Atlas Growth Partners (AGP) 10-K 8 May 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	May 04, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	Atlas Growth Partners, L.P.
Entity Central Index Key	1,572,702
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Units Outstanding		23,300,410
Trading Symbol	AGP

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 8,236	$ 8,586
Accounts receivable	572	846
Total current assets	8,808	9,432
Property, plant and equipment, net	65,293	68,899
Other assets, net	118	169
Total assets	74,219	78,500
Current liabilities:
Accounts payable	332	890
Advances from affiliates	606	1,355
Current portion of derivative liability	497	284
Accrued liabilities	407	241
Total current liabilities	1,842	2,770
Long-term derivative liability		280
Asset retirement obligations and other	465	641
Commitments and contingencies (Note 7)
Partners’ Capital:
General partner’s interest	(2,611)	(2,553)
Common limited partners’ interests	71,387	74,226
Common limited partners’ warrants	3,136	3,136
Total partners’ capital	71,912	74,809
Total liabilities and partners’ capital	$ 74,219	$ 78,500

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Gas and oil production	$ 7,841	$ 11,851	$ 11,846
Gain (loss) on mark-to-market derivatives	310	(780)	862
Total revenues	8,151	11,071	12,708
Costs and expenses:
Gas and oil production	2,528	2,660	2,229
General and administrative	813	571	685
General and administrative – affiliate	4,131	9,347	12,054
Depreciation, depletion and amortization	3,576	14,868	8,951
Asset impairment		41,879	7,346
Total costs and expenses	11,048	69,325	31,265
Operating loss	(2,897)	(58,254)	(18,557)
Other loss		(5,383)
Net loss	(2,897)	(63,637)	(18,557)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest	(2,839)	(62,363)	(18,187)
General partner’s interest	$ (58)	$ (1,274)	$ (370)
Net loss attributable to common limited partners per unit:
Basic and Diluted	$ (0.12)	$ (2.68)	$ (0.98)
Weighted average common limited partner units outstanding:
Basic and Diluted	23,300	23,300	18,585

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	General Partner's InterestGeneral Class A	Common Limited Partners' Interests	Common Limited Partners' Warrants
Balance at Dec. 31, 2014	$ 67,510	$ (446)	$ 66,676	$ 1,280
Balance (units) at Dec. 31, 2014		100	10,676,910	1,067,691
Issuance of units, net of offering costs	111,189		$ 109,333	$ 1,856
Issuance of units, net of offering costs (units)			12,623,500	1,262,350
Distributions paid	(10,755)	$ (215)	$ (10,540)
Net loss	(18,557)	(370)	(18,187)
Balance at Dec. 31, 2015	149,387	$ (1,031)	$ 147,282	$ 3,136
Balance (units) at Dec. 31, 2015		100	23,300,410	2,330,041
Issuance of units, net of offering costs	1,541		$ 1,541
Distributions paid	(12,482)	$ (248)	(12,234)
Net loss	(63,637)	(1,274)	(62,363)
Balance at Dec. 31, 2016	74,809	$ (2,553)	$ 74,226	$ 3,136
Balance (units) at Dec. 31, 2016		100	23,300,410	2,330,041
Net loss	(2,897)	$ (58)	$ (2,839)
Balance at Dec. 31, 2017	$ 71,912	$ (2,611)	$ 71,387	$ 3,136
Balance (units) at Dec. 31, 2017		100	23,300,410	2,330,041

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (2,897)	$ (63,637)	$ (18,557)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	3,576	14,868	8,951
Asset impairment		41,879	7,346
(Gains) losses on derivatives	217	674	(412)
Other loss		5,297
Amortization of deferred financing costs	51	66	31
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	(10)	990	(1,159)
Advances to/from affiliates	(749)	9,363	(24,508)
Accounts payable and accrued liabilities	(538)	(1,395)	1,418
Net cash provided by (used in) operating activities	(350)	8,105	(26,890)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(6,602)	(29,222)
Net cash paid for acquisitions			(42,478)
Net cash used in investing activities		(6,602)	(71,700)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of common limited partner units and warrants		(3,756)	99,440
Distributions paid to unitholders		(12,482)	(10,755)
Deferred financing costs and other			(179)
Net cash provided by (used in) financing activities		(16,238)	88,506
Net change in cash and cash equivalents	(350)	(14,735)	(10,084)
Cash and cash equivalents, beginning of year	8,586	23,321	33,405
Cash and cash equivalents, end of period	$ 8,236	$ 8,586	$ 23,321

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	NOTE 1 – BASIS OF PRESENTATION We are a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in south Texas. Our general partner, Atlas Growth Partners GP, LLC owns 100% of our general partner units (which are entitled to receive 2% of the cash distributed by us without any obligation to make further capital contributions) and all of the incentive distribution rights through which it manages and effectively controls us. Atlas Energy Group, LLC (“ATLS”), a publicly traded Delaware limited liability company (OTCQB: ATLS), manages and controls us through its 2.1% limited partner interest in us and 80% member interest in our general partner. Current and former members of ATLS management own the remaining 20% member interest in our general partner. In addition to its general and limited partner interest in us, ATLS also holds a Series A Preferred Share (which entitles it to receive 2% of distributions, subject to potential dilution in the event of future equity interests and to appoint four of seven directors) in Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States, and a general and limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. Titan is the successor to the business and operations of Atlas Resource Partners, L.P. At December 31, 2017, we had 23,300,410 common limited partner units issued and outstanding.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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. 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, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. 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 consists solely of the trade accounts receivable associated with our operations. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness as determined by our review of customers’ credit information. We extend credit on sales on an unsecured basis to many of our customers. At December 31, 2017 and 2016, we had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets. 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 which 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 which 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 six 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 our calculation of depletion. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated 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 statements 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 type, which is 15-20 years. See Note 3 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 futures 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 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. 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. See Note 3 for additional disclosures regarding impairment of property, plant and equipment. 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 are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. See Note 4 for additional disclosures regarding derivative instruments. 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. The estimated liability for asset retirement obligations was based on our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we determined that there were no other material retirement obligations associated with tangible long-lived assets. As of both December 31, 2017 and 2016, our asset retirement obligation was $0.2 million. For the years ended December 31, 2017, 2016 and 2015, we recorded $16,000, $15,000 and $14,000, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our consolidated statements of operations. Other Non-current Liabilities We have two lease agreements in our Eagle Ford operating area that required us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the lease. We determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law to be $0.5 million which was recorded as a non-current liability on our consolidated balance sheet as of December 31, 2016. As of December 31, 2017, we presented $0.1 million as current accrued liabilities, to reflect the estimated amount owed within one year, and $0.3 million as the estimated remaining non-current liability on our consolidated balance sheet. Income Taxes We are not subject to U.S. federal and most state income taxes. Our partners are liable for income tax in regard to their distributive share of our taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the consolidated financial statements. We evaluate tax positions taken or expected to be taken in the course of preparing our tax returns and disallow the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe it has any tax positions taken within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. We have not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2017 and 2016. We file Partnership Returns of Income in the U.S. and various state jurisdictions. We are not subject to income tax examinations by major tax authorities for years prior to 2013, our year of formation. We are not currently being examined by any jurisdiction and are not aware of any potential examinations. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since our operations are not subject to federal income tax, the Tax Act is not expected to have a material impact on us. Segment Reporting We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment, because the facilities have similar long-term economic characteristics, products and types of customers. Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon our general partner units and incentive distributions to be distributed for the quarter (see Note 9), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with our Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests. We present net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security. The two-class method considers whether our Partnership Agreement contains 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 Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, our management believes our Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands): Years Ended December 31, 2017 2016 2015 Net loss $ (2,897 ) $ (63,637 ) (18,557 ) Less: General partner’s interest (58 ) (1,274 ) (370 ) Net loss attributable to common limited partners $ (2,839 ) $ (62,363 ) (18,187 ) Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method. The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): Years Ended December 31, 2017 2016 2015 Weighted average number of common units – basic 23,300 23,300 18,585 Add effect of dilutive awards(1) — — — Weighted average number of common units – diluted 23,300 23,300 18,585 (1) For both the years ended December 31, 2017 and 2016 and the year ended December 31, 2015, 2,330,000 and 1,859,000, respectively, common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. 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. At December 31, 2017 and 2016, we had $8.3 million and $10.3 million, respectively, in deposits at various banks, of which $8.0 million and $9.7 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 year ended December 31, 2017, Shell Trading Co individually accounted for approximately 91% of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2016, Shell Trading Co and Enterprise Crude Oil, LLC individually accounted for approximately 64% and 29%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, Enterprise Crude Oil, LLC, Shell Trading Co. and Midcoast Energy Partners individually accounted for approximately 59%, 28% and 12%, 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 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, 2017 represent financial instruments from one counterparty, which is a financial institution that has an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our credit facility. Subject to the terms of our credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the credit facility. Revenue Recognition 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 its 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 responsibilities 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. We 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 from our records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. We had unbilled revenues of $0.6 million and $0.9 million at December 31, 2017 and 2016, respectively, which were included in accounts receivable within our consolidated balance sheets. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“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 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. We have completed our detailed contract reviews and documentation.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	NOTE 3 – PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at the dates indicated (in thousands): December 31, 2017 December 31, 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment and other 3,188 3,188 151,120 151,133 Less – accumulated depreciation, depletion and amortization (85,827 ) (82,234 ) $ 65,293 $ 68,899 As of December 31, 2017, we transferred $63.3 million of our unproved properties to proved natural gas and oil properties as management finalized capital plans for drilling and developing the wells within our Eagle Ford operating area. For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. There were no impairments of unproved gas and oil properties for the year ended December 31, 2015. For the year ended December 31, 2015, we recognized $7.3 million of asset impairment related to proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. During the year ended December 31, 2016, we recognized $0.4 million of non-cash investing activities capital expenditures, which were included within the changes in accounts payable and accrued liabilities on our consolidated statements of cash flows. During the year ended December 31, 2015, we assigned a portion of our non-operating Eagle Ford assets to ARP in exchange for ARP funding our remaining $36.3 million of deferred Eagle Ford Acquisition purchase price, which represented a non-cash transaction within our consolidated statement of cash flows.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 4 – DERIVATIVE INSTRUMENTS We use swaps in connection with our commodity price risk management activities. We do not apply hedge accounting to any of our derivative instruments. As a result, gains and losses associated with derivative instruments are recognized as gains on mark-to-market derivatives on our consolidated statements of operations. We enter into commodity future option contracts to achieve more predictable cash flows by hedging our exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. The following table summarizes the commodity derivative activity for the period indicated (in thousands): Years Ended December 31, 2017 2016 Gains (losses) recognized on cash settlement $ 527 $ (106 ) Changes in fair value on open derivative contracts (217 ) (674 ) Gain (loss) on mark-to-market derivatives $ 310 $ (780 ) The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our consolidated balance sheets as of the date indicated (in thousands): Offsetting Derivatives as of December 31, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Current portion of derivative liabilities $ (497 ) $ — $ (497 ) Long-term portion of derivative liabilities — — — Total derivative liabilities $ (497 ) $ — $ (497 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 97 $ (97 ) $ — Long-term portion of derivative assets — — — Total derivative assets $ 97 $ (97 ) $ — Current portion of derivative liabilities $ (381 ) $ 97 $ (284 ) Long-term portion of derivative liabilities (280 ) — (280 ) Total derivative liabilities $ (661 ) $ 97 $ (564 ) As of December 31, 2017, we had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes (1) Average Fixed Price Fair Value Liability (in thousands) (2) 2018 74,500 $ 52.510 (497 ) Net liabilities $ (497 ) (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable. On May 1, 2015, we entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2017, the lenders under the credit facility have no commitment to lend to us under the credit facility and we have a zero dollar borrowing base, but we and our subsidiaries have the ability to enter into derivative contracts to manage our exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on our oil and gas properties and first priority security interest in substantially all of our assets. The credit facility may be amended in the future if we and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit our and our subsidiaries’ ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. We were in compliance with these covenants as of December 31, 2017. In addition, our credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	NOTE 5 – FAIR VALUE OF FINANCIAL INSTRUMENTS Management has established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. Assets and Liabilities Measured at Fair Value on a Recurring Basis We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments (see Note 4). We manage and report derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative values were calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Information for financial instruments measured at fair value was as follows (in thousands): As of December 31, 2017 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ — $ — $ — Total derivative assets, gross — — — — Liabilities, gross Commodity swaps — (497 ) — (497 ) Total derivative liabilities, gross — (497 ) — (497 ) Total derivatives, fair value, net $ — $ (497 ) $ — $ (497 ) As of December 31, 2016 Assets, gross Commodity swaps $ — $ 97 $ — $ 97 Total derivative assets, gross — 97 — 97 Liabilities, gross Commodity swaps — (661 ) — (661 ) Total derivative liabilities, gross — (661 ) — (661 ) Total derivatives, fair value, net $ — $ (564 ) $ — $ (564 ) Other Financial Instruments Our other current assets and liabilities on our consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Warrants . The fair value of the warrants associated with the issuance of common limited partner units in 2015 (see Note 8) was measured using a Black-Scholes pricing model which was based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.5%, an expected term of 1.5 years, expected dividend yield of 7.0% and estimated volatility rate of 50%. The volatility rate used was consistent with that of ARP at the time the warrants were issued. The estimated fair value per warrant was $1.47, which included a $0.37 liquidity adjustment. Asset Impairments. We estimate the fair value of our gas and oil properties in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances based on a discounted cash flow model, which considers the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. See Note 3 for disclosure of impairments of our gas and oil properties. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	NOTE 6 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ATLS . We do not directly employ any persons to manage or operate our business. These functions are provided by employees of ATLS and/or its affiliates, including Titan. Our general partner receives an annual management fee in connection with its management of us equivalent to 1% of capital contributions per annum. During each of the years ended December 31, 2017 and 2016, we paid a management fee of $2.3 million. Other indirect costs, such as rent for offices, are allocated by Titan at the direction of ATLS based on the number of its employees who devoted their time to activities on our behalf. We reimburse ATLS at cost for direct costs incurred on our behalf. We reimburse all necessary and reasonable costs allocated to us by ATLS. All of the costs paid or payable to ATLS and our general partner discussed above were included in general and administrative expenses – affiliate in the consolidated statements of operations. As of each of December 31, 2017 and December 31, 2016, we had payables to ATLS of $0.6 million, related to the management fee, direct costs and allocated indirect costs, which was recorded in advances from affiliates in the consolidated balance sheets. Relationship with Titan . At the direction of ATLS, we reimburse Titan for direct costs, such as salaries and wages, charged to us based on ATLS employees who incurred time to activities on our behalf and indirect costs, such as rent and other general and administrative costs, allocated to us based on the number of ATLS employees who devoted their time to activities on our behalf. As of December 31, 2017 and 2016, we had payables to Titan of $0.1 million and $0.8 million, respectively, related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the consolidated balance sheets.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 7 – COMMITMENTS AND CONTINGENCIES General Commitments We lease office space and equipment under leases with varying expiration dates. Rental expense was $0.2 million, $0.3 million and $0.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. We do not have any future minimum rental commitments as of December 31, 2017. As of December 31, 2017, certain of our executives are parties to employment agreements with ATLS or Titan that provide compensation and certain other benefits. The agreements provide for severance payments under certain circumstances. As of December 31, 2017, we did not have any commitments related to our drilling and completion and capital expenditures. Legal Proceedings We and our subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of business. Our management and our subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. Environmental Matters We and our subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We and our subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. We and our subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability as of December 31, 2017 and 2016.

Issuances of Units

Issuances of Units	12 Months Ended
	Dec. 31, 2017
Proceeds From Issuance Or Sale Of Equity [Abstract]
Issuances Of Units Text Block	NOTE 8 – ISSUANCES OF UNITS On November 2, 2016, our management decided to temporarily suspend our current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. As a result of management’s decision to temporarily suspend our current primary offering efforts (see Note 2), we reclassified $5.3 million of offering costs to other loss on our consolidated statement of operations for the year ended December 31, 2016. These offering costs were previously capitalized within our consolidated statement of changes in partners’ capital as an offset to any proceeds raised in our current primary offering and included $1.5 million that were previously capitalized in our consolidated statement of changes in partners’ capital as of December 31, 2015. Private Placement Offering . Under the terms of our initial offering, we offered in a private placement $500.0 million of our common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that we had not sold $500.0 million of common units at any extension date. We exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which we give the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of our assets. Through the completion of our private placement offering on June 30, 2015, we issued $233.0 million, or 23,300,410 of our common limited partner units, in exchange for proceeds to us, net of dealer manager fees and commissions and expenses, of $203.4 million. ATLS purchased 500,010 common units for $5.0 million during the private placement offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase our common units at an exercise price of $10.00 per unit. During the year ended December 31, 2015, we sold an aggregate of 12,623,500 of our common units at a gross offering price of $10.00 per unit, resulting in proceeds of $112.7 million to us, net of dealer manager fees and commissions and expenses of $12.7 million, of which ATLS had purchased $2.7 million, or 300,000 common units. In connection with the issuance of common limited partner units during the year ended December 31, 2015, unitholders received 1,262,350 warrants to purchase our common units at an exercise price of $10.00 per unit.

Cash Distributions

Cash Distributions	12 Months Ended
	Dec. 31, 2017
Distributions Made To Members Or Limited Partners [Abstract]
Cash Distributions	NOTE 9 – CASH DISTRIBUTIONS We have a cash distribution policy under which we distribute to holders of our common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent we have sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from us beginning with the quarter following the quarter in which we first admit them as limited partners. On November 2, 2016, our Board of Directors determined to suspend our quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain our cash flow and reinvest in our business and assets. During the year ended December 31, 2016, we paid distributions of $12.2 million to common limited partners ($0.1750 per unit for each of the first and second quarters) and $0.3 million to the general partner units ($0.1750 per unit for each of the first and second quarters). During the year ended December 31, 2015, we paid distributions of $10.5 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner units ($0.1750 per unit per quarter).

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Information (Unaudited)	NOTE 10—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Gas Reserve Information . The preparation of the our natural gas, oil and NGL reserve estimates was completed in accordance with the prescribed internal control procedures by our reserve engineers. Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to us. The independent reserve engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by the Executive Vice President of Operations. The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last year. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2017, 2016 and 2015, including adjustments related to regional price differentials and energy content. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of our oil, gas and NGL reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil, gas and NGL prices and in production and development costs and other factors, for their effects have not been proved. Reserve quantity information and a reconciliation of changes in proved reserve quantities were as follows: Gas (MMcf) Oil (MBbls) NGLs (MBbls) Total (MMcfe) Balance, January 1, 2015 8,493 14,931 1,622 107,811 Extensions, discoveries and other additions (1) 364 968 75 6,622 Sales of reserves in-place (3 ) (3,300 ) (7,579 ) (660 ) (52,734 ) Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) (2,246 ) (297 ) (381 ) (6,314 ) Production (203 ) (244 ) (30 ) (1,847 ) Balance, December 31, 2015 3,108 7,779 626 53,539 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) (1,521 ) (4,099 ) (332 ) (28,107 ) Production (154 ) (293 ) (27 ) (2,074 ) Balance, December 31, 2016 1,432 3,387 267 23,356 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) 548 1,231 169 8,949 Production (114 ) (143 ) (20 ) (1,092 ) Balance, December 31, 2017 1,866 4,475 416 31,213 Proved developed reserves at: January 1, 2015 1,255 612 205 6,157 December 31, 2015 802 1,645 154 11,596 December 31, 2016 652 925 100 6,802 December 31, 2017 613 788 121 6,069 Proved undeveloped reserves at: January 1, 2015 7,238 14,319 1,417 101,654 December 31, 2015 2,306 6,134 472 41,942 December 31, 2016 780 2,462 167 16,554 December 31, 2017 1,253 3,687 295 25,144 (1) For the year ended December 31, 2015, the increase represents PUD conversions from probable reserves related to development activity in the Eagle Ford Shale. ( 2 ) See “Revisions of Previous Estimates (3 ) Decrease due to the assignment of certain Eagle Ford assets to ARP in 2015. Revisions of Previous Estimates The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above: December 31, 2017 2016 2015 Unadjusted Prices Natural gas (per MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (per Bbl) $ 51.34 $ 42.75 $ 50.28 Natural gas liquids (per Bbl) $ 20.33 $ 19.57 $ 11.02 For the year ended December 31, 2017, we had positive revisions of 8,585 MMcfe due to modifications in our Eagle Ford development plan, focusing on longer lateral lengths, and 1,208 MMcfe due to increases in pricing, partially offset by negative revisions of 844 MMcfe due to production underperforming previous year’s forecast. For the year ended December 31, 2016, we had negative revisions of 23,794 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, 3,582 MMcfe due to production underperforming previous year’s forecast and 731 MMcfe due to decreases in pricing. For the year ended December 31, 2015, we had negative revisions of 4,543 MMcfe due to decreases in pricing and 3,268 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by 1,497 MMcfe due to our production outperforming the comparable period’s forecast. Capitalized Costs Related to Oil and Gas Producing Activities . The components of our capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment 29 29 147,961 147,974 Accumulated depreciation, depletion and amortization (85,328 ) (81,901 ) Net capitalized costs $ 62,633 $ 66,073 Results of Operations from Oil and Gas Producing Activities. The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Gas and oil production revenues $ 7,841 $ 11,851 $ 11,846 Production costs (2,528 ) (2,660 ) (2,229 ) Depletion (3,410 ) (14,694 ) (8,777 ) Asset impairment (1) — (41,879 ) (7,346 ) $ 1,903 $ (47,382 ) $ (6,506 ) (1) For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. Costs Incurred in Oil and Gas Producing Activities . The costs incurred by our oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2017 2016 2015 Property acquisition costs: Proved properties $ — $ 143 $ 43,520 Unproved properties — — — Exploration costs (1) — — — Development costs — 5,946 28,822 Total costs incurred in oil & gas producing activities $ — $ 6,089 $ 72,342 (1) There were no exploratory wells drilled during the periods presented. Standardized Measure of Discounted Future Cash Flows . The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the periods presented, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2017 2016 2015 Future cash inflows $ 243,644 $ 145,857 $ 396,141 Future production costs (73,792 ) (53,738 ) (117,785 ) Future development costs (68,321 ) (51,942 ) (133,474 ) Future net cash flows 101,531 40,177 144,882 Less 10% annual discount for estimated timing of cash flows (61,082 ) (22,796 ) (72,420 ) Standardized measure of discounted future net cash flows $ 40,449 $ 17,381 $ 72,462 Change in Standardized Discounted Cash Flows . The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since we allocate taxable income to our unitholders, no recognition has been given to income taxes: Years Ended December 31, 2017 2016 2015 Balance, beginning of year $ 17,381 $ 72,462 $ 290,416 Increase (decrease) in discounted future net cash flows (1) Sales of oil and gas produced, net of related costs (5,403 ) (8,758 ) (8,590 ) Net changes in estimated future prices and production costs 22,401 (19,173 ) (176,091 ) Revisions of previous quantity estimates 15,568 (32,119 ) 47,612 Development costs incurred — — 30,144 Changes in future development costs (11,236 ) (2,267 ) (15,690 ) Extensions, discoveries, and improved recovery less related costs — — 6,428 Sales of reserves in-place — — (130,802 ) Accretion of discount 1,738 7,246 29,042 Estimated settlement of asset retirement obligations — — (8 ) Estimated proceeds on disposals of well equipment — (9 ) 1 Balance, end of year $ 40,449 $ 17,381 $ 72,462 (1) See “ Reserve Quantity Information Revisions of Previous Estimates

Quarterly Results

Quarterly Results	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Results	NOTE 11 — QUARTERLY RESULTS (UNAUDITED) Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2017: Revenues $ 1,208 $ 1,282 $ 2,508 $ 3,153 Net loss attributable to common limited partners and the general partner’s interests (1) $ (1,187 ) $ (1,061 ) $ (357 ) $ (292 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (1,163 ) $ (1,040 ) $ (350 ) $ (286 ) General partner’s interest (24 ) (21 ) (7 ) (6 ) Net loss attributable to common unitholders per unit: Basic $ (0.05 ) $ (0.04 ) $ (0.02 ) $ (0.01 ) Diluted $ (0.05 ) $ (0.04 ) $ (0.02 ) $ (0.01 ) (1) For each of the first, second, third, and fourth quarters of the year ended December 31, 2017, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2016: Revenues $ 2,160 $ 2,918 $ 2,559 $ 3,434 Net loss attributable to common limited partners and the general partner’s interests (1)(2) $ (45,629 ) $ (9,551 ) $ (4,161 ) $ (4,296 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (44,717 ) $ (9,360 ) $ (4,077 ) $ (4,209 ) General partner’s interest (912 ) (191 ) (84 ) (87 ) Net loss attributable to common unitholders per unit: Basic $ (1.92 ) $ (0.40 ) $ (0.18 ) $ (0.18 ) Diluted $ (1.92 ) $ (0.40 ) $ (0.18 ) $ (0.18 ) (1) For each of the first, second, third, and fourth quarters of the year ended December 31, 2016, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. (2) Includes asset impairment charges of $41.9 million in the fourth quarter of 2016.

Summary of Significant Accoun17

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of Consolidation	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.
Use of Estimates	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, accruals for well drilling and completion costs, depletion and impairment of gas and oil properties, and fair value of derivative instruments. 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	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	Receivables Accounts receivable consists solely of the trade accounts receivable associated with our operations. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness as determined by our review of customers’ credit information. We extend credit on sales on an unsecured basis to many of our customers. At December 31, 2017 and 2016, we had recorded no allowance for uncollectible accounts receivable on our consolidated balance sheets.
Property, Plant and Equipment	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 which 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 which 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 six 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 our calculation of depletion. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated 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 statements 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 type, which is 15-20 years. See Note 3 for additional disclosures regarding property, plant and equipment.
Impairment of 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 futures 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 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. 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. See Note 3 for additional disclosures regarding impairment of property, plant and equipment.
Derivative Instruments	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 are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently within gain (loss) on mark-to-market derivatives in our consolidated statements of operations. See Note 4 for additional disclosures regarding derivative instruments.
Asset Retirement Obligations	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. The estimated liability for asset retirement obligations was based on our historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we determined that there were no other material retirement obligations associated with tangible long-lived assets. As of both December 31, 2017 and 2016, our asset retirement obligation was $0.2 million. For the years ended December 31, 2017, 2016 and 2015, we recorded $16,000, $15,000 and $14,000, respectively, of accretion expense related to our asset retirement obligations within depreciation, depletion and amortization in our consolidated statements of operations.
Other Non-current Liabilities	Other Non-current Liabilities We have two lease agreements in our Eagle Ford operating area that required us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the lease. We determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law to be $0.5 million which was recorded as a non-current liability on our consolidated balance sheet as of December 31, 2016. As of December 31, 2017, we presented $0.1 million as current accrued liabilities, to reflect the estimated amount owed within one year, and $0.3 million as the estimated remaining non-current liability on our consolidated balance sheet.
Income Taxes	Income Taxes We are not subject to U.S. federal and most state income taxes. Our partners are liable for income tax in regard to their distributive share of our taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the consolidated financial statements. We evaluate tax positions taken or expected to be taken in the course of preparing our tax returns and disallow the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. Our management does not believe it has any tax positions taken within our consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. We have not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2017 and 2016. We file Partnership Returns of Income in the U.S. and various state jurisdictions. We are not subject to income tax examinations by major tax authorities for years prior to 2013, our year of formation. We are not currently being examined by any jurisdiction and are not aware of any potential examinations. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since our operations are not subject to federal income tax, the Tax Act is not expected to have a material impact on us.
Segment Reporting	We derive revenue from our gas and oil production. These production facilities have been aggregated into one reportable segment, because the facilities have similar long-term economic characteristics, products and types of customers.
Net Income (Loss) Per Common Unit	Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s interest, by the weighted average number of common limited partner units outstanding during the period. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon our general partner units and incentive distributions to be distributed for the quarter (see Note 9), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with our Partnership Agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests. We present net income (loss) per unit under the two-class method, which considers whether the incentive distributions represent a participating security. The two-class method considers whether our Partnership Agreement contains 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 Partnership Agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, our management believes our Partnership Agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands): Years Ended December 31, 2017 2016 2015 Net loss $ (2,897 ) $ (63,637 ) (18,557 ) Less: General partner’s interest (58 ) (1,274 ) (370 ) Net loss attributable to common limited partners $ (2,839 ) $ (62,363 ) (18,187 ) Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners by the sum of the weighted average number of common limited partner units outstanding and the dilutive effect of common limited partner warrants, as calculated by the treasury stock method. The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): Years Ended December 31, 2017 2016 2015 Weighted average number of common units – basic 23,300 23,300 18,585 Add effect of dilutive awards(1) — — — Weighted average number of common units – diluted 23,300 23,300 18,585 (1) For both the years ended December 31, 2017 and 2016 and the year ended December 31, 2015, 2,330,000 and 1,859,000, respectively, common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.
Concentration of Credit Risk	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. At December 31, 2017 and 2016, we had $8.3 million and $10.3 million, respectively, in deposits at various banks, of which $8.0 million and $9.7 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 year ended December 31, 2017, Shell Trading Co individually accounted for approximately 91% of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2016, Shell Trading Co and Enterprise Crude Oil, LLC individually accounted for approximately 64% and 29%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, Enterprise Crude Oil, LLC, Shell Trading Co. and Midcoast Energy Partners individually accounted for approximately 59%, 28% and 12%, 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 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, 2017 represent financial instruments from one counterparty, which is a financial institution that has an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our credit facility. Subject to the terms of our credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the credit facility.
Revenue Recognition	Revenue Recognition 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 its 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 responsibilities 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. We 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 from our records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. We had unbilled revenues of $0.6 million and $0.9 million at December 31, 2017 and 2016, respectively, which were included in accounts receivable within our consolidated balance sheets.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“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 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. We have completed our detailed contract reviews and documentation.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Reconciliation of Net Loss	The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands): Years Ended December 31, 2017 2016 2015 Net loss $ (2,897 ) $ (63,637 ) (18,557 ) Less: General partner’s interest (58 ) (1,274 ) (370 ) Net loss attributable to common limited partners $ (2,839 ) $ (62,363 ) (18,187 )
Reconciliation of Weighted Average Number of Common Unit holder Units	The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net income (loss) attributable to common unit holders per unit with those used to compute diluted net income (loss) attributable to common unit holders per unit (in thousands): Years Ended December 31, 2017 2016 2015 Weighted average number of common units – basic 23,300 23,300 18,585 Add effect of dilutive awards(1) — — — Weighted average number of common units – diluted 23,300 23,300 18,585 (1) For both the years ended December 31, 2017 and 2016 and the year ended December 31, 2015, 2,330,000 and 1,859,000, respectively, common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Summary of Property, Plant and Equipment	The following is a summary of property, plant and equipment at the dates indicated (in thousands): December 31, 2017 December 31, 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment and other 3,188 3,188 151,120 151,133 Less – accumulated depreciation, depletion and amortization (85,827 ) (82,234 ) $ 65,293 $ 68,899

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Commodity Derivative Activity	The following table summarizes the commodity derivative activity for the period indicated (in thousands): Years Ended December 31, 2017 2016 Gains (losses) recognized on cash settlement $ 527 $ (106 ) Changes in fair value on open derivative contracts (217 ) (674 ) Gain (loss) on mark-to-market derivatives $ 310 $ (780 )
Fair Values of Derivative Instruments	The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our consolidated balance sheets as of the date indicated (in thousands): Offsetting Derivatives as of December 31, 2017 Gross Amounts Recognized Gross Amounts Offset Net Amount Presented Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Current portion of derivative liabilities $ (497 ) $ — $ (497 ) Long-term portion of derivative liabilities — — — Total derivative liabilities $ (497 ) $ — $ (497 ) Offsetting Derivatives as of December 31, 2016 Current portion of derivative assets $ 97 $ (97 ) $ — Long-term portion of derivative assets — — — Total derivative assets $ 97 $ (97 ) $ — Current portion of derivative liabilities $ (381 ) $ 97 $ (284 ) Long-term portion of derivative liabilities (280 ) — (280 ) Total derivative liabilities $ (661 ) $ 97 $ (564 )
Commodity Derivative Instruments by Type	As of December 31, 2017, we had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes (1) Average Fixed Price Fair Value Liability (in thousands) (2) 2018 74,500 $ 52.510 (497 ) Net liabilities $ (497 ) (1) Volumes for crude oil are stated in barrels. (2) Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

Fair Value of Financial Instr21

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Financial Instruments at Fair Value	Information for financial instruments measured at fair value was as follows (in thousands): As of December 31, 2017 Level 1 Level 2 Level 3 Total Assets, gross Commodity swaps $ — $ — $ — $ — Total derivative assets, gross — — — — Liabilities, gross Commodity swaps — (497 ) — (497 ) Total derivative liabilities, gross — (497 ) — (497 ) Total derivatives, fair value, net $ — $ (497 ) $ — $ (497 ) As of December 31, 2016 Assets, gross Commodity swaps $ — $ 97 $ — $ 97 Total derivative assets, gross — 97 — 97 Liabilities, gross Commodity swaps — (661 ) — (661 ) Total derivative liabilities, gross — (661 ) — (661 ) Total derivatives, fair value, net $ — $ (564 ) $ — $ (564 )

Supplemental Oil and Gas Info22

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Reserve Quantity Information	Reserve quantity information and a reconciliation of changes in proved reserve quantities were as follows: Gas (MMcf) Oil (MBbls) NGLs (MBbls) Total (MMcfe) Balance, January 1, 2015 8,493 14,931 1,622 107,811 Extensions, discoveries and other additions (1) 364 968 75 6,622 Sales of reserves in-place (3 ) (3,300 ) (7,579 ) (660 ) (52,734 ) Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) (2,246 ) (297 ) (381 ) (6,314 ) Production (203 ) (244 ) (30 ) (1,847 ) Balance, December 31, 2015 3,108 7,779 626 53,539 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) (1,521 ) (4,099 ) (332 ) (28,107 ) Production (154 ) (293 ) (27 ) (2,074 ) Balance, December 31, 2016 1,432 3,387 267 23,356 Extensions, discoveries and other additions — — — — Sales of reserves in-place — — — — Purchase of reserves in-place — — — — Revisions of previous estimates (2 ) 548 1,231 169 8,949 Production (114 ) (143 ) (20 ) (1,092 ) Balance, December 31, 2017 1,866 4,475 416 31,213 Proved developed reserves at: January 1, 2015 1,255 612 205 6,157 December 31, 2015 802 1,645 154 11,596 December 31, 2016 652 925 100 6,802 December 31, 2017 613 788 121 6,069 Proved undeveloped reserves at: January 1, 2015 7,238 14,319 1,417 101,654 December 31, 2015 2,306 6,134 472 41,942 December 31, 2016 780 2,462 167 16,554 December 31, 2017 1,253 3,687 295 25,144 (1) For the year ended December 31, 2015, the increase represents PUD conversions from probable reserves related to development activity in the Eagle Ford Shale. ( 2 ) See “Revisions of Previous Estimates (3 ) Decrease due to the assignment of certain Eagle Ford assets to ARP in 2015.
Schedule of Revisions of Previous Estimates	The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above: December 31, 2017 2016 2015 Unadjusted Prices Natural gas (per MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (per Bbl) $ 51.34 $ 42.75 $ 50.28 Natural gas liquids (per Bbl) $ 20.33 $ 19.57 $ 11.02
Schedule of Capitalized Costs Related to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities . The components of our capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands): December 31, 2017 2016 Natural gas and oil properties: Proved properties $ 147,932 $ 84,631 Unproved properties — 63,314 Support equipment 29 29 147,961 147,974 Accumulated depreciation, depletion and amortization (85,328 ) (81,901 ) Net capitalized costs $ 62,633 $ 66,073
Schedule of Results of Operations from Oil and Gas Producing Activities	Results of Operations from Oil and Gas Producing Activities. The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2017 2016 2015 Gas and oil production revenues $ 7,841 $ 11,851 $ 11,846 Production costs (2,528 ) (2,660 ) (2,229 ) Depletion (3,410 ) (14,694 ) (8,777 ) Asset impairment (1) — (41,879 ) (7,346 ) $ 1,903 $ (47,382 ) $ (6,506 ) (1) For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties.
Schedule of Costs Incurred in Oil and Gas Producing Activities	Costs Incurred in Oil and Gas Producing Activities . The costs incurred by our oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2017 2016 2015 Property acquisition costs: Proved properties $ — $ 143 $ 43,520 Unproved properties — — — Exploration costs (1) — — — Development costs — 5,946 28,822 Total costs incurred in oil & gas producing activities $ — $ 6,089 $ 72,342 (1) There were no exploratory wells drilled during the periods presented.
Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows	Standardized Measure of Discounted Future Cash Flows . The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the periods presented, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2017 2016 2015 Future cash inflows $ 243,644 $ 145,857 $ 396,141 Future production costs (73,792 ) (53,738 ) (117,785 ) Future development costs (68,321 ) (51,942 ) (133,474 ) Future net cash flows 101,531 40,177 144,882 Less 10% annual discount for estimated timing of cash flows (61,082 ) (22,796 ) (72,420 ) Standardized measure of discounted future net cash flows $ 40,449 $ 17,381 $ 72,462
Schedule of Changes in Discounted Future Net Cash Flows	Change in Standardized Discounted Cash Flows . The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since we allocate taxable income to our unitholders, no recognition has been given to income taxes: Years Ended December 31, 2017 2016 2015 Balance, beginning of year $ 17,381 $ 72,462 $ 290,416 Increase (decrease) in discounted future net cash flows (1) Sales of oil and gas produced, net of related costs (5,403 ) (8,758 ) (8,590 ) Net changes in estimated future prices and production costs 22,401 (19,173 ) (176,091 ) Revisions of previous quantity estimates 15,568 (32,119 ) 47,612 Development costs incurred — — 30,144 Changes in future development costs (11,236 ) (2,267 ) (15,690 ) Extensions, discoveries, and improved recovery less related costs — — 6,428 Sales of reserves in-place — — (130,802 ) Accretion of discount 1,738 7,246 29,042 Estimated settlement of asset retirement obligations — — (8 ) Estimated proceeds on disposals of well equipment — (9 ) 1 Balance, end of year $ 40,449 $ 17,381 $ 72,462 (1) See “ Reserve Quantity Information Revisions of Previous Estimates

Quarterly Results (Tables)

Quarterly Results (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2017: Revenues $ 1,208 $ 1,282 $ 2,508 $ 3,153 Net loss attributable to common limited partners and the general partner’s interests (1) $ (1,187 ) $ (1,061 ) $ (357 ) $ (292 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (1,163 ) $ (1,040 ) $ (350 ) $ (286 ) General partner’s interest (24 ) (21 ) (7 ) (6 ) Net loss attributable to common unitholders per unit: Basic $ (0.05 ) $ (0.04 ) $ (0.02 ) $ (0.01 ) Diluted $ (0.05 ) $ (0.04 ) $ (0.02 ) $ (0.01 ) (1) For each of the first, second, third, and fourth quarters of the year ended December 31, 2017, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2016: Revenues $ 2,160 $ 2,918 $ 2,559 $ 3,434 Net loss attributable to common limited partners and the general partner’s interests (1)(2) $ (45,629 ) $ (9,551 ) $ (4,161 ) $ (4,296 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (44,717 ) $ (9,360 ) $ (4,077 ) $ (4,209 ) General partner’s interest (912 ) (191 ) (84 ) (87 ) Net loss attributable to common unitholders per unit: Basic $ (1.92 ) $ (0.40 ) $ (0.18 ) $ (0.18 ) Diluted $ (1.92 ) $ (0.40 ) $ (0.18 ) $ (0.18 ) (1) For each of the first, second, third, and fourth quarters of the year ended December 31, 2016, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive. (2) Includes asset impairment charges of $41.9 million in the fourth quarter of 2016.

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017shares
Common Limited Partners' Interests
Basis Of Presentation [Line Items]
Common units, issued	23,300,410
Common units, outstanding	23,300,410
Atlas Growth Partners GP, LLC
Basis Of Presentation [Line Items]
General partner ownership interest	100.00%
Percentage of cash distribution	2.00%
ATLS
Basis Of Presentation [Line Items]
General partner ownership interest	80.00%
Common limited partner ownership interest	2.10%
General partners remaining ownership interest	20.00%
ATLS | Titan Energy, LLC | Series A Preferred Share
Basis Of Presentation [Line Items]
Percentage of cash distribution	2.00%

Summary of Significant Accoun25

Summary of Significant Accounting Policies - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017USD ($)LeaseSegment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Significant Accounting Policies [Line Items]
Allowance for uncollectible accounts receivable	$ 0	$ 0
Asset retirement obligation	$ 200,000	200,000
Number of lease agreements | Lease	2
Other liabilities recorded	$ 300,000	500,000
Accrued liabilities current	$ 100,000
Entity not subject to income taxes, policy	We are not subject to U.S. federal and most state income taxes. Our partners are liable for income tax in regard to their distributive share of our taxable income. Such taxable income may vary substantially from net income reported in the accompanying consolidated financial statements. Accordingly, no federal or state current or deferred income tax has been provided for in the consolidated financial statements.
Income tax examination, description	We file Partnership Returns of Income in the U.S. and various state jurisdictions. We are not subject to income tax examinations by major tax authorities for years prior to 2013, our year of formation. We are not currently being examined by any jurisdiction and are not aware of any potential examinations
Number of reportable segments | Segment	1
Partnership deposits at various banks	$ 8,300,000	10,300,000
Deposits over insurance limit of Federal Deposit Insurance Corporation	$ 8,000,000	9,700,000
Concentration of credit risk, uninsured deposits	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. At December 31, 2017 and 2016, we had $8.3 million and $10.3 million, respectively, in deposits at various banks, of which $8.0 million and $9.7 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.
Loss on Investments	$ 0
Concentration risk, customer	We sell natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2017, Shell Trading Co individually accounted for approximately 91% of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2016, Shell Trading Co and Enterprise Crude Oil, LLC individually accounted for approximately 64% and 29%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, Enterprise Crude Oil, LLC, Shell Trading Co. and Midcoast Energy Partners individually accounted for approximately 59%, 28% and 12%, respectively, of our natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.
Unbilled revenues	$ 600,000	$ 900,000
Consolidated Revenues | Shell Trading Co | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk, percentage	91.00%	64.00%	28.00%
Consolidated Revenues | Enterprise Crude Oil, LLC | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk, percentage		29.00%	59.00%
Consolidated Revenues | Midcoast Energy Partners | Customer Concentration Risk
Significant Accounting Policies [Line Items]
Concentration risk, percentage			12.00%
Depreciation, depletion and amortization
Significant Accounting Policies [Line Items]
Accretion expense related to asset retirement obligations	$ 16,000	$ 15,000	$ 14,000
Minimum | Support Equipment and Other
Significant Accounting Policies [Line Items]
Support equipment and other useful life	15 years
Maximum | Support Equipment and Other
Significant Accounting Policies [Line Items]
Support equipment and other useful life	20 years

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Schedule of Net Loss Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Net loss									$ (2,897)	$ (63,637)	$ (18,557)
Less: General partner’s interest	$ (24)	$ (21)	$ (7)	$ (6)	$ (912)	$ (191)	$ (84)	$ (87)	(58)	(1,274)	(370)
Net loss attributable to common limited partners	$ (1,163)	$ (1,040)	$ (350)	$ (286)	$ (44,717)	$ (9,360)	$ (4,077)	$ (4,209)	$ (2,839)	$ (62,363)	$ (18,187)

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Units) (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Weighted average number of common units – basic	23,300,000	23,300,000	18,585,000
Weighted average number of common units – diluted	23,300,000	23,300,000	18,585,000
Antidilutive securities excluded from computation of diluted net income (loss) attributable to common limited partners outstanding units	2,330,000	2,330,000	1,859,000

Property, Plant and Equipment28

Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Proved properties	$ 147,932	$ 84,631
Unproved properties		63,314
Support equipment and other	3,188	3,188
Total gross property, plant and equipment	151,120	151,133
Less – accumulated depreciation, depletion and amortization	(85,827)	(82,234)
Property, plant and equipment, Net, Total	$ 65,293	$ 68,899

Property, Plant and Equipment -

Property, Plant and Equipment - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Property Plant And Equipment [Line Items]
Unproved properties transferred to proved natural gas and oil properties			$ 63,300,000
Asset impairment of oil and gas properties	$ 41,879,000	$ 7,346,000
Non-cash investing activities capital expenditures	400,000
Unproved Oil and Gas Properties
Property Plant And Equipment [Line Items]
Asset impairment of oil and gas properties		0
Eagle Ford Acquisition | ARP
Property Plant And Equipment [Line Items]
Deferred acquisition purchase price		36,300,000
Eagle Ford Acquisition | Unproved Oil and Gas Properties
Property Plant And Equipment [Line Items]
Asset impairment of oil and gas properties	16,500,000
Eagle Ford Acquisition | Proved Oil and Gas Properties
Property Plant And Equipment [Line Items]
Asset impairment of oil and gas properties	$ 25,400,000
Marble Falls and Mississippi Lime
Property Plant And Equipment [Line Items]
Asset impairment of oil and gas properties		$ 7,300,000

Derivative Instruments (Summary

Derivative Instruments (Summary of Commodity Derivative Activity) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains (losses) recognized on cash settlement	$ 527	$ (106)
Changes in fair value on open derivative contracts	(217)	(674)	$ 412
Gain (loss) on mark-to-market derivatives	$ 310	$ (780)	$ 862

Derivative Instruments (Fair Va

Derivative Instruments (Fair Values of Derivative Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets		$ 97
Gross Amounts Recognized, Liabilities	$ (497)	(661)
Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(497)	(381)
Gross Amounts Offset, Liabilities		97
Net Amount Presented, Liabilities	(497)	(284)
Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(280)
Net Amount Presented, Liabilities		(280)
Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(497)	(661)
Gross Amounts Offset, Liabilities		97
Net Amount Presented, Liabilities	$ (497)	(564)
Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets		97
Gross Amounts Offset, Assets		(97)
Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets		97
Gross Amounts Offset, Assets		$ (97)

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivative Instruments by Type) (Details) $ in Thousands	Dec. 31, 2017USD ($)bbl$ / bbl
Crude Oil - Fixed Price Swaps for Production Period Ending December 31, 2018
Derivatives Fair Value [Line Items]
Volumes | bbl	74,500	[1]
Average Fixed Price | $ / bbl	52.510	[1]
Fair Value Liability	$ (497)	[2]
Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Liability	$ (497)	[2]
[1]	Volumes for crude oil are stated in barrels.
[2]	Fair value of crude oil fixed price swaps are based on forward WTI crude oil prices, as applicable.

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments Gain Loss [Line Items]
Commitments
Credit Facility
Derivative Instruments Gain Loss [Line Items]
Commitments	$ 0

Fair Value of Financial Instr34

Fair Value of Financial Instruments (Schedule of Financial Instruments at Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross		$ 97
Derivative liabilities, gross	$ (497)	(661)
Total derivatives, fair value, net	(497)	(564)
Commodity Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross		97
Derivative liabilities, gross	(497)	(661)
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross		97
Derivative liabilities, gross	(497)	(661)
Total derivatives, fair value, net	(497)	(564)
Level 2 | Commodity Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross		97
Derivative liabilities, gross	$ (497)	$ (661)

Fair Value of Financial Instr35

Fair Value of Financial Instruments - Additional Information (Details) - Common Limited Partners' Warrants - Level 3	12 Months Ended
	Dec. 31, 2017$ / shares
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair value assumptions, exercise price	$ 10
Fair value inputs, discount rate	0.50%
Fair value assumptions, expected term	1 year 6 months
Fair value assumptions, expected dividend rate	7.00%
Fair value assumptions, expected volatility rate	50.00%
Estimated fair value per warrant	$ 1.47
Estimated fair value per warrant, liquidity adjustment	$ 0.37

Certain Relationships and Rel36

Certain Relationships and Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Accounts payable	$ 606	$ 1,355
Relationship with General Partner
Related Party Transaction [Line Items]
Percentage of capital contribution	1.00%	1.00%
Payment for management fee	$ 2,300	$ 2,300
Relationship with ATLS
Related Party Transaction [Line Items]
Accounts payable	600	600
Relationship with Titan/ARP
Related Party Transaction [Line Items]
Accounts payable	$ 100	$ 800

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Operating leases, rental expense, net	$ 200,000	$ 300,000	$ 500,000
Future minimum rental commitments	0
Long-term purchase commitment, amount	0
Accrual for environmental loss contingencies	$ 0	$ 0

Issuances of Units (Details)

Issuances of Units (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capital Unit [Line Items]
Reclassification adjustment of offering costs to other loss			$ (5,297,000)
Offering costs previously capitalized as offset to proceed raised				$ 1,500,000
Common limited partner units issued			$ 1,541,000	$ 111,189,000
Additional consideration for warrants to purchase additional common units		$ 0
Percentage of warrants to purchase additional common units in amount equal to		10.00%
Warrants, exercise price		$ 10
Partners unit, issued				12,623,500
Common limited partner number of units purchased				300,000
Common limited partner units purchased				$ 2,700,000
Warrants to purchase common units	2,330,041			1,262,350
Warrants to purchase common units, per share	$ 10			$ 10
Sale of common units, per share				$ 10
Net proceeds from issuance of common units				$ 112,700,000
Fees and commission and expenses				$ 12,700,000
Private Placement Offering
Capital Unit [Line Items]
Common limited partner units issued	$ 233,000,000	$ 500,000,000
Number of days extension private placement offering		two 90 day
Partners unit, issued	23,300,410
Fees and commission and expenses	$ 203,400,000
Common limited partner number of units purchased	500,010
Common limited partner units purchased	$ 5,000,000

Cash Distributions - Additional

Cash Distributions - Additional Information (Details) $ / shares in Units, $ in Millions	3 Months Ended						12 Months Ended
	Jun. 30, 2016$ / shares	Mar. 31, 2016$ / shares	Dec. 31, 2015$ / shares	Sep. 30, 2015$ / shares	Jun. 30, 2015$ / shares	Mar. 31, 2015$ / shares	Dec. 31, 2017$ / perunit	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Distribution Made To Limited Partner [Line Items]
Quarterly cash distribution target | $ / perunit							0.175
Yearly cash distribution target | $ / perunit							0.70
Common Limited Partners' Interests
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $								$ 12.2	$ 10.5
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ / shares	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750
General Partners
Distribution Made To Limited Partner [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid | $								$ 0.3	$ 0.2
Distribution Made to Member or Limited Partner, Distributions Paid, Per Unit | $ / shares	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750	$ 0.1750

Supplemental Oil and Gas Info40

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Details) - MMcfe	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas In Process Activities [Line Items]
Maximum scheduled drilling term	5 years
Estimation of reserves quantities and future net cash flows description	The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2017, 2016 and 2015, including adjustments related to regional price differentials and energy content.
Revisions of previous estimates, positive revisions due to modification in development plans	8,585
Revisions of previous estimates, positive revisions due to increases in pricing	1,208
Revisions of previous estimates, positive revisions due to production underperforming	844
Revisions of previous estimates, negative revisions due to removal of proved undeveloped properties		23,794	3,268
Revisions of previous estimates, negative revisions due to production underperforming		3,582
Revisions of previous estimates, negative revisions due to decreases in pricing		731	4,543
Revisions of previous estimates, partially offset due to production outperforming			1,497
Gas And Oil Production
Oil And Gas In Process Activities [Line Items]
Percentage of discount factor to measure future cash flows	10.00%

Supplemental Oil and Gas Info41

Supplemental Oil and Gas Information (Unaudited) (Reserve Quantity Information) (Details)		12 Months Ended
		Dec. 31, 2017MMcfeMMcfMBbls	Dec. 31, 2016MMcfeMMcfMBbls	Dec. 31, 2015MMcfeMMcfMBbls	Dec. 31, 2014MMcfeMMcfMBbls
Reserve Quantities [Line Items]
Balance | MMcfe		23,356	53,539	107,811
Extensions, discoveries and other additions | MMcfe	[1]			6,622
Sales of reserves in-place | MMcfe	[2]			(52,734)
Revisions of previous estimates | MMcfe	[3]	8,949	(28,107)	(6,314)
Production | MMcfe		(1,092)	(2,074)	(1,847)
Balance | MMcfe		31,213	23,356	53,539
Proved developed reserves | MMcfe		6,069	6,802	11,596	6,157
Proved undeveloped reserves | MMcfe		25,144	16,554	41,942	101,654
Gas
Reserve Quantities [Line Items]
Balance | MMcf		1,432	3,108	8,493
Extensions, discoveries and other additions | MMcf	[1]			364
Sales of reserves in-place | MMcf	[2]			(3,300)
Revisions of previous estimates | MMcf	[3]	548	(1,521)	(2,246)
Production | MMcf		(114)	(154)	(203)
Balance | MMcf		1,866	1,432	3,108
Proved developed reserves | MMcf		613	652	802	1,255
Proved undeveloped reserves | MMcf		1,253	780	2,306	7,238
Oil
Reserve Quantities [Line Items]
Balance		3,387	7,779	14,931
Extensions, discoveries and other additions	[1]			968
Sales of reserves in-place	[2]			(7,579)
Revisions of previous estimates	[3]	1,231	(4,099)	(297)
Production		(143)	(293)	(244)
Balance		4,475	3,387	7,779
Proved developed reserves		788	925	1,645	612
Proved undeveloped reserves		3,687	2,462	6,134	14,319
NGLs
Reserve Quantities [Line Items]
Balance		267	626	1,622
Extensions, discoveries and other additions	[1]			75
Sales of reserves in-place	[2]			(660)
Revisions of previous estimates	[3]	169	(332)	(381)
Production		(20)	(27)	(30)
Balance		416	267	626
Proved developed reserves		121	100	154	205
Proved undeveloped reserves		295	167	472	1,417
[1]	For the year ended December 31, 2015, the increase represents PUD conversions from probable reserves related to development activity in the Eagle Ford Shale.
[2]	Decrease due to the assignment of certain Eagle Ford assets to ARP in 2015.
[3]	See “Revisions of Previous Estimates” section below for additional discussion and analysis of significant components of revisions of previous estimates.

Supplemental Oil and Gas Info42

Supplemental Oil and Gas Information (Unaudited) (Schedule of Revisions of Previous Estimates) (Details)	12 Months Ended
	Dec. 31, 2017$ / bbl$ / MMBTU	Dec. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015$ / bbl$ / MMBTU
Gas
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Unadjusted Prices | $ / MMBTU	2.98	2.48	2.59
Oil
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Unadjusted Prices	51.34	42.75	50.28
NGLs
Average Sales Price And Production Costs Per Unit Of Production [Line Items]
Unadjusted Prices	20.33	19.57	11.02

Supplemental Oil and Gas Info43

Supplemental Oil and Gas Information (Unaudited) (Schedule of Results Capitalized Costs Related to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Proved properties	$ 147,932	$ 84,631
Unproved properties		63,314
Support equipment	29	29
Natural gas and oil properties	147,961	147,974
Accumulated depreciation, depletion and amortization	(85,328)	(81,901)
Net capitalized costs	$ 62,633	$ 66,073

Supplemental Oil and Gas Info44

Supplemental Oil and Gas Information (Unaudited) (Schedule of Results of Operations from Oil and Gas Producing Activities) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Gas and oil production revenues		$ 7,841,000	$ 11,851,000		$ 11,846,000
Production costs		(2,528,000)	(2,660,000)		(2,229,000)
Depletion		(3,410,000)	(14,694,000)		(8,777,000)
Asset impairment	$ (41,900,000)		(41,879,000)	[1]	(7,346,000)	[1]
Results of operations from oil and gas producing activities		$ 1,903,000	(47,382,000)		(6,506,000)
Asset impairment of oil and gas properties			41,879,000		7,346,000
Unproved Oil and Gas Properties
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Asset impairment of oil and gas properties					0
Marble Falls and Mississippi Lime
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Asset impairment of oil and gas properties					$ 7,300,000
Eagle Ford Acquisition | Proved Oil and Gas Properties
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Asset impairment of oil and gas properties			25,400,000
Eagle Ford Acquisition | Unproved Oil and Gas Properties
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Asset impairment of oil and gas properties			$ 16,500,000
[1]	For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $7.3 million of asset impairment related to oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices.

Supplemental Oil and Gas Info45

Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Incurred in Oil and Gas Producing Activities) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017Well	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)Well
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Proved properties		$ 143	$ 43,520
Development costs		5,946	28,822
Total costs incurred in oil & gas producing activities		$ 6,089	$ 72,342
Number of exploratory wells drilled | Well	0	0	0

Supplemental Oil and Gas Info46

Supplemental Oil and Gas Information (Unaudited) (Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Future cash inflows	$ 243,644	$ 145,857	$ 396,141
Future production costs	(73,792)	(53,738)	(117,785)
Future development costs	(68,321)	(51,942)	(133,474)
Future net cash flows	101,531	40,177	144,882
Less 10% annual discount for estimated timing of cash flows	(61,082)	(22,796)	(72,420)
Standardized measure of discounted future net cash flows	$ 40,449	$ 17,381	$ 72,462

Supplemental Oil and Gas Info47

Supplemental Oil and Gas Information (Unaudited) (Schedule of Changes in Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Balance, beginning of year		$ 17,381	$ 72,462	$ 290,416
Sales of oil and gas produced, net of related costs	[1]	(5,403)	(8,758)	(8,590)
Net changes in estimated future prices and production costs	[1]	22,401	(19,173)	(176,091)
Revisions of previous quantity estimates	[1]	15,568	(32,119)	47,612
Development costs incurred	[1]			30,144
Changes in future development costs	[1]	(11,236)	(2,267)	(15,690)
Extensions, discoveries, and improved recovery less related costs	[1]			6,428
Sales of reserves in-place	[1]			(130,802)
Accretion of discount	[1]	1,738	7,246	29,042
Estimated settlement of asset retirement obligations	[1]			(8)
Estimated proceeds on disposals of well equipment	[1]		(9)	1
Balance, end of year		$ 40,449	$ 17,381	$ 72,462
[1]	See “Reserve Quantity Information” and “Revisions of Previous Estimates” sections above for additional discussion and analysis of significant changes within the periods presented.

Quarterly Results (Unaudited) -

Quarterly Results (Unaudited) - Schedule of Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 1,208		$ 1,282		$ 2,508		$ 3,153		$ 2,160		$ 2,918		$ 2,559		$ 3,434		$ 8,151	$ 11,071		$ 12,708
Net loss attributable to common limited partners and the general partner’s interests	(1,187)	[1]	(1,061)	[1]	(357)	[1]	(292)	[1]	(45,629)	[2],[3]	(9,551)	[2],[3]	(4,161)	[2],[3]	(4,296)	[2],[3]
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	(1,163)		(1,040)		(350)		(286)		(44,717)		(9,360)		(4,077)		(4,209)		(2,839)	(62,363)		(18,187)
General partner’s interest	$ (24)		$ (21)		$ (7)		$ (6)		$ (912)		$ (191)		$ (84)		$ (87)		$ (58)	$ (1,274)		(370)
Basic	$ (0.05)		$ (0.04)		$ (0.02)		$ (0.01)		$ (1.92)		$ (0.40)		$ (0.18)		$ (0.18)
Diluted	$ (0.05)		$ (0.04)		$ (0.02)		$ (0.01)		$ (1.92)		$ (0.40)		$ (0.18)		$ (0.18)
Antidilutive securities excluded from computation of diluted earnings attributable to common limited partners outstanding units	2,330,000		2,330,000		2,330,000		2,330,000		2,330,000		2,330,000		2,330,000		2,330,000
All antidilutive securities excluded from computation of diluted earnings attributable to common limited partners outstanding units																	For each of the first, second, third, and fourth quarters of the year ended December 31, 2017, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive	For each of the first, second, third, and fourth quarters of the year ended December 31, 2016, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive
Asset impairment charges									$ 41,900									$ 41,879	[4]	$ 7,346	[4]
[1]	For each of the first, second, third, and fourth quarters of the year ended December 31, 2017, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.
[2]	For each of the first, second, third, and fourth quarters of the year ended December 31, 2016, approximately 2,330,000 common limited partner warrants were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of units issuable upon the exercise of the warrants would have been anti-dilutive.
[3]	Includes asset impairment charges of $41.9 million in the fourth quarter of 2016
[4]	For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to our proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $7.3 million of asset impairment related to oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices.