Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

NOTE 2 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

In connection with the Chapter 11 Filings, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852 Reorganizations (“ASC 852”). All expenses, realized gains and losses and provisions for losses directly associated with the bankruptcy proceedings were classified as “reorganization items” in the consolidated statements of operations.

Upon emergence from bankruptcy on the Plan Effective Date, we adopted fresh-start accounting in accordance with ASC 852 (see Note 3). Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Plan Effective Date, which differed materially from the recorded values of ARP’s assets and liabilities as reflected in ARP’s historical consolidated balance sheet. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of September 1, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the predecessor period January 1 to August 31, 2016.  

As a result, our consolidated balance sheet and consolidated statement of operations subsequent to the Plan Effective Date is not comparable to ARP’s consolidated balance sheet and consolidated statements of operations prior to the Plan Effective Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after September 1, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

References to “Successor” relate to the Company on and subsequent to the Plan Effective Date. References to “Predecessor” refer to the Company prior to the Plan Effective Date. The consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

Principles of Consolidation

Our consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiaries. Transactions between us and other ATLS managed operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated.

In accordance with established practice in the oil and gas industry, our consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which we have an interest. Such interests generally approximates 10-30%. Our consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, we calculate these items specific to our own economics.

Liquidity, Capital Resources, and Ability to Continue as a Going Concern

We have historically funded our operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under our credit facilities and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted our revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on our liquidity position. In addition, challenges with our ability to raise capital through our Drilling Partnerships, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted our ability to remain in compliance with the covenants under our credit facilities.

We are not in compliance with certain of the financial covenants under our credit facilities (as described in Note 7) as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification.  We do not currently have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there is substantial doubt regarding our ability to continue as a going concern. In addition to the $30 million of indebtedness due on May 1, 2017, we classified the remaining $666.8 million of outstanding indebtedness under our credit facilities as a current liability, based on the occurrence of the event of default, the lenders under our credit facilities, as applicable, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit.  In total, we have $694.8 million of outstanding indebtedness under our credit facilities, which is net of $2 million of deferred financing costs, as current portion of long term debt, net within our consolidated balance sheet as of December 31, 2016.

On April 19, 2017, we expect to enter into an amendment to the First Lien Facility.  Pursuant to the amendment, certain of the financial ratio covenants will be revised upwards. Specifically, beginning December 31, 2017, we are required to maintain a ratio of Total Debt to EBITDA (each as defined in the First Lien Facility) of not more than 5.50 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 5.00 to 1.00 thereafter. We are also required, beginning December 31, 2017, to maintain a ratio of First Lien Debt (as defined in the First Lien Facility) to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter through December 31, 2018 and of not more than 3.50 to 1.00 thereafter.

In addition to the amendments to the financial ratio covenants, the First Lien lenders will waive certain defaults by us with respect to the fourth quarter of 2016, including compliance with the ratios of Total Debt to EBITDA and First Lien Debt to EBITDA, as well as our obligation to deliver financial statements without a “going concern” qualification. The First Lien lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to our second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the First Lien Facility.

The First Lien amendment will confirm the conforming and non-conforming tranches of the borrowing base at $410 million and $30 million, respectively, but requires us to take actions (which can include asset sales and equity offerings) to reduce the conforming tranche of the borrowing base to $330 million by August 31, 2017 and to $190 million by October 1, 2017 (subject to extension at the administrative agent’s option to October 31, 2017). Similarly, the non-conforming tranche of the borrowing base will be required to be reduced to $10 million by November 1, 2017. In addition, we will be required to use excess asset sale proceeds (after application in accordance with the existing terms of the First Lien Facility) to repay outstanding borrowings and reduce the applicable borrowing base to the required level.

Unless we are able to obtain an amendment or waiver, the lenders under our Second Lien Facility may declare a default with respect to our failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under the Second Lien Facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under the Second Lien Facility have not yet given us notice of any default.

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet and meeting our debt service obligations. We could pursue options such as refinancing, restructuring or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. In addition, we expect that we will sell a significant amount of non-core assets in the near future to comply with the requirements of our expected First Lien Facility amendment and to attempt to enhance our liquidity.

We cannot assure you that we would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities.  Additionally, there can be no assurance that the above actions would allow us to meet our debt obligations and capital requirements.

Arkoma Acquisition

On June 5, 2015, ARP acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”) for $31.5 million, net of purchase price adjustments, which was funded through the issuance of 6,500,000 of our Predecessor’s common limited partner units. We determined that the Arkoma Acquisition constituted a transaction between entities under common control and, accordingly, retroactively adjusted ARP’s prior period consolidated financial statements assuming our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations before the date of the transaction.

In April 2015, the FASB updated the accounting guidance for earnings per unit (“EPU”) of master limited partnerships (“MLP”) applying the two-class method. The updated accounting guidance specifies that for general partner transfers (or “drop downs”) to an MLP accounted for as a transaction between entities under common control, the earnings (losses) of the transferred business before the date of the transaction should be allocated entirely to the general partner’s interest, and previously reported EPU of the limited partners should not change. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs are also required.

We adopted this accounting guidance upon its effective date of January 1, 2016, which resulted in the following retrospective restatement to allocate the net income (loss) of the Arkoma operations before the date of the transaction entirely to our Predecessor’s general partner’s interest:

Predecessor Consolidated Statement of Operations	Previously Filed			Adjustment			Restated
Year Ended December 31, 2015:
Common limited partners' interest	$	(808,780	)	$	(2,486	)	$	(811,266	)
General partner's interest	$	(16,505	)	$	2,486		$	(14,019	)
Net loss attributable to common limited partners per unit – basic	$	(8.63	)	$	(0.02	)	$	(8.65	)
Net loss attributable to common limited partners per unit – diluted	$	(8.63	)	$	(0.02	)	$	(8.65	)
Year Ended December 31, 2014:
Common limited partners' interest	$	(625,133	)	$	(3,793	)	$	(628,926	)
General partner's interest	$	(1,222	)	$	3,793		$	2,571
Net loss attributable to common limited partners per unit – basic	$	(8.37	)	$	(0.05	)	$	(8.42	)
Net loss attributable to common limited partners per unit – diluted	$	(8.37	)	$	(0.05	)	$	(8.42	)
Predecessor Consolidated Balance Sheet
December 31, 2015:
Common limited partners’ interest	$	(260,276	)	$	(2,486	)	$	(262,762	)
General partners’ interest	$	(33,642	)	$	2,486		$	(31,156	)

Prior to the Arkoma Acquisition, our Predecessor’s common limited partners did not participate in the net income (loss) of the Arkoma operations. Subsequent to the Arkoma Acquisition, our Predecessor’s common limited partners participated in the net income (loss) of the Arkoma operations, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests.

Use of Estimates

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, fair value of derivative instruments, fair value of certain gas and oil properties and asset retirement obligations, and fair value of assets and liabilities in connection with the application of fresh-start accounting and accounting for business combinations. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.

Cash Equivalents

We consider all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

Receivables

Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with our operations. We perform ongoing credit evaluations of our customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness. We extend credit on sales on an unsecured basis to many of our customers. At December 31, 2016 and 2015, we had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets.

Inventory

We had $7.4 million and $8.0 million of inventory at December 31, 2016 and 2015, respectively, which was included within prepaid expenses and other current assets on our consolidated balance sheets. We value inventories at the lower of cost or market. Our inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. During the year ended December 31, 2015, we recognized a $1.2 million loss on asset sales and disposal on our consolidated statement of operations related to the obsolescence of our pipe, pump units and other inventory in the New Albany Shale and Black Warrior basin.

Subscriptions Receivable

We receive contributions from limited partner investors of our Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker-dealer and our wholly owned subsidiary, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. We recognize the contributions associated with the executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.

Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. We also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by us for our interests, properties purchased and working interests with other outside operators.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to our consolidated statement of operations. Upon the sale of an individual well, we credit the proceeds to accumulated depreciation and depletion within our consolidated balance sheet. Upon our sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in our consolidated statement of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Support equipment and other are carried at cost and consist primarily of pipelines, processing and compression facilities, and gathering systems and related support equipment.  We compute depreciation of support equipment and other using the straight-line balance method over the estimated useful life of each asset category as follows: Pipelines, processing and compression facilities: 15-20 years; Buildings and land improvements: 3-40 years; Other support equipment: 3-10 years.

See Note 5 for additional disclosures regarding property, plant and equipment.

Impairment of Property, Plant and Equipment

We review our property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area.  As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.

The review of our oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. We estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published future prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected undiscounted future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, our reserve estimates for our investments in the Drilling Partnerships are based on our own assumptions rather than our proportionate share of the Drilling Partnerships’ reserves. These assumptions include our actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.

Our lower operating and administrative costs result from recognizing our proportionate share of limited partners’ Drilling Partnership external operating expenses. These assumptions could result in our calculation of depletion and impairment being different than our proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. We cannot predict what reserve revisions may be required in future periods.

Our method of calculating our reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships. Our reserve quantities include reserves in excess of our proportionate share of reserves in Drilling Partnerships, which we may be unable to recover due to the Drilling Partnerships’ legal structure. We may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to us becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from a Drilling Partnership by us is governed under the Drilling Partnership’s limited partnership agreement. In general, we will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon our determination of fair market value.

See Note 5 for additional disclosures regarding impairment of property, plant and equipment.

Capitalized Interest

We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use.  The weighted average interest rate used to capitalize interest on borrowed funds during the Successor period September 1, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through August 31, 2016 and the years ended December 2015 and 2014 was 7.6%, 6.5%, 6.5% and 5.6%, respectively. The aggregate amount of interest capitalized during the Successor period September 1, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through August 31, 2016 and the years ended December 31, 2015 and 2014 was $0.1 million, $6.5 million, $15.8 million and $13.0 million, respectively.

Intangible Assets

We recorded our intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. We amortize contracts acquired on a declining balance method over their respective estimated useful lives. We evaluate intangible assets for impairment annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

We had a $0.5 million net carrying amount of intangible assets recorded within goodwill and intangible assets, net on our consolidated balance sheet at December 31, 2015.  Amortization expense on our intangible assets during the Predecessor period from January 1, 2016 through August 31, 2016 and the years ended December 31, 2015 and 2014 was $0.5 million, $0.2 million, and $0.3 million, respectively.  We do not have any intangible assets recorded on our consolidated balance sheet at December 31, 2016 and did not record any amortization expense during the Successor period from September 1, 2016 through December 31, 2016.

Goodwill

We evaluate goodwill for impairment annually or whenever impairment indicators arise by comparing our reporting units’ estimated fair values to their carrying values. Because quoted market prices for the reporting units are not available, we must apply judgment in determining the estimated fair value of our reporting units. We use all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in our assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to our market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the fair value calculations have been determined, we also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in our industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.

As a result of our Predecessor’s goodwill impairment evaluation at December 31, 2014, our Predecessor recognized an $18.1 million non-cash impairment charge within asset impairments in the consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in our Predecessor’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. Our Predecessor’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. The $13.6 million remaining goodwill at December 31, 2014 and 2015 was attributable to our Predecessor’s well construction and completion and other partnership management reporting units that was recorded in connection with prior consummated acquisitions.  No changes in the carrying amount of goodwill was recorded during the Predecessor period from January 1, 2016 through August 31, 2016 and the year ended December 31, 2015. As a result of the adoption of fresh start accounting, our Predecessor’s goodwill was eliminated (see Note 3).

Derivative Instruments

We enter into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in our consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, our Predecessor discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives were recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the consolidated statement of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ capital (deficit) on our Predecessor’s consolidated balance sheet and reclassified to the consolidated statement of operations at the time the originally hedged physical transactions affected earnings.  See Note 8 for additional disclosures regarding derivative instruments.

Other Assets

In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes to our consolidated balance sheet:

Predecessor Consolidated Balance Sheet	Previously Filed		Adjustment			Restated
December 31, 2015:
Other assets, net	$	60,044	$	(31,055	)	$	28,989
Long-term debt, net	$	1,534,482	$	(31,055	)	$	1,503,427

Deferred financing costs related to revolving credit facility (line-of-credit) arrangements are recorded at cost, amortized over the term of the arrangement, and are presented net of accumulated amortization within other assets, net on our consolidated balance sheets.  If our revolving credit facility’s borrowing base is reduced, we will accelerate amortization of the deferred financing costs to correspond to the lower borrowing base. We had revolving credit facility deferred financing costs of $3.8 million and $19.8 million, which were net of $0.5 million and $29.1 million of accumulated amortization, recorded within other assets, net on our consolidated balance sheets at December 31, 2016 and 2015, respectively. For the Successor period September 1, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through August 31, 2016 and the years ended December 2015 and 2014, amortization expense of revolving credit facility deferred financing costs was $0.5 million, $10.6 million, $13.6 million and $7.3 million, respectively, which was recorded within interest expense on our consolidated statements of operations.

At December 31, 2016 and 2015, we had notes receivable with certain investors of our Drilling Partnerships of $0.6 million and $3.7 million, respectively, recorded within other assets, net on our consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain conditions, including an extension fee of 1.0% of the outstanding principal balance. For the Predecessor period from January 1, 2016 through August 31, 2016, we recognized $3.1 million provision for losses to adjust the notes receivables to their net realizable value, which was recorded within other income (loss) on our consolidated statement of operations. For the Successor period September 1, 2016 through December 31, 2016 and the Predecessor years ended December 2015 and 2014, we did not record any provision for losses related to notes receivables.

Asset Retirement Obligations

We recognize an estimated liability for the plugging and abandonment of our gas and oil wells and related facilities. We recognize a liability for our future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. See Note 6 for additional disclosures regarding asset retirement obligations.

Share-Based Compensation

We recognize all share-based payments to employees, including grants of employee options, in the consolidated financial statements based on their fair values.  See Note 15 for additional disclosures regarding share-based compensation.

Predecessor’s Net Income (Loss) Per Common Unit

Basic net income (loss) attributable to our Predecessor’s common limited partners per unit was computed by dividing net income (loss) attributable to our Predecessor’s common limited partners, which was determined after the deduction of our Predecessor’s general partner’s and preferred unitholders’ interests, by the weighted average number of our Predecessor’s common limited partner units outstanding during the period. Net income (loss) attributable to our Predecessor’s common limited partners was determined by deducting net income (loss) attributable to participating securities, if applicable, income (loss) attributable to our Predecessor’s preferred limited partners and net income (loss) attributable to our Predecessor’s general partner’s Class A units. Our Predecessor’s general partner’s interest in net income (loss) was calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 14), with a priority allocation of net income to our Predecessor’s general partner’s incentive distributions, if any, in accordance with our Predecessor’s partnership agreement, and the remaining net income (loss) allocated with respect to our Predecessor’s general partner’s and limited partners’ ownership interests.

Our Predecessor presented net income (loss) per unit under the two-class method for MLPs, which considers whether the incentive distributions of a MLP represent a participating security. The two-class method considers whether our Predecessor’s partnership agreement contained any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under our Predecessor’s partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, we believe our Predecessor’s partnership agreement contractually limited cash distributions to available cash; therefore, undistributed earnings were not allocated to the incentive distribution rights.

Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plan, contain non-forfeitable rights to distribution equivalents. The participation rights would result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.

The following is a reconciliation of net income allocated to our Predecessor’s common limited partners for purposes of calculating net income attributable to our Predecessor’s common limited partners per unit (in thousands, except unit data):

	Predecessor
	Period from January 1 through August 31,  2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Net loss	$	(177,430	)	$	(808,816	)	$	(607,088	)
Preferred limited partner dividends		(4,013	)		(16,469	)		(19,267	)
Net loss attributable to common limited partners and the general partner		(181,443	)		(825,285	)		(626,355	)
Less: General partner’s interest		(3,629	)		(14,019	)		2,571
Net loss attributable to common limited partners		(177,814	)		(811,266	)		(628,926	)
Less: Net loss attributable to participating securities – phantom units		—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit – Basic		(177,814	)		(811,266	)		(628,926	)
Plus: Convertible preferred limited partner dividends(1)		—			—			—
Net loss utilized in the calculation of net loss attributable to common limited partners per unit – Diluted	$	(177,814	)	$	(811,266	)	$	(628,926	)

(1) For all predecessor periods presented, distributions on our Predecessor’s Class B and Class C convertible preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.

Diluted net income (loss) attributable to our Predecessor’s common limited partners per unit was calculated by dividing net income (loss) attributable to our Predecessor’s common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of unit option awards, convertible preferred units and warrants, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.

The following table sets forth the reconciliation of our Predecessor’s weighted average number of common limited partner units used to compute basic net income attributable to our Predecessor’s common limited partners per unit with those used to compute diluted net income attributable to our Predecessor’s common limited partners per unit (in thousands):

	Predecessor
	Period from January 1,  2016 through August 31,  2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Weighted average number of common limited partner units—basic		102,912		93,745		74,716
Add effect of dilutive incentive awards(1)		—		—		—
Add effect of dilutive convertible preferred limited partner units(2)		—		—		—
Weighted average number of common limited partner units—diluted		102,912		93,745		74,716

(1) For the period January 1, 2016 through August 31, 2016 and years ended December 31, 2015 and 2014, 274,000, 453,000 and 783,000 phantom units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive.

(2) For the period January 1, 2016 through August 31, 2016 and the years ended December 31, 2015 and 2014, potential common limited partner units issuable upon conversion of our Predecessor’s Class B preferred units and potential common limited partner units issuable upon (a) conversion of our Predecessor’s Class C preferred units and (b) exercise of the common unit warrants issued with our Predecessor’s Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As our Predecessor’s Class D and Class E preferred units were convertible only upon a change of control event, they were not considered dilutive securities for earnings per unit purposes.

Concentration of Credit Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. We place our temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. We had $41.3 million and $10.3 million, respectively, in deposits at various banks at December 31, 2016 and 2015, respectively, of which $38.2 million and $8.4 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.

Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.

We sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the Successor period September 1, 2016 through December 31, 2016, Tenaska Marketing Ventures and Chevron within our gas and oil production segment individually accounted for approximately 22% and 15%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the Predecessor period January 1, 2016 through August 31, 2016, Tenaska Marketing Ventures, Chevron and Interconn Resources LLC within our gas and oil production segment individually accounted for approximately 25%, 16% and 13%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the Predecessor year ended December 31, 2015, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC within our gas and oil production segment individually accounted for approximately 21%, 15%, 11% and 11%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the Predecessor year ended December 31, 2014, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC within our gas and oil production segment individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.

We are subject to the risk of loss on our derivative instruments that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews of significant counterparties to physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk.  Our liabilities related to derivatives as of December 31, 2016 represent financial instruments from nine counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our revolving credit facility. Subject to the terms of our revolving credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the revolving credit facility.

Revenue Recognition

Natural gas and oil production. We generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, our sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of our natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are 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. Revenues from the production of natural gas, crude oil and NGLs, in which we have an interest with other producers, are recognized on the basis of our percentage ownership of the working interest and/or overriding royalty.

Drilling Partnerships. Certain energy activities are conducted by us through, and a portion of our revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by us is deployed to drill and complete wells included within the partnership. As we deploy Drilling Partnership investor capital, we recognize certain management fees we are entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if we have Drilling Partnership investor capital that has not yet been deployed, we will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our consolidated balance sheet. After the Drilling Partnership well is completed and turned in line (i.e. wells that have been drilled, completed, and connected to a gathering system), we are entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees we are entitled to receive for services provided, we are also entitled to our pro-rata share of Drilling Partnership gas and oil production revenue, which is generally between 10-30%. We recognize our Drilling Partnership management fees in the following manner:

• Well construction and completion. For each well that is drilled by a Drilling Partnership, we receive a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with each Drilling Partnership’s partnership agreement, and recognized as the services are performed, typically between 60 and 270 days.

• Administration and oversight. For each well drilled by a Drilling Partnership, we receive a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with each Drilling Partnership’s partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays us a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed.

• Well services. Each Drilling Partnership pays us a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed.

While the historical structure has varied, we have generally agreed to subordinate a portion of our share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of cumulative unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically from 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. We periodically compare the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, we recognize subordination as an estimated reduction of our pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which we have recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, we will recognize an estimated increase in our portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.

Gathering and processing revenue. Gathering and processing revenue includes gathering fees we charge to the Drilling Partnership wells for our processing plants in the New Albany and the Chattanooga Shales. Generally, we charge a gathering fee to the Drilling Partnership wells equivalent to the fees we remit. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby we remit a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, we charge the Drilling Partnership wells a 13% gathering fee. As a result, some of our gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.

Our gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices and/or contract market prices. We had unbilled revenues at December 31, 2016 and 2015 of $29.1 million and $37.7 million, respectively, which were included in accounts receivable within our consolidated balance sheets.

Comprehensive Income (Loss)

Accumulated other comprehensive income was eliminated pursuant to the application of fresh-start accounting (see Note 3). Prior to that, our Predecessor’s comprehensive income (loss) included net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, had not been recognized in the calculation of net income (loss). These changes, other than net income (loss), were referred to as “other comprehensive income (loss)” on our Predecessor’s consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). Our Predecessor did not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In February 2016, the FASB updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented.  We are currently in the process of determining the impact that the updated accounting guidance will have on our consolidated financial statements.

In November 2015, the FASB updated the accounting guidance related to the balance sheet presentation of deferred taxes. The updated accounting guidance requires that all deferred tax liabilities and assets be classified as noncurrent in a classified balance sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in this update. This guidance is effective for us beginning January 1, 2017, with early adoption permitted. We early adopted this guidance in the fourth quarter of 2016 on a prospective basis; therefore, prior periods were not retrospectively adjusted.

In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line of credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016, and it did not have a material impact on our consolidated financial statements.

In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our consolidated financial statements.

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our consolidated financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.