DGOC Series 28 10-K 28 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	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	DGOC Series 28, L.P.
Entity Central Index Key	1,711,485
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0
Entity Public Float		$ 0
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No

Balance Sheets

Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash	$ 0	$ 152,800
Accounts receivable trade-affiliate	1,016,100	656,300
Total current assets	1,016,100	809,100
Natural gas properties, net	18,591,300	19,836,500
Long-term asset retirement receivable-affiliate	47,200	24,800
Total assets	19,654,600	20,670,400
Current liabilities:
Accrued liabilities	79,500	15,300
Total current liabilities	79,500	15,300
Asset retirement obligations	1,799,500	1,698,100
Total long-term liabilities	1,799,500	1,698,100
Total liabilities	1,879,000	1,713,400
Commitments and contingencies (Note 7)
Partners’ capital:
Managing general partner’s interest	2,653,000	2,787,500
Limited partners’ interest (7,500 units)	15,122,600	16,169,500
Total partners’ capital	17,775,600	18,957,000
Total liabilities and partners’ capital	$ 19,654,600	$ 20,670,400

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical)	Dec. 31, 2017shares
Statement of Financial Position [Abstract]
Limited partners' units	7,500

Statements Of Operations

Statements Of Operations - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
REVENUES
Natural gas	$ 4,174,700	$ 2,643,700
Loss on mark-to-market derivatives	0	(20,100)
Total revenues	4,174,700	2,623,600
COSTS AND EXPENSES
Production	1,104,800	837,700
Depletion	1,245,200	1,327,900
Accretion of asset retirement obligations	101,400	95,700
General and administrative	63,900	42,800
Total costs and expenses	2,515,300	2,304,100
Net income	$ 1,659,400	319,500
Allocation of net income:
Managing general partner		455,400
Limited partners		$ (135,900)
Net income (loss) per limited partnership unit	$ 99	$ (18)

Statements Of Changes In Partne

Statements Of Changes In Partners' Capital - USD ($)	Total	Managing General Partner	Limited Partners
Beginning balance at Dec. 31, 2015	$ 21,147,700	$ 2,984,900	$ 18,162,800
Participation in revenues and costs and expenses:
Net production revenues	1,806,000	694,200	1,111,800
Loss on mark-to-market derivatives	(20,100)	0	(20,100)
Depletion	(1,327,900)	(186,700)	(1,141,200)
Accretion of asset retirement obligations	(95,700)	(36,000)	(59,700)
General and administrative	(42,800)	(16,100)	(26,700)
Net income	319,500	455,400	(135,900)
Subordination	0	(188,000)	188,000
Distributions to partners	(2,510,200)	(464,800)	(2,045,400)
Ending balance at Dec. 31, 2016	18,957,000	2,787,500	16,169,500
Participation in revenues and costs and expenses:
Net production revenues	3,069,900	1,154,100	1,915,800
Loss on mark-to-market derivatives	0
Depletion	(1,245,200)	(175,000)	(1,070,200)
Accretion of asset retirement obligations	(101,400)	(38,100)	(63,300)
General and administrative	(63,900)	(24,000)	(39,900)
Net income	1,659,400	917,000	742,400
Distributions to partners	(2,840,800)	(1,051,500)	(1,789,300)
Ending balance at Dec. 31, 2017	$ 17,775,600	$ 2,653,000	$ 15,122,600

Statements Of Cash Flows

Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income	$ 1,659,400	$ 319,500
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	1,245,200	1,327,900
Non-cash loss on derivative value	0	421,700
Accretion of asset retirement obligations	101,400	95,700
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate	(359,800)	333,900
Increase in asset retirement receivable-affiliate	(22,400)	(9,600)
Increase in accrued liabilities	64,200	1,900
Net cash provided by operating activities	2,688,000	2,491,000
Cash flows from investing activities:
Net cash provided by investing activities	0	0
Cash flows from financing activities:
Distributions to partners	(2,840,800)	(2,510,200)
Net cash used in financing activities	(2,840,800)	(2,510,200)
Net change in cash	(152,800)	(19,200)
Cash at beginning of year	152,800	172,000
Cash at end of year	$ 0	$ 152,800

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES DGOC Series 28, L.P. (the “Partnership”) is a Delaware limited partnership formed on July 6, 2017 and includes the Appalachian-based assets that were previously included within Atlas Resources Series 28-2010 L.P. ("Predecessor Partnership") that was formed on April 1, 2010 and was then managed by Atlas Resources, LLC ("Atlas" or "Previous MGP"). DGOC Partnership Holdings, LLC now serves as the Partnership's Managing General Partner (“DGOC Holdings” or the “MGP”) and certain affiliates of the MGP serve as our Operator ("Operator"). DGOC Holdings is an indirect subsidiary of Diversified Gas & Oil, PLC (“Diversified”; AIM: DGOC). Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to DGOC Series 28, L.P. Atlas previously served as the Partnership's Managing General Partner and Operator. Atlas is an indirect subsidiary of Titan Energy, LLC (“Titan”). On May 4, 2017, Titan entered into a definitive agreement to sell, among other conventional assets, its general and limited partnership equity interest (“Equity Interest”) in the Partnership to Diversified (the “Purchase and Sale Agreement” or “PSA”). The transaction closed on September 29, 2017. Prior to closing the PSA, the Previous MGP delegated operational activities to an affiliate of Diversified for the Partnership’s natural gas wells in Pennsylvania on June 30, 2017. Upon closing the PSA, the Previous MGP’s Equity Interest in the Partnership was transferred to DGOC Holdings and DGOC Holdings was admitted as a substitute managing general partner of the Partnership and continues to serve as Operator. Use of Estimates Preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires the MGP 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 the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, impairments, fair value of derivative instruments, and the probability of forecasted transactions. The natural 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. Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2017 and 2016 , the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. Asset retirement receivable-affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnerships wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells. For additional information, see Note 7. The following is a reconciliation of the Partnership’s asset retirement receivable-affiliate for the years indicated: 2017 2016 Asset retirement receivable – affiliate, beginning of year $ 24,800 $ 15,200 Asset retirement estimates withheld 22,400 9,600 Asset retirement receivable –affiliate, end of year $ 47,200 $ 24,800 Natural Gas Properties Natural gas properties are stated at cost. The Partnership follows the successful efforts method of accounting for natural gas producing activities. The Partnership expenses maintenance and repairs as incurred that generally do not extend the useful life or enhance the productivity of an asset for two years or more through the replacement of critical components. The Partnership capitalizes major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components. For additional information see Note 3. The Partnership’s depletion expense is determined using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with the field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership also considers the estimated salvage value in the calculation of depletion. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets. Impairment of Long-Lived Assets The Partnership reviews its long-lived assets 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 of that asset to its estimated fair value if such carrying amount exceeds the fair value. The MGP reviews the Partnership’s natural gas properties by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The MGP estimates the expected future cash flows based on the Partnership’s plans to continue to produce and develop proved reserves. The MGP calculates the expected future cash flow from the sale of the production of reserves based on estimated future prices. The Partnership estimates 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, we recognize impairment loss for the difference between the estimated fair market value (as determined by the discounted cash flows) and the carrying value of the assets. Determination of 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. 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. The Partnership cannot predict what reserve revisions may be required in future periods. For additional information, see Note 3. Derivative Instruments and Other Comprehensive Loss The Partnership’s Previous MGP entered into certain financial derivative contracts to manage the Partnership’s exposure to changes in commodity prices. The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value were recognized in the Partnership’s statements of operations unless specific hedge accounting criteria were met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2015 of these derivatives were recognized immediately within loss on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2015 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. There was no other comprehensive loss for the year ended December 31, 2016, the loss subsequent to hedge accounting recognized in loss on mark-to-market derivatives was $20,100 . Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its natural gas wells and related facilities (For additional information see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Company’s tax returns are generally subject to possible examination by the taxing authorities for a period of three years from the date they are filed, though the Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2017 . Environmental Matters The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2017 and 2016 . Concentration of Credit Risk The Partnership sells natural gas under contracts to various purchasers in the normal course of business. For the years ended December 31, 2017 and 2016 , the Partnership had the following customers that individually accounted for greater than 10% of the Partnership's natural gas revenues. Percentage of Revenue Customer 2017 2016 Direct Energy Business LLC 100 % — % Hess Energy Marketing LLC — % 56 % Chevron Natural — % 44 % Total 100 % 100 % Revenue Recognition The Partnership sells natural gas at prevailing market prices. The Partnership’s 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. The market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The Partnership recognizes revenues from the production of natural gas in which the Partnership has an interest with other producers on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at December 31, 2017 and 2016 of $561,600 and $573,900 , respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. Recently Issued Accounting Standards In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. At December 31, 2017, the MGP has completed the evaluation of sources of revenue and the impact of this accounting standards update on our results of operations, financial position, cash flows and financial disclosures, in addition to developing and implementing any process or control changes necessary. We do not expect to record a cumulative effect adjustment on date of adoption. The Partnership adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

Participation in Revenues and C

Participation in Revenues and Costs (Working Interest)	12 Months Ended
	Dec. 31, 2017
Partners' Capital Notes [Abstract]
PARTICIPATION IN REVENUES AND COSTS (WORKING INTEREST)	PARTICIPATION IN REVENUES AND COSTS (WORKING INTEREST) The MGP allocates revenues and expenses to the MGP and limited partners based on their proportion of capital contributions to total contributions ("working interest") per the partnership agreement. The MGP has provided an additional working interest of 10% as provided in the partnership agreement. The MGP determined the final working interest ownership of the partners once the wells were producing. The MGP and the limited partners generally participated in revenues and costs in the following manner: Managing General Partner Limited Partners Organization and offering cost 100% —% Lease costs 100% —% Intangible drilling costs 8% 92% Tangible equipment costs 52% 48% Revenues (1) 37% 63% Operating costs, administrative costs, direct and all other costs (2) 37% 63% ___________________________________________________________________________________________________ (1) All partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues which is reflected in the rate presented. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT The following is a summary of proved natural gas properties at the dates indicated: December 31, 2017 2016 Leasehold interests $ 540,100 $ 540,100 Wells and related equipment 90,300,700 90,300,700 Total natural gas properties 90,840,800 90,840,800 Accumulated depletion and impairment (72,249,500 ) (71,004,300 ) Natural gas properties, net $ 18,591,300 $ 19,836,500 The Partnership recorded depletion expense on natural gas properties of $1,245,200 and $1,327,900 for the years ended December 31, 2017 and 2016 , respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS The estimated liability for asset retirement obligations is based on the MGP’s 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 is 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. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. The MGP’s historical practice and continued intention is to retain distributions from the limited partners up to the fair value of the future plugging and abandonment costs. As of December 31, 2017 and 2016 , the MGP and the Previous MGP withheld $47,200 and $24,800 , respectively, of net production revenue for future plugging and abandonment costs. The following table reconciles the Partnership’s asset retirement obligation liability for well plugging and abandonment costs: Years Ended December 31, 2017 2016 Asset retirement liability, beginning of year $ 1,698,100 $ 1,602,400 Accretion expense 101,400 95,700 Asst retirement liability, end of year $ 1,799,500 $ 1,698,100

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	FAIR VALUE OF FINANCIAL INSTRUMENTS The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it 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 the Partnership’s 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 for identical instruments in active markets. Level 2– Quoted prices for similar instruments. Level 3 –Valuations that are significant and unobservable. Financial Instruments The Partnership determines its estimated fair value of the Partnership’s financial instruments, which include current assets and liabilities, based upon its assessment of available market information and valuation methodologies. The Partnership has categorized the estimated fair values of these instruments approximate their carrying amounts due to their short-term nature as Level 1. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Asset Retirement Obligations The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments discussed in Note 5. The MGP made no adjustments to retirement obligations for the years ended December 31, 2017 and 2016 and would define them, if applicable, as Level 3 fair value measurements. For additional information see Note 4. Long-Lived Assets The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or 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. For the years ended December 31, 2017 and 2016 , the Partnership recognized no impairment of long-lived assets, which we would define, if applicable, as Level 3 fair value measurements.

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	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its partnership agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Direct costs, which are included in production and general and administrative expenses in the Partnership's statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $975 per well per month for Marcellus wells for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 16% of the natural gas sales price or $0.35 per Mcf, whichever is greater. The MGP and its affiliates, with administrative support from the Previous MGP under the previously mentioned TSA, perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts Payable Trade-Affiliate on the Partnership’s balance sheet includes the net production expenses due to the MGP. The following table provides information with respect to these costs and the periods incurred: Years Ended December 31, 2017 2016 $ Change % Change Supervision fees $ 140,400 $ 140,400 $ — — % Transportation fees 667,800 463,700 204,100 44 % Direct costs 296,600 233,600 63,000 27 % Total production costs $ 1,104,800 $ 837,700 $ 267,100 32 % Administrative fees $ 10,800 $ 10,800 $ — — % Direct costs 53,100 32,000 21,100 66 % Total general and administrative $ 63,900 $ 42,800 $ 21,100 49 % Subordination by Managing General Partner Under the terms of the partnership agreement, the MGP was required to subordinate up to 50% of its share of net production revenues of the Partnership commencing with the first distribution to the limited partners in March 2011 and expiring in February 2016 ("subordination period"). If, during the subordination period, the limited partners distributions did not meet, or exceed, an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, the MGP will subsidize the limited partners distribution. The MGP subordinated $188,000 during the year ended December 31, 2016 .

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES General Commitments Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation. Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, exercised its right to retain $200 per month per well to cover estimated future plugging and abandonment costs. For additional information see Note 4. Environmental risk is inherent to natural gas operations, and we and our affiliates may be, at times, subject to potential environmental remediation liability. At December 31, 2017 , there were no unresolved environmental matters. For additional information see Note 1. Legal Proceedings From time to time, the Partnership and affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising out of the ordinary course of its business. The MGP believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s or the MGP’s financial condition or results of operations. As of December 31, 2017 , there were no outstanding legal proceedings.

Supplemental Natural Gas Inform

Supplemental Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
SUPPLEMENTAL GAS INFORMATION (UNAUDITED)	SUPPLEMENTAL NATURAL GAS INFORMATION (UNAUDITED) Natural Gas Reserve Information. The MGP's reserve engineers prepared the Partnership’s natural gas reserve estimates in accordance with our MGP’s prescribed internal control procedures. For the periods presented, the MGP retained Wright & Company, Inc., the MGP's independent third-party reserve engineer, to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 41 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist. Our MGP's Vice President of Gas Marketing, who has more than 18 years of natural gas and oil industry experience, oversaw the preparation, review and approval of reserve estimates with final approval by the MGP’s Chief Operating Officer. The reserve disclosures that follow reflect estimates of proved developed reserves of natural gas owned at year end, net of royalty interests. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. 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 and 2016 , including adjustments related to regional price differentials and energy content. Numerous uncertainties are 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 natural gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in natural gas prices and in production and development costs and other factors. Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows: Gas (Mcf) Balance, December 31, 2015 30,206,100 Revisions (1) (2,329,300 ) Production (1,887,300 ) Balance, December 31, 2016 25,989,500 Revisions (2) (952,500 ) Production (1,645,400 ) Balance, December 31, 2017 23,391,600 ___________________________________________________________________________________________________ (1) The downward revision in natural gas forecasts is primarily due to a decrease in SEC base pricing from the prior year, resulting in shorter economic life. (2) The downward revision in natural gas forecasts is primarily due to future production forecast adjustments in our Marcellus field to reflect realized production declines. Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved natural gas reserves using the pricing methodology described above. The resulting estimated future cash inflows were reduced by estimated future costs to 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 properties, with the net result discounted to present value 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: Years Ended December 31, 2017 2016 Future cash inflows $ 57,075,400 $ 30,315,600 Future production costs (28,786,900 ) (14,274,600 ) Future development costs (1) (2,736,000 ) — Future net cash flows 25,552,500 16,041,000 Less 10% annual discount for estimated timing of cash flows (13,149,700 ) (8,536,400 ) Standardized measure of discounted future net cash flows $ 12,402,800 $ 7,504,600 _________________________________________________________________________________________________ (1) Future development costs represent costs to plug and abandon wells at the end of the estimated economic life of a well.

Basis of Presentation and Sum15

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Use of Estimates	Use of Estimates Preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires the MGP 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 the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, impairments, fair value of derivative instruments, and the probability of forecasted transactions. The natural 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.
Receivables	Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2017 and 2016 , the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. Asset retirement receivable-affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnerships wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells.
Natural Gas Properties	Natural Gas Properties Natural gas properties are stated at cost. The Partnership follows the successful efforts method of accounting for natural gas producing activities. The Partnership expenses maintenance and repairs as incurred that generally do not extend the useful life or enhance the productivity of an asset for two years or more through the replacement of critical components. The Partnership capitalizes major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components. For additional information see Note 3. The Partnership’s depletion expense is determined using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with the field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership also considers the estimated salvage value in the calculation of depletion. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Partnership reviews its long-lived assets 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 of that asset to its estimated fair value if such carrying amount exceeds the fair value. The MGP reviews the Partnership’s natural gas properties by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The MGP estimates the expected future cash flows based on the Partnership’s plans to continue to produce and develop proved reserves. The MGP calculates the expected future cash flow from the sale of the production of reserves based on estimated future prices. The Partnership estimates 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, we recognize impairment loss for the difference between the estimated fair market value (as determined by the discounted cash flows) and the carrying value of the assets. Determination of 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. 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. The Partnership cannot predict what reserve revisions may be required in future periods.
Derivative Instruments	Derivative Instruments and Other Comprehensive Loss The Partnership’s Previous MGP entered into certain financial derivative contracts to manage the Partnership’s exposure to changes in commodity prices. The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value were recognized in the Partnership’s statements of operations unless specific hedge accounting criteria were met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges.
Asset Retirement Obligations	Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its natural gas wells and related facilities (For additional information see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made.
Income Taxes	Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012.
Environmental Matters	Environmental Matters The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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.
Revenue Recognition	Revenue Recognition The Partnership sells natural gas at prevailing market prices. The Partnership’s 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. The market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The Partnership recognizes revenues from the production of natural gas in which the Partnership has an interest with other producers on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. At December 31, 2017, the MGP has completed the evaluation of sources of revenue and the impact of this accounting standards update on our results of operations, financial position, cash flows and financial disclosures, in addition to developing and implementing any process or control changes necessary. We do not expect to record a cumulative effect adjustment on date of adoption. The Partnership adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

Basis of Presentation and Sum16

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Reconciliation of the Partnerships Asset Retirement Receivable	The following is a reconciliation of the Partnership’s asset retirement receivable-affiliate for the years indicated: 2017 2016 Asset retirement receivable – affiliate, beginning of year $ 24,800 $ 15,200 Asset retirement estimates withheld 22,400 9,600 Asset retirement receivable –affiliate, end of year $ 47,200 $ 24,800
Schedule of Revenue by Major Customers	For the years ended December 31, 2017 and 2016 , the Partnership had the following customers that individually accounted for greater than 10% of the Partnership's natural gas revenues. Percentage of Revenue Customer 2017 2016 Direct Energy Business LLC 100 % — % Hess Energy Marketing LLC — % 56 % Chevron Natural — % 44 % Total 100 % 100 %

Participation in Revenues and17

Participation in Revenues and Costs (Working Interest) (Tables)	12 Months Ended
	Dec. 31, 2017
Partners' Capital Notes [Abstract]
Schedule of Participation in Revenues and Costs, Allocation	The MGP and the limited partners generally participated in revenues and costs in the following manner: Managing General Partner Limited Partners Organization and offering cost 100% —% Lease costs 100% —% Intangible drilling costs 8% 92% Tangible equipment costs 52% 48% Revenues (1) 37% 63% Operating costs, administrative costs, direct and all other costs (2) 37% 63% ___________________________________________________________________________________________________ (1) All partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues which is reflected in the rate presented. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Summary of Natural Gas Properties	The following is a summary of proved natural gas properties at the dates indicated: December 31, 2017 2016 Leasehold interests $ 540,100 $ 540,100 Wells and related equipment 90,300,700 90,300,700 Total natural gas properties 90,840,800 90,840,800 Accumulated depletion and impairment (72,249,500 ) (71,004,300 ) Natural gas properties, net $ 18,591,300 $ 19,836,500

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table reconciles the Partnership’s asset retirement obligation liability for well plugging and abandonment costs: Years Ended December 31, 2017 2016 Asset retirement liability, beginning of year $ 1,698,100 $ 1,602,400 Accretion expense 101,400 95,700 Asst retirement liability, end of year $ 1,799,500 $ 1,698,100

Certain Relationships and Rel20

Certain Relationships and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	The following table provides information with respect to these costs and the periods incurred: Years Ended December 31, 2017 2016 $ Change % Change Supervision fees $ 140,400 $ 140,400 $ — — % Transportation fees 667,800 463,700 204,100 44 % Direct costs 296,600 233,600 63,000 27 % Total production costs $ 1,104,800 $ 837,700 $ 267,100 32 % Administrative fees $ 10,800 $ 10,800 $ — — % Direct costs 53,100 32,000 21,100 66 % Total general and administrative $ 63,900 $ 42,800 $ 21,100 49 %

Supplemental Natural Gas Info21

Supplemental Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Changes in Proved Reserve Quantities	Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows: Gas (Mcf) Balance, December 31, 2015 30,206,100 Revisions (1) (2,329,300 ) Production (1,887,300 ) Balance, December 31, 2016 25,989,500 Revisions (2) (952,500 ) Production (1,645,400 ) Balance, December 31, 2017 23,391,600 ___________________________________________________________________________________________________ (1) The downward revision in natural gas forecasts is primarily due to a decrease in SEC base pricing from the prior year, resulting in shorter economic life. (2) The downward revision in natural gas forecasts is primarily due to future production forecast adjustments in our Marcellus field to reflect realized production declines.
Standardized Measure of Discounted Future Cash Flows	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: Years Ended December 31, 2017 2016 Future cash inflows $ 57,075,400 $ 30,315,600 Future production costs (28,786,900 ) (14,274,600 ) Future development costs (1) (2,736,000 ) — Future net cash flows 25,552,500 16,041,000 Less 10% annual discount for estimated timing of cash flows (13,149,700 ) (8,536,400 ) Standardized measure of discounted future net cash flows $ 12,402,800 $ 7,504,600 _________________________________________________________________________________________________ (1) Future development costs represent costs to plug and abandon wells at the end of the estimated economic life of a well.

Basis of Presentation and Sum22

Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for uncollectible accounts receivable	$ 0	$ 0
Other comprehensive loss		0
Loss on mark-to-market derivatives	0	20,100
Federal or state deferred tax	0
Unbilled revenues	$ 561,600	$ 573,900

Basis of Presentation and Sum23

Basis of Presentation and Summary of Significant Accounting Policies (Schedule of Major Customers) (Details) - Customer Concentration Risk - Sales Revenues	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, percentage	100.00%	100.00%
Direct Energy Business LLC
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, percentage	100.00%	0.00%
Hess Energy Marketing LLC
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, percentage	0.00%	56.00%
Chevron Natural
Summary Of Significant Accounting Policies [Line Items]
Concentration risk, percentage	0.00%	44.00%

Basis of Presentation and Sum24

Basis of Presentation and Summary of Significant Accounting Policies (Reconciliation of the Partnerships Asset Retirement Receivable) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Receivable [Roll Forward]
Asset retirement receivable – affiliate, beginning of year	$ 24,800	$ 15,200
Asset retirement estimates withheld	22,400	9,600
Asset retirement receivable –affiliate, end of year	$ 47,200	$ 24,800

Participation in Revenues and25

Participation in Revenues and Costs (Working Interest) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, percentage	10.00%

Participation in Revenues and26

Participation in Revenues and Costs (Working Interest) (Schedule of Participation in Revenues and Costs, Allocation) (Details)	12 Months Ended
	Dec. 31, 2017
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, percentage	10.00%
Organization and offering cost | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	100.00%
Organization and offering cost | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	0.00%
Lease costs | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	100.00%
Lease costs | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	0.00%
Intangible drilling costs | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	8.00%
Intangible drilling costs | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	92.00%
Tangible equipment costs | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	52.00%
Tangible equipment costs | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	48.00%
Revenues | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	37.00%
Revenues | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	63.00%
Operating costs, administrative costs, direct and all other costs | Managing General Partner
Capital Unit [Line Items]
Participation in revenues and costs, percentage	37.00%
Operating costs, administrative costs, direct and all other costs | Limited Partners
Capital Unit [Line Items]
Participation in revenues and costs, percentage	63.00%

Property, Plant and Equipment27

Property, Plant and Equipment (Summary of Natural Gas Properties) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Proved properties:
Total natural gas and oil properties	$ 90,840,800	$ 90,840,800
Accumulated depletion and impairment	(72,249,500)	(71,004,300)
Natural gas properties, net	18,591,300	19,836,500
Leasehold interests
Proved properties:
Total natural gas and oil properties	540,100	540,100
Wells and related equipment
Proved properties:
Total natural gas and oil properties	$ 90,300,700	$ 90,300,700

Property, Plant and Equipment28

Property, Plant and Equipment (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Depletion of natural gas properties	$ 1,245,200	$ 1,327,900

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 47,200	$ 24,800

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Beginning of year	$ 1,698,100	$ 1,602,400
Accretion expense	101,400	95,700
End of year	$ 1,799,500	$ 1,698,100

Fair Value of Financial Instr31

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment	$ 0	$ 0
Asset Retirement Obligation Costs
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Adjustments to retirement obligations	$ 0	$ 0

Certain Relationships and Rel32

Certain Relationships and Related Party Transactions (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017USD ($)$ / mo	Dec. 31, 2016USD ($)
Related Party Transaction [Line Items]
Managing general partner maximum subordination percentage of share of net production revenues	50.00%
Subordination		$ 0
MGP
Related Party Transaction [Line Items]
Subordination target return rate for limited partner subscriptions	12.00%
Subordination target return rate for limited partner subscriptions for second, third and fourth twelve month period	10.00%
Subordination target return rate for limited partner subscriptions for last twelve month period	8.00%
Subordination		$ (188,000)
MGP and Affiliates | General and administrative expenses
Related Party Transaction [Line Items]
Monthly administrative costs per well | $ / mo	75
MGP and Affiliates | Production
Related Party Transaction [Line Items]
Transportation fee rate as percentage of natural gas sales price	16.00%
Transportation fees (USD per Mcf)	$ 0.35
MGP and Affiliates | Production | Marcellus wells
Related Party Transaction [Line Items]
Monthly supervision fees per well | $ / mo	975

Certain Relationships and Rel33

Certain Relationships and Related Party Transactions (Schedule of Transactions) (Details) - MGP and Affiliates - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Production costs, amount	$ 1,104,800	$ 837,700
Production costs, $ change	$ 267,100
Production costs, % change	32.00%
General and administrative costs, amount	$ 63,900	42,800
General and administrative costs, $ change	$ 21,100
General and administrative costs, % change	49.00%
Supervision fees
Related Party Transaction [Line Items]
Production costs, amount	$ 140,400	140,400
Production costs, $ change	$ 0
Production costs, % change	0.00%
Transportation fees
Related Party Transaction [Line Items]
Production costs, amount	$ 667,800	463,700
Production costs, $ change	$ 204,100
Production costs, % change	44.00%
Administrative fees
Related Party Transaction [Line Items]
General and administrative costs, amount	$ 10,800	10,800
General and administrative costs, $ change	$ 0
General and administrative costs, % change	0.00%
Direct costs
Related Party Transaction [Line Items]
Production costs, amount	$ 296,600	233,600
Production costs, $ change	$ 63,000
Production costs, % change	27.00%
General and administrative costs, amount	$ 53,100	$ 32,000
General and administrative costs, $ change	$ 21,100
General and administrative costs, % change	66.00%

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017$ / mo
Commitments and Contingencies Disclosure [Abstract]
Operator fee per well to cover estimated future plugging and abandonment costs, monthly	200

Supplemental Natural Gas Info35

Supplemental Natural Gas Information (Unaudited) (Changes in Proved Reserve Quantities) (Details) - Gas (Mcf) - Mcf	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Proved Developed and Undeveloped Reserves [Roll Forward]
Balance	25,989,500	30,206,100
Revisions	(952,500)	(2,329,300)
Production	(1,645,400)	(1,887,300)
Balance	23,391,600	25,989,500

Supplemental Natural Gas Info36

Supplemental Natural Gas Information (Unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017
Natural Gas Producing Activities [Abstract]
Present value of discount factor	10.00%

Supplemental Natural Gas Info37

Supplemental Natural Gas Information (Unaudited) (Standardized Measure of Discounted Future Cash Flows) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Natural Gas Producing Activities [Abstract]
Future cash inflows	$ 57,075,400	$ 30,315,600
Future production costs	(28,786,900)	(14,274,600)
Future development costs(1)	(2,736,000)	0
Future net cash flows	25,552,500	16,041,000
Less 10% annual discount for estimated timing of cash flows	(13,149,700)	(8,536,400)
Standardized measure of discounted future net cash flows	$ 12,402,800	$ 7,504,600