ATLAS RESOURCES Public #17-2007 10-K 14 Apr 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015USD ($)shares
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Registrant Name	ATLAS RESOURCES Public #17-2007 (A) L.P.
Entity Central Index Key	1,399,542
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding | shares	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, 2015	Dec. 31, 2014
Current assets:
Cash	$ 0	$ 100
Accounts receivable trade–affiliate	236,400	808,100
Asset retirement receivable-affiliate		104,500
Current portion of derivative assets	106,800	54,200
Total current assets	343,200	966,900
Gas and oil properties, net	4,533,300	7,378,100
Long-term asset retirement receivable-affiliate	189,400
Long-term derivative assets		45,400
Total assets	5,065,900	8,390,400
Current liabilities:
Accounts payable trade-affiliate	103,100
Accrued liabilities	35,100	18,100
Current portion of put premiums payable-affiliate	49,300	34,800
Total current liabilities	187,500	52,900
Asset retirement obligations	7,772,800	7,352,800
Long-term put premiums payable-affiliate	$ 0	$ 39,800
Commitments and contingencies (Note 9)
Partners’ (deficit) capital:
Managing general partner’s (deficit) interest	$ (961,800)	$ 225,000
Limited partners’ (deficit) interest (16,345.90 units)	(1,938,200)	694,900
Accumulated other comprehensive income	5,600	25,000
Total partners’ (deficit) capital	(2,894,400)	944,900
Total liabilities and partners’ (deficit) capital	$ 5,065,900	$ 8,390,400

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical)	Dec. 31, 2015shares
Statement Of Financial Position [Abstract]
Limited partners' units	16,345.90

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
REVENUES
Natural gas and oil	$ 2,074,100	$ 5,550,700
Gain on mark-to-market derivatives	71,500
Total revenues	2,145,600	5,550,700
COSTS AND EXPENSES
Production	2,019,700	2,802,300
Depletion	407,100	1,337,300
Impairment	2,437,500	7,099,600
Accretion of asset retirement obligations	420,500	312,100
General and administrative	278,300	306,800
Total costs and expenses	5,563,100	11,858,100
Net loss	(3,417,500)	(6,307,400)
Allocation of net loss:
Managing general partner	(1,050,600)	(1,862,000)
Limited partners	$ (2,366,900)	$ (4,445,400)
Net loss per limited partnership unit	$ (145)	$ (272)

STATEMENTS OF COMPREHENSIVE LOS

STATEMENTS OF COMPREHENSIVE LOSS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (3,417,500)	$ (6,307,400)
Other comprehensive (loss) income:
Mark-to-market gains on cash flow hedging contracts		25,000
Difference in estimated hedge gains receivable	(5,600)	87,400
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges	(13,800)	(56,400)
Total other comprehensive (loss) income	(19,400)	56,000
Comprehensive loss	$ (3,436,900)	$ (6,251,400)

STATEMENTS OF CHANGES IN PARTNE

STATEMENTS OF CHANGES IN PARTNERS' DEFICIT - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2013	$ 10,176,200	$ 3,037,200	$ 7,170,000	$ (31,000)
Participation in revenues and costs and expenses:
Net production revenues	2,748,400	919,500	1,828,900
Depletion	(1,337,300)	(368,800)	(968,500)
Impairment	(7,099,600)	(2,206,300)	(4,893,300)
Accretion of asset retirement obligations	(312,100)	(104,100)	(208,000)
General and administrative	(306,800)	(102,300)	(204,500)
Net loss	(6,307,400)	(1,862,000)	(4,445,400)
Other comprehensive income (loss)	56,000			56,000
Distributions to partners	(2,979,900)	(950,200)	(2,029,700)
Ending balance at Dec. 31, 2014	944,900	225,000	694,900	25,000
Participation in revenues and costs and expenses:
Net production revenues	54,400	13,300	41,100
Gain on mark-to-market derivatives	71,500		71,500
Depletion	(407,100)	(92,700)	(314,400)
Impairment	(2,437,500)	(738,000)	(1,699,500)
Accretion of asset retirement obligations	(420,500)	(140,300)	(280,200)
General and administrative	(278,300)	(92,900)	(185,400)
Net loss	(3,417,500)	(1,050,600)	(2,366,900)
Other comprehensive income (loss)	(19,400)			(19,400)
Distributions to partners	(402,400)	(136,200)	(266,200)
Ending balance at Dec. 31, 2015	$ (2,894,400)	$ (961,800)	$ (1,938,200)	$ 5,600

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net loss	$ (3,417,500)	$ (6,307,400)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	407,100	1,337,300
Impairment	2,437,500	7,099,600
Non-cash (gain) loss on derivative value	(51,900)	70,200
Accretion of asset retirement obligations	420,500	312,100
Asset retirement obligation settled	(500)	(30,400)
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate	571,700	324,000
Increase in asset retirement receivable-affiliate	(84,900)	(104,500)
Increase in accounts payable trade-affiliate	103,100
Increase in accrued liabilities	17,000	400
Net cash provided by operating activities	402,100	2,701,300
Cash flows from investing activities:
Purchase of tangible equipment		(2,500)
Proceeds from sale of tangible equipment	200	36,400
Net cash provided by investing activities	200	33,900
Cash flows from financing activities:
Distributions to partners	(402,400)	(2,979,900)
Net cash used in financing activities	(402,400)	(2,979,900)
Net change in cash	(100)	(244,700)
Cash at beginning of year	100	244,800
Cash at end of year	$ 0	100
Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligations revisions		$ 1,814,100

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
BASIS OF PRESENTATION	NOTE 1—BASIS OF PRESENTATION Atlas Resources Public #17-2007 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 7, 2007 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest. The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and West Virginia. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling. The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues. The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically. Liquidity and Capital Resources The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations. Historically, there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations and distributions to the partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern. If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of the Partnership’s 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 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, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. 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 (see “ Revenue Recognition 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, 2015 and 2014, 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 Partnership’s 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. The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the periods indicated: December 31, 2015 2014 Asset retirement receivable – affiliate, beginning of year $ 104,500 $ - Asset retirement estimates withheld 85,400 104,500 Plugging and abandonment costs incurred (500 ) - Asset retirement receivable –affiliate, end of year $ 189,400 $ 104,500 Gas and oil Properties Gas and oil properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, 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 cost of developed producing properties. 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 (see Note 4). The review of the Partnership’s gas and oil properties is done on a field-by-field basis 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 expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated 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, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. Derivative Instruments The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). 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 are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are 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, 2014 of these derivatives are recognized immediately within gain (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, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings. Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (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. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion. 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. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2015 and 2014. 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 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015. 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, 2015 and 2014. Concentration of Credit Risk The Partnership sells natural gas and crude oil under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had two customers that individually accounted for approximately 55% and 33% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had two customers that individually accounted for approximately 62% and 26% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. Revenue Recognition The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, 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. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized 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 crude oil and condensate, 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 (See “- Use of Estimates Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss). Recently Issued Accounting Standards In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements and its method of adoption.

Participation in Revenues and C

Participation in Revenues and Costs	12 Months Ended
	Dec. 31, 2015
Partners Capital Notes [Abstract]
PARTICIPATION IN REVENUES AND COSTS	NOTE 3—PARTICIPATION IN REVENUES AND COSTS Working Interest The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. The MGP and the limited partners generally participated in revenues and costs in the following manner: Managing Limited Organization and offering costs 100% 0% Lease costs 100% 0% Intangible drilling costs 5% 95% Tangible equipment costs 70% 30% Revenues (1) 33% 67% Operating costs, administrative costs, direct and all other costs (2) 33% 67% (1) Subject to the MGP’s subordination obligation, substantially 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 7% of the partnership revenues. (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, 2015
Property Plant And Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	NOTE 4 — The following is a summary of natural gas and oil properties at the dates indicated: December 31, 2015 2014 Proved properties: Leasehold interests $ 3,843,500 $ 3,854,800 Wells and related equipment 203,136,000 203,537,700 Total natural gas and oil properties 206,979,500 207,392,500 Accumulated depletion and impairment (202,446,200 ) (200,014,400 ) Gas and oil properties, net $ 4,533,300 $ 7,378,100 The Partnership recorded depletion expense on natural gas and oil properties of $407,100 and $1,337,300 for the years ended December 31, 2015 and 2014, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. As a result of retirements, the Partnership reclassified $412,800 from gas and oil properties to accumulated depletion for the year ended December 31, 2015. During the year ended December 31, 2015, the Partnership recognized $2,437,500, of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2015. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. During the year ended December 31, 2014, the Partnership recognized $7,099,600 of impairment related to gas and oil properties on its balance sheet. As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on our MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 5—ASSET RETIREMENT OBLIGATIONS The estimated liability for asset retirement obligations was 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 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. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets. The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of December 31, 2015, the MGP withheld $189,400 of net production revenue for future plugging and abandonment costs. A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows: Years Ended December 31, 2015 2014 Beginning of year $ 7,352,800 $ 5,257,000 Accretion expense 420,500 312,100 Revision - 1,814,100 Settlements (500 ) (30,400 ) End of year $ 7,772,800 $ 7,352,800

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	NOTE 6—DERIVATIVE INSTRUMENTS The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put options, in connection with the Partnership’s commodity price risk management activities. Management uses financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $106,800 and $99,600 at December 31, 2015 and 2014, respectively. At December 31, 2015, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Volumes (1) Average (1) Fair Value (2) 2016 64,300 $ 4.15 $ 106,800 $ 106,800 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable. The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Years Ended 2015 2014 Gains reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues $ 16,600 $ 56,400 Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ 71,500 $ - Put Premiums Payable During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2015 and 2014, the put premiums were recorded as short-term payables to affiliate $49,300 and $34,800, respectively, and long-term payables to affiliate of $0 and $39,800, respectively.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 7—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 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 The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts 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. The fair values of these derivative instruments are 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 the pricing formula utilized in the derivative instrument. Information for assets and liabilities measured at fair value was as follows: As of December 31, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity puts $ - $ 106,800 $ - $ 106,800 As of December 31, 2014 Derivative assets, gross Commodity puts $ - $ 99,600 $ - $ 99,600 Other Financial Instruments The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale of such financial instruments. The Partnership’s other current assets and liabilities on its 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 The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5). There were no adjustments to retirement obligations for the year ended December 31, 2015. Adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis was $1,814,100 for the year ended December 31, 2014. 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, 2015 and 2014, the Partnership recognized $2,437,500 and $7,099,600, respectively, of impairment of long-lived assets which were defined as Level 3 fair value measurements (See Note 4: Property, Plant, and Equipment).

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	NOTE 8—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. Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $377 per well per month 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 13% of the natural gas sales price. Direct costs, which are included in production and general 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. The following table provides information with respect to these costs and the periods incurred: Years Ended December 31, 2015 2014 Administrative fees $ 214,400 $ 242,700 Supervision fees 1,077,600 1,220,100 Transportation fees 297,200 638,100 Direct costs 708,800 1,008,200 Total $ 2,298,000 $ 3,109,100 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 9—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. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. 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, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2015 and 2014, the MGP withheld $189,400 and $104,500, respectively, of net production revenue for future plugging and abandonment costs. Legal Proceedings The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations. Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 10—SUBSEQUENT EVENTS Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Supplemental Gas and Oil Inform

Supplemental Gas and Oil Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)	NOTE 11—SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED) Gas and oil Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas Resources Public #17-2007 (A) L.P. annual Form 10-K for the years ended December 31, 2015 and 2014 (See Note 2). For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 39 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, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 17 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s Senior Engineering Staff and management, with final approval by the MGP’s President. The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves 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. The proved reserves quantities and future net cash flows as of December 31, 2015 and 2014 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, 2015 and 2014, 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 gas and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil 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 included within the Partnership are as follows: Gas (Mcf) Oil (Bbls) Balance, December 31, 2013 9,423,300 37,700 Revisions (1) 168,900 3,100 Production (1,260,000 ) (8,900 ) Balance, December 31, 2014 8,332,200 31,900 Revisions (2) (3,227,200 ) 10,500 Production (1,046,500 ) (5,400 ) Balance, December 31, 2015 (3) 4,058,500 37,000 (1) The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year resulting in longer economic life. The upward revision in oil forecasting is primarily due to forecast adjustments in order to better reflect actual production. (2) 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; the upward revision in oil forecasts is primarily due to forecast adjustments in order to reflect actual production. (3) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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 Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows: Years Ended December 31, 2015 2014 Natural gas and oil properties: Leasehold interest $ 3,843,500 $ 3,854,800 Wells and related equipment 203,136,000 203,537,700 Accumulated depletion, accretion and impairment (202,446,200 ) (200,014,400 ) Net capitalized costs $ 4,533,300 $ 7,378,100 Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows: Years Ended December 31, 2015 2014 Revenues $ 2,074,100 $ 5,550,700 Production costs (2,019,700 ) (2,802,300 ) Depletion (407,100 ) (1,337,300 ) Impairment (2,437,500 ) (7,099,600 ) $ (2,790,200 ) $ (5,688,500 ) 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 gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015 and 2014, adjusted only for regional price differentials and energy content. 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 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: Years Ended December 31, 2015 (1) 2014 Future cash inflows $ 9,484,200 $ 32,256,500 Future production costs (6,081,300 ) (20,535,600 ) Future net cash flows 3,402,900 11,720,900 Less 10% annual discount for estimated timing of cash flows (1,155,300 ) (4,116,700 ) Standardized measure of discounted future net cash flows $ 2,247,600 $ 7,604,200 (1) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Liquidity and Capital Resources	Liquidity and Capital Resources The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners. The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations. Historically, there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations and distributions to the partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern. If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.
Use of Estimates	Use of Estimates The preparation of the Partnership’s 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 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, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. 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 (see “ Revenue Recognition
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, 2015 and 2014, 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 Partnership’s 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. The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the periods indicated: December 31, 2015 2014 Asset retirement receivable – affiliate, beginning of year $ 104,500 $ - Asset retirement estimates withheld 85,400 104,500 Plugging and abandonment costs incurred (500 ) - Asset retirement receivable –affiliate, end of year $ 189,400 $ 104,500
Gas and Oil Properties	Gas and oil Properties Gas and oil properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, 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 cost of developed producing properties. 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 (see Note 4). The review of the Partnership’s gas and oil properties is done on a field-by-field basis 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 expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated 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, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
Derivative Instruments	Derivative Instruments The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). 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 are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are 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, 2014 of these derivatives are recognized immediately within gain (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, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.
Asset Retirement Obligations	Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (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. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
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. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2015 and 2014. 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 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015.
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. 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, 2015 and 2014.
Concentration of Credit Risk	Concentration of Credit Risk The Partnership sells natural gas and crude oil under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had two customers that individually accounted for approximately 55% and 33% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had two customers that individually accounted for approximately 62% and 26% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity.
Revenue Recognition	Revenue Recognition The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, 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. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized 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 crude oil and condensate, 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 (See “- Use of Estimates
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).
Recently Issued Accounting Standards	Recently Issued Accounting Standards In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements and its method of adoption.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Reconciliation of Partnership's Asset Retirement Receivable Affiliate	The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the periods indicated: December 31, 2015 2014 Asset retirement receivable – affiliate, beginning of year $ 104,500 $ - Asset retirement estimates withheld 85,400 104,500 Plugging and abandonment costs incurred (500 ) - Asset retirement receivable –affiliate, end of year $ 189,400 $ 104,500

Participation in Revenues and21

Participation in Revenues and Costs (Tables)	12 Months Ended
	Dec. 31, 2015
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 Limited Organization and offering costs 100% 0% Lease costs 100% 0% Intangible drilling costs 5% 95% Tangible equipment costs 70% 30% Revenues (1) 33% 67% Operating costs, administrative costs, direct and all other costs (2) 33% 67% (1) Subject to the MGP’s subordination obligation, substantially 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 7% of the partnership revenues. (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, 2015
Property Plant And Equipment [Abstract]
Summary of Natural Gas and Oil Properties	The following is a summary of natural gas and oil properties at the dates indicated: December 31, 2015 2014 Proved properties: Leasehold interests $ 3,843,500 $ 3,854,800 Wells and related equipment 203,136,000 203,537,700 Total natural gas and oil properties 206,979,500 207,392,500 Accumulated depletion and impairment (202,446,200 ) (200,014,400 ) Gas and oil properties, net $ 4,533,300 $ 7,378,100

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligation	A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows: Years Ended December 31, 2015 2014 Beginning of year $ 7,352,800 $ 5,257,000 Accretion expense 420,500 312,100 Revision - 1,814,100 Settlements (500 ) (30,400 ) End of year $ 7,772,800 $ 7,352,800

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity Derivatives	At December 31, 2015, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Volumes (1) Average (1) Fair Value (2) 2016 64,300 $ 4.15 $ 106,800 $ 106,800 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable.
Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges	The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Years Ended 2015 2014 Gains reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues $ 16,600 $ 56,400 Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ 71,500 $ -

Fair Value of Financial Instr25

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on a Recurring Basis	Information for assets and liabilities measured at fair value was as follows: As of December 31, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity puts $ - $ 106,800 $ - $ 106,800 As of December 31, 2014 Derivative assets, gross Commodity puts $ - $ 99,600 $ - $ 99,600

Certain Relationships and Rel26

Certain Relationships and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 Administrative fees $ 214,400 $ 242,700 Supervision fees 1,077,600 1,220,100 Transportation fees 297,200 638,100 Direct costs 708,800 1,008,200 Total $ 2,298,000 $ 3,109,100

Supplemental Gas and Oil Info27

Supplemental Gas and Oil Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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) Oil (Bbls) Balance, December 31, 2013 9,423,300 37,700 Revisions (1) 168,900 3,100 Production (1,260,000 ) (8,900 ) Balance, December 31, 2014 8,332,200 31,900 Revisions (2) (3,227,200 ) 10,500 Production (1,046,500 ) (5,400 ) Balance, December 31, 2015 (3) 4,058,500 37,000 (1) The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year resulting in longer economic life. The upward revision in oil forecasting is primarily due to forecast adjustments in order to better reflect actual production. (2) 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; the upward revision in oil forecasts is primarily due to forecast adjustments in order to reflect actual production. (3) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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
Capitalized Costs Relating to Gas and Oil Producing Activities	Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows: Years Ended December 31, 2015 2014 Natural gas and oil properties: Leasehold interest $ 3,843,500 $ 3,854,800 Wells and related equipment 203,136,000 203,537,700 Accumulated depletion, accretion and impairment (202,446,200 ) (200,014,400 ) Net capitalized costs $ 4,533,300 $ 7,378,100
Results of Operations for Gas and Oil Producing Activities	Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows: Years Ended December 31, 2015 2014 Revenues $ 2,074,100 $ 5,550,700 Production costs (2,019,700 ) (2,802,300 ) Depletion (407,100 ) (1,337,300 ) Impairment (2,437,500 ) (7,099,600 ) $ (2,790,200 ) $ (5,688,500 )
Standardized Measure of Discounted Future 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 the Partnership’s proved gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015 and 2014, adjusted only for regional price differentials and energy content. 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 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: Years Ended December 31, 2015 (1) 2014 Future cash inflows $ 9,484,200 $ 32,256,500 Future production costs (6,081,300 ) (20,535,600 ) Future net cash flows 3,402,900 11,720,900 Less 10% annual discount for estimated timing of cash flows (1,155,300 ) (4,116,700 ) Standardized measure of discounted future net cash flows $ 2,247,600 $ 7,604,200 (1) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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.

Basis of Presentation (Details)

Basis of Presentation (Details)	Feb. 27, 2015	Dec. 31, 2015
Description Of Business [Line Items]
Atlas Resources Public 17-2007 (A) L.P. Formation Date		May 7, 2007
Atlas Energy Group | Atlas Energy | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders	100.00%

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)Customer	Dec. 31, 2014USD ($)Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for Uncollectible Accounts Receivable	$ 0	$ 0
Number of major customers | Customer	2	2
Unbilled Revenues	$ 236,400	$ 586,700
Customer Concentration Risk | Customer1 | Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	55.00%	62.00%
Customer Concentration Risk | Customer2 | Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	33.00%	26.00%

Summary of Significant Accoun30

Summary of Significant Accounting Policies - Summary of Reconciliation of Partnership's Asset Retirement Receivable Affiliate (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Receivable [Abstract]
Asset retirement receivable – affiliate, beginning of year	$ 104,500
Asset retirement estimates withheld	85,400	$ 104,500
Plugging and abandonment costs incurred	(500)
Asset retirement receivable –affiliate, end of year	$ 189,400	$ 104,500

Participation in Revenues and31

Participation in Revenues and Costs (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, Percentage	7.00%

Participation in Revenues and32

Participation in Revenues and Costs (Schedule of Participation in Revenues and Costs, Allocation)(Details)	12 Months Ended
	Dec. 31, 2015
Managing General Partner
Capital Unit [Line Items]
Additional partnership revenues to receive, Percentage	7.00%
Organization And Offering Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	100.00%
Organization And Offering Costs | 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	5.00%
Intangible Drilling Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	95.00%
Tangible Equipment Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	70.00%
Tangible Equipment Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	30.00%
Revenues | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	33.00%	[1]
Revenues | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	67.00%	[1]
Operating Costs, Administrative Costs, Direct And All Other Costs | Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	33.00%	[2]
Operating Costs, Administrative Costs, Direct And All Other Costs | Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	67.00%	[2]
[1]	Subject to the MGP’s subordination obligation, substantially 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 7% of the partnership revenues.
[2]	These costs will be charged to the partners in the same ratio as the related production revenues are credited.

Property, Plant and Equipment33

Property, Plant and Equipment (Summary of Natural Gas and Oil Properties) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 206,979,500	$ 207,392,500
Accumulated depletion and impairment	(202,446,200)	(200,014,400)
Gas and oil properties, net	4,533,300	7,378,100
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	3,843,500	3,854,800
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 203,136,000	$ 203,537,700

Property, Plant and Equipment34

Property, Plant and Equipment (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Depletion of natural gas and oil properties	$ 407,100	$ 1,337,300
Reclassification from gas and oil properties to accumulated depletion due to asset retirements	412,800
Impairment	$ 2,437,500	$ 7,099,600

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 189,400	$ 104,500

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligation) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Beginning of year	$ 7,352,800	$ 5,257,000
Accretion expense	420,500	312,100
Revision		1,814,100
Settlements	(500)	(30,400)
End of year	$ 7,772,800	$ 7,352,800

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net derivative assets	$ 106,800	$ 99,600
Current portion of put premiums payable-affiliate	49,300	34,800
Long-term put premiums payable-affiliate	$ 0	$ 39,800

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivatives) (Details)		12 Months Ended
		Dec. 31, 2015USD ($)MMBTU$ / MMBTU	Dec. 31, 2014USD ($)
Derivative [Line Items]
Fair Value Asset		$ 106,800	$ 99,600
Natural Gas Put Options
Derivative [Line Items]
Fair Value Asset	[1]	$ 106,800
Natural Gas Put Options | Production Period Ending December 31, 2016
Derivative [Line Items]
Volumes(MMBtu) | MMBTU	[2]	64,300
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[1]	$ 106,800
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	“MMBtu” represents million British Thermal Units.

Derivative Instruments (Summary

Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues	$ 16,600	$ 56,400
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$ 71,500

Fair Value of Financial Instr40

Fair Value of Financial Instruments (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - Commodity Puts - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 106,800	$ 99,600
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 106,800	$ 99,600

Fair Value of Financial Instr41

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	$ 2,437,500	$ 7,099,600
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	2,437,500	7,099,600
Asset Retirement Obligation
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Adjustments to retirement obligations	$ 0
Asset Retirement Obligation | Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Adjustments to retirement obligations		$ 1,814,100

Certain Relationships and Rel42

Certain Relationships and Related Party Transactions (Narrative) (Details) - MGP and Affiliates	12 Months Ended
	Dec. 31, 2015$ / mo
Administrative costs
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Supervision fees
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	377
Transportation fees
Related Party Transaction [Line Items]
Transportation Fees Rate As Percentage Of Natural Gas Sales Price	13.00%

Certain Relationships and Rel43

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 2,298,000	$ 3,109,100
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	214,400	242,700
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	1,077,600	1,220,100
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	297,200	638,100
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 708,800	$ 1,008,200

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)$ / mo	Dec. 31, 2014USD ($)
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly | $ / mo	200
Net production revenue for future plugging and abandonment costs | $	$ 189,400	$ 104,500

Supplemental Gas and Oil Info45

Supplemental Gas and Oil Information (Unaudited) (Changes In Proved Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2015Mcfbbl		Dec. 31, 2014Mcfbbl
Gas (Mcf)
Reserve Quantities [Line Items]
Balance | Mcf	8,332,200		9,423,300
Revisions | Mcf	(3,227,200)	[1]	168,900	[2]
Production | Mcf	(1,046,500)		(1,260,000)
Balance | Mcf	4,058,500	[3]	8,332,200
Oil (Bbls)
Reserve Quantities [Line Items]
Balance | bbl	31,900		37,700
Revisions | bbl	10,500	[1]	3,100	[2]
Production | bbl	(5,400)		(8,900)
Balance | bbl	37,000	[3]	31,900
[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; the upward revision in oil forecasts is primarily due to forecast adjustments in order to reflect actual production.
[2]	The upward revision in natural gas forecasts is primarily due to an increase in SEC base pricing from the prior year resulting in longer economic life. The upward revision in oil forecasting is primarily due to forecast adjustments in order to better reflect actual production.
[3]	We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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

Supplemental Gas and Oil Info46

Supplemental Gas and Oil Information (Unaudited) (Capitalized Costs Relating to Gas and Oil Producing Activities) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Natural Gas and Oil Producing Activities [Abstract]
Natural gas and oil properties: Leasehold interest	$ 3,843,500	$ 3,854,800
Natural gas and oil properties: Wells and related equipment	203,136,000	203,537,700
Accumulated depletion, accretion and impairment	(202,446,200)	(200,014,400)
Net capitalized costs	$ 4,533,300	$ 7,378,100

Supplemental Gas and Oil Info47

Supplemental Gas and Oil Information (Unaudited) (Results of Operations for Gas and Oil Producing Activities) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Natural Gas and Oil Producing Activities [Abstract]
Revenues	$ 2,074,100	$ 5,550,700
Production costs	(2,019,700)	(2,802,300)
Depletion	(407,100)	(1,337,300)
Impairment	(2,437,500)	(7,099,600)
Total Results of Operations from Gas and Oil Producing Activities	$ (2,790,200)	$ (5,688,500)

Supplemental Gas and Oil Info48

Supplemental Gas and Oil Information (Unaudited) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Natural Gas and Oil Producing Activities [Abstract]
Present value of discount factor	10.00%

Supplemental Gas and Oil Info49

Supplemental Gas and Oil Information (Unaudited) (Standardized Measure of Discounted Future Cash Flows) (Details) - USD ($)	Dec. 31, 2015	[1]	Dec. 31, 2014
Natural Gas and Oil Producing Activities [Abstract]
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves, Future Cash Inflows	$ 9,484,200		$ 32,256,500
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves, Future Production Costs	(6,081,300)		(20,535,600)
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves, Future Net Cash Flows, Total	3,402,900		11,720,900
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	(1,155,300)		(4,116,700)
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves, Standardized Measure, Total	$ 2,247,600		$ 7,604,200
[1]	We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. 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.