Quarter 4 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 65,720 |
Average Price | 3.62 |
NYMEX 2019 [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 277,888 |
Average Price | 3.62 |
NYMEX [Member] | |
Derivative [Line Items] | |
Volume (in MMBtu) | 8,507,549 |
Derivative_And_Financial_Instr4
Derivative And Financial Instruments (Schedule Of Change In Commodity Derivatives Fair Value) (Details) (USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 |
Derivative Instruments Gain Loss [Line Items] | ||||
Beginning fair value of commodity derivatives | $22,829 | $10,601 | ||
Ending fair value of commodity derivatives | 25,505 | 22,829 | 22,829 | 10,601 |
Crude Oil Derivatives [Member] | ||||
Derivative Instruments Gain Loss [Line Items] | ||||
Net gains on derivatives | 2,643 | 13,983 | ||
Net settlements on derivative contracts | -4,023 | 69 | ||
Fair value of commodity derivatives received by novation | 3,263 | |||
Natural Gas Derivatives [Member] | ||||
Derivative Instruments Gain Loss [Line Items] | ||||
Net gains on derivatives | 2,189 | 5,871 | ||
Net settlements on derivative contracts | -1,541 | -7,695 | ||
Fair value of commodity derivatives received by novation | $145 |
Derivative_And_Financial_Instr5
Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (Oil And Natural Gas Sales [Member], USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Oil And Natural Gas Sales [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative gains (losses) recognized in income | $4,832 | ($4,074) |
Oil_And_Natural_Gas_Properties2
Oil And Natural Gas Properties (Narrative) (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Oil And Natural Gas Properties [Abstract] | ||
Asset Impairments | $82,865 | $149 |
Exploration costs | $0 | $0 |
Oil_And_Natural_Gas_Properties3
Oil And Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Oil And Natural Gas Properties [Abstract] | ||
Proved property | $731,308 | $649,432 |
Unproved property | 1,582 | 1,560 |
Land | 501 | 501 |
Total property costs | 733,391 | 651,493 |
Materials and supplies | 1,056 | 1,056 |
Total | 734,447 | 652,549 |
Less: Accumulated depreciation, depletion, amortization and impairments | -602,995 | -517,239 |
Oil and natural gas properties and equipment, net | $131,452 | $135,310 |
LongTerm_Debt_Details
Long-Term Debt (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Outstanding debt under reserve-based credit facility | $106,000,000 | $42,500,000 |
Unamortized debt issue costs | 1,700,000 | 700,000 |
Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Reserve based credit facility maximum borrowing capacity | 500,000,000 | |
Borrowing base amount | 110,000,000 | |
Amount borrowed under credit facility | 106,000,000 | |
Sub-limit of reserve-based credit facility | 15,000,000 | |
Outstanding debt under reserve-based credit facility | 106,000,000 | |
Projected monthly production from proved reserves, first 24 months | 90.00% | |
Projected monthly production from proved developed and producing reserves | 90.00% | |
Projected monthly production from proved reserves, following 24 month period | 85.00% | |
Projected monthly production from proved developed and producing reserves, following 12 month period | 85.00% | |
Projected monthly production from proved reserves following 12 month period | 80.00% | |
Maximum term on hedge | 5 years | |
Maximum hedge on interest rate | 75.00% | |
Second Amended And Restated Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Reserve based credit facility maximum borrowing capacity | 350,000,000 | |
Borrowing base amount | 70,000,000 | |
Outstanding debt under reserve-based credit facility | $42,500,000 | |
Minimum [Member] | Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Commitment fee on unutilized borrowing base | 0.38% | |
Consolidated current asset ratio | 1 | |
Ownership percentage by subsidiary | 50.00% | |
Exceeding of reserve-based credit facility over borrowing base | 90.00% | |
Minimum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||
Line of Credit Facility [Line Items] | ||
Interest rate | 1.75% | |
Minimum [Member] | Credit Agreement [Member] | ABR [Member] | ||
Line of Credit Facility [Line Items] | ||
Interest rate | 0.75% | |
Maximum [Member] | Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Commitment fee on unutilized borrowing base | 0.50% | |
Total Net Debt ratio | 3.5 | |
Maximum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||
Line of Credit Facility [Line Items] | ||
Interest rate | 2.75% | |
Maximum [Member] | Credit Agreement [Member] | ABR [Member] | ||
Line of Credit Facility [Line Items] | ||
Interest rate | 1.75% |
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, 2015 | Mar. 31, 2014 | Dec. 31, 2014 |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligation, beginning balance | $17,031 | $9,513 | $9,513 |
Liabilities added from acquisitions | 877 | 80 | |
Liabilities added from drilling | 59 | ||
Sold | -11 | ||
Revisions to cost estimates | 6,780 | ||
Settlements | -5 | ||
Accretion expense | 253 | 150 | 604 |
Asset retirement obligation, ending balance | $18,150 | $17,031 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Related Party Transaction [Line Items] | ||
Units owned by third party | 1,052,632 | |
Units owned by third party, percentage of total shares | 3.40% | |
Percent of value of properties held used to compute quarterly fee | 0.38% | |
Administrative fee | $1,000,000 | |
Maximum asset acquisition, disposition and financing fee | 2.00% | |
Term of Services Agreement | 10 years | |
Term of Services Agreement renewal | 10 years | |
Administrative fee paid | 900,000 | |
Net receivable from related parties | 200,000 | 900,000 |
Sanchez Energy Partners I [Member] | ||
Related Party Transaction [Line Items] | ||
Units owned by third party | 5,951,482 | |
Units owned by third party, percentage of total shares | 19.00% | |
Eagle Ford [Member] | ||
Related Party Transaction [Line Items] | ||
Purchase price | $84,673,000 |
UnitBased_Compensation_Schedul
Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $) | 3 Months Ended |
Mar. 31, 2015 | |
Unit-Based Compensation [Abstract] | |
Number of Restricted Units, Outstanding | 100,825 |
Number of Restricted Units, Granted | 1,288,796 |
Number of Restricted Units, Vested | -794,949 |
Number of Restricted Units, Returned/Cancelled | -338,262 |
Number of Restricted Units, Outstanding | 256,410 |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $3.11 |
Weighted Averaged Grant Date Fair Value Per Unit, Granted | $1.70 |
Weighted Averaged Grant Date Fair Value Per Unit, Vested | $1.86 |
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled | $1.73 |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $1.65 |
Members_EquityPartners_Capital2
Members' Equity/Partners' Capital (Narrative) (Details) (USD $) | 0 Months Ended | 3 Months Ended | 0 Months Ended | ||
Mar. 06, 2015 | Mar. 31, 2015 | Mar. 31, 2014 | Mar. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Common units outstanding | 31,383,036 | 31,383,036 | |||
Percent of common units outstanding | 2.00% | ||||
Proceeds from issuance of preferred units | $17,000,000 | ||||
Restricted unvested common units granted and outstanding | 256,410 | 256,410 | 100,825 | ||
Asset impairments | 82,865,000 | 149,000 | |||
Long Term Incentive Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Common units outstanding | 256,410 | 256,410 | |||
Class A Preferred Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Preferred units outstanding | 10,625,000 | 10,625,000 | 0 | ||
Preferred units sold | 10,625,000 | 10,625,000 | 0 | ||
Common Class A [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Common units outstanding | 0 | 0 | 484,505 | ||
Common Class B [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Common units outstanding | 0 | 0 | 28,792,584 | ||
Purchasers [Member] | Class A Preferred Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Preferred units sold | 10,625,000 | 10,625,000 | |||
Price per unit sold | $1.60 | $1.60 | |||
Proceeds from issuance of preferred units | $17,000,000 |
Members_EquityPartners_Capital3
Members' Equity/Partners' Capital (Schedule Of Weighted Average Units Outstanding) (Details) | 1 Months Ended | 2 Months Ended | 3 Months Ended |
Mar. 31, 2015 | Mar. 05, 2015 | Mar. 31, 2014 | |
Class Of Stock [Line Items] | |||
Weighted average units outstanding - Basic and Diluted | 29,276,131 | 29,928,009 | 29,829,121 |
Common Class A [Member] | |||
Class Of Stock [Line Items] | |||
Weighted average units outstanding - Basic and Diluted | 484,505 | 1,615,017 | |
Common Class B [Member] | |||
Class Of Stock [Line Items] | |||
Weighted average units outstanding - Basic and Diluted | 28,791,626 | 28,214,104 | |
Common Units [Member] | |||
Class Of Stock [Line Items] | |||
Weighted average units outstanding - Basic and Diluted | 29,928,009 |
Members_EquityPartners_Capital4
Members' Equity/Partners' Capital (Earnings Per Common Unit Amounts) (Details) (USD $) | 1 Months Ended | 2 Months Ended | 3 Months Ended |
In Thousands, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 05, 2015 | Mar. 31, 2014 |
Class Of Stock [Line Items] | |||
Loss from continuing operations | ($89,063) | ($923) | ($2,939) |
Common Class A [Member] | |||
Class Of Stock [Line Items] | |||
Loss from continuing operations | -18 | -59 | |
Basic and diluted loss per unit | ($0.04) | ($0.04) | |
Common Class B [Member] | |||
Class Of Stock [Line Items] | |||
Loss from continuing operations | -905 | -2,880 | |
Basic and diluted loss per unit | ($0.03) | ($0.10) | |
Common Units [Member] | |||
Class Of Stock [Line Items] | |||
Loss from continuing operations | ($89,063) | ||
Basic and diluted loss per unit | ($2.98) |
Subsequent_Events_Details
Subsequent Events (Details) (USD $) | 3 Months Ended | 0 Months Ended | |
Mar. 31, 2015 | Apr. 15, 2015 | Dec. 31, 2014 | |
Subsequent Event [Line Items] | |||
Proceeds from issuance of preferred units | $17,000,000 | ||
Class A Preferred Units [Member] | |||
Subsequent Event [Line Items] | |||
Preferred units sold | 10,625,000 | 0 | |
Class A Preferred Units [Member] | Subsequent Event [Member] | April Purchasers [Member] | |||
Subsequent Event [Line Items] | |||
Preferred units sold | 234,375 | ||
Price per unit sold | $1.60 | ||
Proceeds from issuance of preferred units | $375,000 |