| Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
| Dec. 31, 2016 |
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
| Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation: Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity. We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements. |
| Chapter 11 Proceedings | Chapter 11 Proceedings On February 1, 2017 (the “Chapter 11 Filing Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. See Note 2 for a discussion of the Chapter 11 Proceedings (as defined in Note 2). Chapter 11 Proceedings Commencement of Bankruptcy Cases On February 1, 2017 , the Company and certain subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the Chapter 11 Cases under the caption “In re Vanguard Natural Resources, LLC, et al.” The subsidiary Debtors in the Chapter 11 Cases are VNRF; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUDC II; ERAP; ERAP II; EAC; and EOC. No trustee has been appointed and the Company will continue to manage itself and its affiliates and operate their businesses as “debtors-in-possession” subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. The Company expects to continue its operations without interruption during the pendency of the Chapter 11 Cases. To assure ordinary course operations, the Debtors secured orders from the Bankruptcy Court approving a variety of “first day” motions, including motions that authorize the Debtors to maintain their existing cash management system, to secure debtor-in-possession financing and other customary relief. These motions are designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. Restructuring Support Agreement Prior to the filing of the Petitions, on February 1, 2017, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) certain holders (the “Consenting 2020 Noteholders”) constituting approximately 52% of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”); (ii) certain holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders) constituting approximately 10% of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the “Consenting Second Lien Noteholders” and, together with the Consenting Senior Noteholders, the “Restructuring Support Parties”) constituting approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”). The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases. The Restructuring Transactions will be financed by (i) use of cash collateral, (ii) the proposed DIP Credit Agreement (as described below), (iii) a fully committed $19.25 million equity investment (the “Second Lien Investment”) by the Consenting Second Lien Noteholders and (iv) a $255.75 million rights offering (the “Senior Note Rights Offering”) that is fully backstopped by the Consenting Senior Noteholders. Certain principal terms of the Plan are outlined below: • Allowed claims (“First Lien Claims”) under the Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”) will be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and may be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims will participate in a new Company $1.1 billion reserve-based lending facility (the “New Facility”) on terms substantially the same as the Reserve-Based Credit Facility and provided by some or all of the lenders under the Reserve-Based Credit Facility. • Allowed Second Lien Claims will receive new notes in the current principal amount of approximately $75.6 million , which shall be substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate. • Each holder of an allowed Senior Note Claim shall receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering. • If the Plan is accepted by the classes of general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units will receive their pro rata share of (a) 3% of the New Equity Interests and (b) three -year warrants for 3% of the New Equity Interests. • The Plan will provide for the $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims will execute a backstop commitment agreement whereby they will agree to fully backstop the Senior Note Rights Offering. • The Plan will provide for the Second Lien Investors to purchase $19.25 million in New Equity Interests at a 25% discount to the Company’s total enterprise value. The Plan will provide for the establishment of a customary management incentive plan at the Company under which 10% of the New Equity Interests will be reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities. The Plan will provide for releases of specified claims held by the Debtors, the Restructuring Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions. The Restructuring Support Agreement obligates the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan. The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. The Restructuring Support Agreement is subject to termination if the effective date of the Plan has not occurred within 150 days of the filing of the Petitions. There can be no assurances that the Restructuring Transactions will be consummated. The Administrative Agent (as defined in the Restructuring Agreement) under the Reserve-Based Credit Facility and the financial institutions party thereto (the “First Lien Lenders”) have not executed the Restructuring Support Agreement, and the New Facility will be subject to the approval of the Administrative Agent and First Lien Lenders in all respects. The Company and the Restructuring Support Parties expect to engage with the First Lien Lenders in an effort to agree upon mutually acceptable terms of the New Facility. Debtor-in-Possession Financing In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The proposed DIP Credit Agreement, if approved by the Bankruptcy Court, contains the following terms: • a revolving credit facility in the aggregate amount of up to $50.0 million , and $15.0 million available on an interim basis; • proceeds of the DIP Credit Agreement may be used by the DIP Borrower to (i) pay certain costs and expenses related to the Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court; • the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court has not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement; • interest will accrue at a rate per year equal to the LIBOR rate plus 5.50% ; • in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay to the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the DIP Credit Agreement, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid; • the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion, (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion; • the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and • the DIP Credit Agreement is subject to customary covenants, prepayment events, events of default and other provisions. The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion. Acceleration of Debt Obligations The commencement of the Chapter 11 Cases described above constitutes an event of default that accelerated the Debtors’ obligations under the following debt instruments (the “Debt Instruments”). Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code. • $1.25 billion in unpaid principal and approximately $0.2 million of undrawn letters of credit, plus interest, fees, and other expenses arising under or in connection with the Reserve-Based Credit Facility; • $51.12 million in unpaid principal, plus interest, fees, and other expenses, arising under or in connection with the Senior Notes due 2019 issued pursuant to that certain Indenture, dated as of May 27, 2011, as amended, by and among the Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the guarantors named therein, and U.S. Bank, National Association, as indenture trustee. VO became the issuer of the Senior Notes due 2019 pursuant to the Fourth Supplemental Indenture effective as of October 8, 2015, among VO, the Subsidiary Guarantors named therein, as guarantors and U.S. Bank, National Association. Wilmington Trust, National Association, is the successor indenture trustee to the Senior Notes due 2019. • $381.83 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Senior Notes due 2020 issued pursuant to that certain Indenture, dated as of April 4, 2012, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. UMB Bank, N.A., is the successor indenture trustee to the Senior Notes due 2020. • $75.63 million in unpaid principal, plus interest, fees, and other expenses, arising in connection with the Second Lien Notes issued pursuant to that certain Indenture, dated as of February 10, 2016, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. The Delaware Trust Company is the successor indenture trustee to the Second Lien Notes. The commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility, Second Lien Secured Notes, Senior Notes due 2020 and Senior Notes 2019 are classified as current in the accompanying consolidated balance sheet as of December 31, 2016. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Going Concern The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern. |
| New Pronouncement Issued But Not Yet Adopted | New Pronouncements Issued But Not Yet Adopted: In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five-step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation and begun contract review and documentation. The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catch-up transition method). The Company is currently evaluating the available adoption methods. In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16, pursuant to Staff Announcements at the March 3, EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU provide clarifying guidance in certain narrow areas and adds some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on the calculation or presentation of our results of operations, cash flows, or financial position. In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) to simplify the accounting for goodwill impairment. The guidance eliminates the need for Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The new standard also eliminates the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. The revised guidance will be applied prospectively, and is effective for public companies for fiscal years beginning January 1, 2020. Early adoption is permitted for any impairment tests performed after January 1, 2017. The Company plans to early adopt this guidance and will apply it prospectively for all goodwill impairment tests performed on or after January 1, 2017. As a result of adopting this guidance, we do not expect to record a goodwill impairment in the near term due to the negative carrying value of the reporting unit at December 31, 2016. |
| Cash Equivalents | Cash Equivalents: The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. |
| Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts: Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method. |
| Inventory | Inventory: Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets. |
| Oil and Natural Gas Properties | Oil and Natural Gas Properties: The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and natural gas liquids (“NGLs”) reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below. Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values. Capitalized costs are limited to a ceiling based on the present value of estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (the “12-month average price”), discounted at 10% , plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2016 of $494.3 million . Such impairment was recognized during the first, second and fourth quarters of 2016 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2016 $ 207,764 $2.41 $46.16 Second quarter 2016 $ 157,894 $2.24 $42.91 Third quarter 2016 $ — $2.29 $41.48 Fourth quarter 2016 $ 128,612 $2.47 $42.60 Total $ 494,270 The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2016 were the reduction in our proved reserves quantities due to the reclassification of our proved undeveloped reserves to contingent resources due to uncertainties surrounding the availability of financing that would be necessary to develop these reserves and the impact of sustained lower commodity prices. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices. Such impairment was recorded during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows: Impairment Amount (in thousands) Natural Gas ($ per MMBtu) Oil ($ per Bbl) First quarter 2015 $ 132,610 $3.91 $82.62 Second quarter 2015 $ 733,365 $3.44 $71.51 Third quarter 2015 $ 491,487 $3.11 $59.23 Fourth quarter 2015 $ 484,855 $2.62 $50.20 Total $ 1,842,317 The most significant factors affecting the 2015 impairment were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisition date) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas property costs for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties. |
| Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets: We account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (ASC) Topic 350, “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist using a two-step process. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach based on our quoted common unit price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary. If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. In addition, if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test is performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, we evaluate any adverse qualitative factors. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. As described above, the key inputs used in estimating the fair value of our reporting unit are our common unit price, number of common units outstanding and a control premium. There is no uncertainty associated with our common unit price and number of common units outstanding. The control premium is based on market data of actual control premiums in our industry. Changes in the common unit price, which could result from further significant declines in the prices of oil and natural gas or significant negative reserve adjustments, or changes in market data as it relates to control premiums in the oil and gas extraction industry could change our estimate of the fair value of the reporting unit and could result in a non-cash impairment charge. We performed our annual impairment tests during 2016 , 2015 and 2014 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we also performed interim impairment tests at each quarter end, commencing with the quarter ended December 31, 2014. At each measurement date, if the Company was required to perform the second step of the goodwill impairment test, the fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties included: (i) observable forward prices for commodities at the respective measurement date and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. At the respective measurement dates of March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016 , the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test at these interim dates. Based on the results of the the second step of the interim goodwill impairment test, we recorded a non-cash goodwill impairment loss of $252.7 million during the quarter ended September 30, 2016 to write the goodwill down to its estimated fair value of $253.4 million . Based on our estimates, the implied fair value of our reporting unit exceeded its carrying value by 15% , 3% , and 14% at the respective measurement dates of March 31, 2016, June 30, 2016 and December 31, 2016. Therefore no additional impairment loss was recorded for the year ended December 31, 2016 . Based on evaluation of qualitative factors, we determined that the goodwill impairment was primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units. As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million . Based on evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units. Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value was appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium was taken into account and in light of the recent volatility in the equity markets. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional impairment charge. Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2016 , the net carrying value of this contract was $7.9 million . The carrying value is shown as Other assets on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year. |
| Asset Retirement Obligations | Asset Retirement Obligations: We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Big Escambia Creek, Elk Basin and Fairway gas plants. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations. |
| Revenue Recognition | Revenue Recognition and Gas Imbalances: Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, our revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets. |
| Gas Imbalances | The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2016 or 2015 . |
| Concentrations of Credit Risk | Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset. At December 31, 2016 and 2015 , the cash and cash equivalents were primarily concentrated in one financial institution. We periodically assess the financial condition of this institution and believe that any possible credit risk is minimal. |
| Use of Estimates | Use of Estimates: The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates. |
| Price and Interest Rate Risk Management Activities | Price and Interest Rate Risk Management Activities: We have historically entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 5) to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2016 , our derivative transactions included the following: • Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty. • Basis swap contracts - which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. • Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity. • Three-way collar contracts - which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price drops below the price of the short put. This allows us to settle for market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. • Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years. • Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Put spread options - created when we purchase a put and sell a put simultaneously. • Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously. • Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level. We also entered into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We 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 since specific hedge accounting criteria are not met. Gains or losses on derivative contracts are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations. Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. As of December 31, 2016, we have no commodity derivative contracts in place. |
| Income Taxes | Income Taxes: The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholders’ tax attributes in the Company. However, the tax basis of our net assets exceeded the net book basis by $2.0 billion and $1.3 billion at December 31, 2016 and 2015 , respectively. Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.3 million and $0.2 million as of December 31, 2016 and 2015 , respectively, and a deferred tax asset of $2.0 million and $0.5 million as of December 31, 2016 and 2015 , respectively. Tax benefits of $1.3 million , $0.3 million and $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2016 , 2015 , and 2014 , respectively, as a component of Selling, general and administrative expenses. The Company’s provision for income taxes also relates to the federal taxes for ERAC and ERAC II and their wholly owned corporations, ERUD and ERUD II, which are subject to federal income taxes (the “C Corporations”). As part of the Eagle Rock Merger, the Company assumed deferred tax liabilities, the largest single component of which is related to federal income taxes of the C Corporations, where the book/tax differences were created by certain acquisitions completed by ERAC and ERAC II prior to the Eagle Rock Merger. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. As of December 31, 2016 and 2015, the Company recorded a deferred tax liability of $37.6 million and $39.4 million , respectively, related to these C Corporations, which is included in the other long-term liabilities line item in the Consolidated Balance Sheets. The Company also recorded a net deferred tax asset at December 31, 2016 and 2015 of $2.2 million from the Eagle Rock Merger related to the book/tax differences in property, plant and equipment and hedging transactions, which is included in the other assets line item in the Consolidated Balance Sheets. In assessing the realizability of net deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2016 , based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of the deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. |
| Prior Year Financial Statement Presentation | Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Annual Report on Form 10-K. Please read Note 4. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification. |
