ATLAS AMERICA Public #9 Inactive 10-K17 Apr 172016 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information	12 Months Ended
Document and Entity Information	Dec. 31, 2016USD ($)shares
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Entity Registrant Name	ATLAS AMERICA PUBLIC #9 LTD.
Entity Central Index Key	1,121,745
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, 2016	Dec. 31, 2015
Current assets:
Cash	$ 0	$ 0
Accounts receivable trade–affiliate	41,700	29,600
Current portion of derivative assets	0	13,400
Total current assets	41,700	43,000
Gas and oil properties, net	338,500	537,000
Long-term asset retirement receivable-affiliate	382,500	188,100
Total assets	762,700	768,100
Current liabilities:
Accounts payable trade-affiliate	718,100	302,300
Accrued liabilities	11,600	10,300
Current portion put premiums payable-affiliate	0	6,200
Total current liabilities	729,700	318,800
Asset retirement obligations	1,948,300	1,879,800
Commitments and contingencies (Note 9)
Partners’ (deficit) capital:
Managing general partner’s deficit	(480,800)	(181,000)
Limited partners’ deficit (1,500 units)	(1,434,500)	(1,250,200)
Accumulated other comprehensive income		700
Total partners’ deficit	(1,915,300)	(1,430,500)
Total liabilities and partners’ deficit	$ 762,700	$ 768,100

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical)	Dec. 31, 2016shares
Statement Of Financial Position [Abstract]
Limited partners' units	1,500

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
STATEMENTS OF OPERATIONS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Natural gas and oil	$ 216,400	$ 264,800
(Loss) gain on mark-to-market derivatives	(100)	8,500
Total revenues	216,300	273,300
COSTS AND EXPENSES
Production	328,500	346,100
Depletion	36,400	27,600
Impairment	162,100	457,200
Accretion of asset retirement obligations	68,500	101,700
General and administrative	104,900	106,800
Total costs and expenses	700,400	1,039,400
Net loss	(484,100)	(766,100)
Allocation of net loss:
Managing general partner	(299,800)	(302,700)
Limited partners	$ (184,300)	$ (463,400)
Net loss per limited partnership unit	$ (123)	$ (309)

STATEMENTS OF COMPREHENSIVE LOS

STATEMENTS OF COMPREHENSIVE LOSS - USD ($)	12 Months Ended
STATEMENTS OF COMPREHENSIVE LOSS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (484,100)	$ (766,100)
Other comprehensive loss:
Difference in estimated hedge gains receivable		(600)
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges	(700)	(1,900)
Total other comprehensive loss	(700)	(2,500)
Comprehensive loss	$ (484,800)	$ (768,600)

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, 2014	$ (661,900)	$ 121,700	$ (786,800)	$ 3,200
Participation in revenues and costs and expenses:
Net production expenses	(81,300)	(29,600)	(51,700)
(Loss) gain on mark-to-market derivatives	8,500		8,500
Depletion	(27,600)	(11,300)	(16,300)
Impairment	(457,200)	(187,800)	(269,400)
Accretion of asset retirement obligations	(101,700)	(36,100)	(65,600)
General and administrative	(106,800)	(37,900)	(68,900)
Net loss	(766,100)	(302,700)	(463,400)
Other comprehensive loss	(2,500)			(2,500)
Ending balance at Dec. 31, 2015	(1,430,500)	(181,000)	(1,250,200)	700
Participation in revenues and costs and expenses:
Net production expenses	(112,100)	(39,800)	(72,300)
(Loss) gain on mark-to-market derivatives	(100)		(100)
Depletion	(36,400)	(36,400)
Impairment	(162,100)	(162,100)
Accretion of asset retirement obligations	(68,500)	(24,300)	(44,200)
General and administrative	(104,900)	(37,200)	(67,700)
Net loss	(484,100)	(299,800)	(184,300)
Other comprehensive loss	(700)			$ (700)
Ending balance at Dec. 31, 2016	$ (1,915,300)	$ (480,800)	$ (1,434,500)

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss	$ (484,100)	$ (766,100)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion	36,400	27,600
Non-cash loss (gain) on derivative value	6,500	(6,500)
Impairment	162,100	457,200
Accretion of asset retirement obligations	68,500	101,700
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate	(12,100)	61,500
Increase in asset retirement receivable-affiliate	(194,400)	(178,200)
Increase in accounts payable trade-affiliate	415,800	302,300
Increase in accrued liabilities	1,300	300
Net cash provided by (used in) operating activities		(200)
Cash flows from investing activities:
Proceeds from sale of tangible equipment		200
Net cash provided by investing activities		200
Cash flows from financing activities:
Distributions to partners	0	0
Net cash used in financing activities	0	0
Net change in cash	0	0
Cash at beginning of year	0	0
Cash at end of year	$ 0	$ 0

Basis of Presentation

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
BASIS OF PRESENTATION	NOTE 1—BASIS OF PRESENTATION Atlas America Public #9 LTD. (the “Partnership”) is a Pennsylvania limited partnership, formed July 27, 2000 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Titan Energy, LLC (“Titan”). Titan is an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. Titan also sponsors and manages tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”), a Delaware limited partnership organized in 2012. Unless the context otherwise requires, references below to “the Partnership,” “we,” “us,” “our” and “our company”, refer to Atlas America Public #9 LTD. Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) is a publicly traded company and manages Titan and the MGP through a 2% preferred member interest in Titan. The Partnership has drilled and currently operates wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on Atlas Energy Group 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 price for the sale of its 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. ARP Restructuring and Chapter 11 Bankruptcy Proceedings On July 25, 2016, ARP and certain of its subsidiaries, including the MGP, and Atlas Energy Group, solely with respect to certain sections thereof, entered into a restructuring support agreement with ARP’s lenders (the “Restructuring Support Agreement”) to support ARP’s restructuring that reduced debt on its balance sheet (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”). On July 27, 2016, ARP and certain of its subsidiaries, including the MGP, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The cases commenced thereby were being jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.” ARP and the MGP operated the Partnership’s businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired and were satisfied in full in the ordinary course of business, and the MGP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP and the MGP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to the Partnership, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business. The Partnership was not a party to the Restructuring Support Agreement. The ARP Restructuring did not materially impact the MGP’s ability to perform as the managing general partner and operator of the Partnership’s operations. On July 26, 2016, the MGP adopted certain amendments to our partnership agreement, in accordance with the MGP’s ability to amend our partnership agreement to cure an ambiguity in or correct or supplement any provision of our partnership agreement as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the MGP’s Chapter 11 filing, with respect to the managing general partner would not cause the managing general partner to cease to serve as the managing general partner of the Partnership nor cause the termination of the Partnership. Atlas Energy Group was not a party to the ARP Restructuring. Atlas Energy Group remains controlled by the same ownership group and management team and thus, the ARP Restructuring did not have a material impact on the ability of Atlas Energy Group management to operate ARP or the other Atlas Energy Group businesses. On August 26, 2016, an order confirming ARP’s Plan was entered by the Bankruptcy Court. On September 1, 2016, ARP’s Plan became effective and ARP emerged as Titan. Liquidity, Capital Resources and Ability to Continue as a Going Concern 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. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the 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 strategic 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 liquidation of the Partnership’s operations. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had been adequate to fund its obligations and distributions to its 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, these conditions raise substantial doubt about the Partnership’s ability to continue as a going concern. If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could occur without any further contributions from or distributions to the limited partners. The significant risks and uncertainties related to the Partnership’s ability to fund its operations raise 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 obligations; however, the uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which further raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended. The financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material. MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for debt service including interest, and capital expenditures. The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under Titan’s credit facilities and equity and debt offerings. The MGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities. Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern. Titan expects to finalize an amendment to its first lien credit facility on April 19, 2017 in an attempt to ameliorate some of its liquidity concerns, subject to receiving the remaining lenders’ consent. The amendment is expected to provide for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility. Unless Titan is able to obtain an amendment or waiver, the lenders under Titan’s second lien credit facility may declare a default with respect to Titan’s failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under Titan’s second lien credit facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under Titan’s second lient credit facility have not yet given notice of any default. Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2016
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. Actual results could differ from those estimates. Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2016 and 2015, 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, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 188,100 $ 9,900 Asset retirement estimates withheld 194,400 178,200 Asset retirement receivable –affiliate, end of year $ 382,500 $ 188,100 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 is 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. 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. 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 (as determined by the discounted cash flows) and the carrying value of the assets. The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In 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 entered 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 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. 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. 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, 2016 and 2015. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2016. 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, 2016 and 2015. 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, 2016, the Partnership had four customers that individually accounted for approximately 28%, 23%, 16% and 15% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, the Partnership had four customers that individually accounted for approximately 27%, 17%, 12% and 12% 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. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $41,700 and $29,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. 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, 2016, 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. We adopted this accounting guidance on December 15, 2016, and provided enhanced disclosures, as applicable, within our financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our consolidated financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.

Participation in Revenues and C

Participation in Revenues and Costs	12 Months Ended
Participation in Revenues and Costs	Dec. 31, 2016
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 0% 100% Tangible equipment costs 100% 0% Revenues (1) 35% 65% Operating costs, administrative costs, direct and all other costs (2) 35% 65% (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
Property, Plant and Equipment	Dec. 31, 2016
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, 2016 2015 Proved properties: Leasehold interest $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Total natural gas and oil properties 18,976,300 18,976,300 Accumulated depletion and impairment (18,637,800 ) (18,439,300 ) Gas and oil properties, net $ 338,500 $ 537,000 The Partnership recorded depletion expense on natural gas and oil properties of $36,400 and $27,600 for the years ended December 31, 2016 and 2015, respectively. The depletion expense recorded for the year ended December 31, 2016 was a result of a decrease in management’s estimated salvage value. During the years ended December 31, 2016 and 2015, the Partnership recognized $162,100 and $457,200, respectively, of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2016 and 2015. At December 31, 2016, the MGP redetermined estimated salvage values to be lower than previous estimates. This redetermination resulted in the impairment of gas and oil properties. Due to the change in estimated salvage values of tangible equipment, all impairment expense was allocated to the MGP (See Note 3: Participation in revenues and Costs). At December 31, 2015, the estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. 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, 2016 represents management’s estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2016
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, 2016 and 2015, the MGP withheld $382,500 and $188,100, respectively, 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, 2016 2015 Beginning of year $ 1,879,800 $ 1,778,100 Accretion expense 68,500 101,700 End of year $ 1,948,300 $ 1,879,800

Derivative Instruments

Derivative Instruments	12 Months Ended
Derivative Instruments	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	NOTE 6—DERIVATIVE INSTRUMENTS The MGP, on behalf of the Partnership, used a number of different derivative instruments, principally put options, in connection with the Partnership’s commodity price risk management activities. Management used 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 entered 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 $0 and $13,400 at December 31, 2016 and 2015, respectively. 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 2016 2015 Gain reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues $ 700 $ 1,900 (Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ (100 ) $ 8,500 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, 2016 and 2015, the put premiums were recorded as short-term payables to affiliate of $0 and $6,200, respectively

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
Fair Value of Financial Instruments	Dec. 31, 2016
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, 2016 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity puts $ - $ - $ - $ - As of December 31, 2015 Derivative assets, gross Commodity puts $ - $ 13,400 $ - $ 13,400 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 such 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, 2016. There were no adjustments to retirement obligations for the year ended December 31, 2015. 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, 2016 and 2015, the Partnership recognized $162,100 and $457,200, respectively, of impairment of long-lived assets which was defined as a Level 3 fair value measurement (See Note 4: Property, Plant, and Equipment).

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	12 Months Ended
Certain Relationships and Related Party Transactions	Dec. 31, 2016
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 $337 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, 2016 2015 Administrative fees $ 49,700 $ 51,000 Supervision fees 223,300 229,400 Transportation fees 25,700 31,200 Direct Costs 134,700 141,300 Total $ 433,400 $ 452,900 The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s balance sheet includes the net production expenses due to the MGP.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 9—COMMITMENTS AND CONTINGENCIES General Commitments Subject to certain conditions, limited 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, 2016 and 2015, the MGP withheld $382,500 and $188,100, 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
Subsequent Events	Dec. 31, 2016
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
Supplemental Gas and Oil Information (Unaudited)	Dec. 31, 2016
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. 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 41 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by 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 and crude oil 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 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, 2016 and 2015, including adjustments related to regional price differentials and energy content. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of 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, 2014 772,500 5,500 Revisions (1) (636,900 ) (4,700 ) Production (135,600 ) (800 ) Balance, December 31, 2015 (2) - - Revisions - - Production - - Balance, December 31, 2016 (2) - - (1) The downward revision in natural gas forecasts is primarily due to a decrease in the SEC base pricing from the prior year, resulting in a shorter economic life. (2) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2016 and 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 years presented, 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, 2016 2015 Natural gas and oil properties: Leasehold interest $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Accumulated depletion, accretion and impairment (18,637,800 ) (18,439,300 ) Net capitalized costs $ 338,500 $ 537,000 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, 2016 2015 Revenues $ 216,400 $ 264,800 Production costs (328,500 ) (346,100 ) Depletion (36,400 ) (27,600 ) Impairment (162,100 ) (457,200 ) $ (310,600 ) $ (566,100 )

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Liquidity, Capital Resources and Ability to Continue as a Going Concern	Liquidity, Capital Resources and Ability to Continue as a Going Concern 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. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the Partnership’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on the Partnership’s liquidity position. In addition, the Partnership has experienced significant downward revisions of its natural gas and oil reserves volumes and values due to the 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 strategic 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 liquidation of the Partnership’s operations. Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations had been adequate to fund its obligations and distributions to its 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, these conditions raise substantial doubt about the Partnership’s ability to continue as a going concern. If the Partnership is not able to continue as a going concern, the Partnership will liquidate. If the Partnership’s operations are liquidated, a valuation of the Partnership’s assets and liabilities would be determined by an independent expert in accordance with the partnership agreement. It is possible that based on such determination, the Partnership would not be able to make any liquidation distributions to its limited partners. A liquidation could occur without any further contributions from or distributions to the limited partners. The significant risks and uncertainties related to the Partnership’s ability to fund its operations raise 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 obligations; however, the uncertainties of Titan’s and the MGP’s liquidity and capital resources (as further described below) raise substantial doubt about Titan’s and the MGP’s ability to continue as a going concern, which further raises substantial doubt about the Partnership’s ability to continue as a going concern. If Titan is unsuccessful in taking actions to resolve its liquidity issues (as further described below), the MGP’s ability to continue the Partnership’s operations may be further impacted and may make it uneconomical for the Partnership to produce its wells until they are depleted as originally intended. The financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of the Partnership’s assets and liabilities and the reported amounts of income and expenses could be required and could be material.
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. Actual results could differ from those estimates.
Receivables	Receivables Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2016 and 2015, 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, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 188,100 $ 9,900 Asset retirement estimates withheld 194,400 178,200 Asset retirement receivable –affiliate, end of year $ 382,500 $ 188,100
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 is 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. 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. 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 (as determined by the discounted cash flows) and the carrying value of the assets. The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In 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 entered 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 were reclassified to the statements of operations in the periods in which the respective derivative contracts settled. 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.
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, 2016 and 2015. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2012. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2016.
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, 2016 and 2015.
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, 2016, the Partnership had four customers that individually accounted for approximately 28%, 23%, 16% and 15% of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, the Partnership had four customers that individually accounted for approximately 27%, 17%, 12% and 12%
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. The Partnership had unbilled revenues at December 31, 2016 and 2015 of $41,700 and $29,600, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
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, 2016, 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. We adopted this accounting guidance on December 15, 2016, and provided enhanced disclosures, as applicable, within our financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our consolidated financial statements. This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.
MGP
Summary Of Significant Accounting Policies [Line Items]
Liquidity, Capital Resources and Ability to Continue as a Going Concern	MGP’s Liquidity, Capital Resources, and Ability to Continue as a Going Concern The MGP’s primary sources of liquidity are cash generated from operations, capital raised through its drilling partnership program, and borrowings under Titan’s credit facilities. The MGP’s primary cash requirements are operating expenses, payments to Titan for debt service including interest, and capital expenditures. The MGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations, amounts available under Titan’s credit facilities and equity and debt offerings. The MGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and continued to remain low in 2016. These lower commodity prices have negatively impacted the MGP’s revenues, earnings and cash flows. Sustained low commodity prices could have a material and adverse effect on the MGP’s liquidity position. In addition, challenges with the MGP’s ability to raise capital through its drilling partnership program, either as a result of downturn in commodity prices or other difficulties affecting the fundraising channel, have negatively impacted Titan’s and the MGP’s ability to remain in compliance with the covenants under its credit facilities. Titan was not in compliance with certain of the financial covenants under its credit facilities as of December 31, 2016, as well as the requirement to deliver audited financial statements without a going concern qualification. Titan and the MGP do not currently have sufficient liquidity to repay all of Titan’s outstanding indebtedness, and as a result, there is substantial doubt regarding Titan’s and the MGP’s ability to continue as a going concern. Titan expects to finalize an amendment to its first lien credit facility on April 19, 2017 in an attempt to ameliorate some of its liquidity concerns, subject to receiving the remaining lenders’ consent. The amendment is expected to provide for, among other things, waivers of non-compliance, increases in certain financial covenant ratios and scheduled decreases in Titan’s borrowing base. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. The lenders’ waivers are subject to revocation in certain circumstances, including the exercise of remedies by junior lenders (including pursuant to Titan’s second lien credit facility), the failure to extend the standstill period under the intercreditor agreement at least 15 business days prior to its expiration, and the occurrence of additional events of default under the first lien credit facility. Unless Titan is able to obtain an amendment or waiver, the lenders under Titan’s second lien credit facility may declare a default with respect to Titan’s failure to comply with financial covenants and deliver audited financial statements without a going concern qualification. However, pursuant to the intercreditor agreement, the lenders under Titan’s second lien credit facility are restricted in their ability to pursue remedies for 180 days from any such notice of default. As of the date hereof, the lenders under Titan’s second lient credit facility have not yet given notice of any default. Titan continually monitors the capital markets and the MGP’s capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening its balance sheet, meeting its debt service obligations and/or achieving cost efficiency. For example, Titan could pursue options such as refinancing, restructuring or reorganizing its indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address its liquidity concerns and high debt levels. Titan is evaluating various options, but there is no certainty that Titan will be able to implement any such options, and cannot provide any assurances that any refinancing or changes in its debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for Titan’s stakeholders. In addition, Titan expects that it will sell a significant amount of non-core assets in the near future to comply with the requirements of its expected first lien credit facility amendment and to attempt to enhance its liquidity. However, there is no guarantee that the proceeds Titan receives for any asset sale will satisfy the repayment requirements under its first lien credit facility.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2016
Accounting Policies [Abstract]
Reconciliation of the Partnership's Asset Retirement Receivable	The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the periods indicated: December 31, 2016 2015 Asset retirement receivable – affiliate, beginning of year $ 188,100 $ 9,900 Asset retirement estimates withheld 194,400 178,200 Asset retirement receivable –affiliate, end of year $ 382,500 $ 188,100

Participation in Revenues and21

Participation in Revenues and Costs (Tables)	12 Months Ended
Participation in Revenues and Costs (Tables)	Dec. 31, 2016
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 0% 100% Tangible equipment costs 100% 0% Revenues (1) 35% 65% Operating costs, administrative costs, direct and all other costs (2) 35% 65% (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
Property, Plant and Equipment (Tables)	Dec. 31, 2016
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, 2016 2015 Proved properties: Leasehold interest $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Total natural gas and oil properties 18,976,300 18,976,300 Accumulated depletion and impairment (18,637,800 ) (18,439,300 ) Gas and oil properties, net $ 338,500 $ 537,000

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	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, 2016 2015 Beginning of year $ 1,879,800 $ 1,778,100 Accretion expense 68,500 101,700 End of year $ 1,948,300 $ 1,879,800

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
Derivative Instruments (Tables)	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 2016 2015 Gain reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues $ 700 $ 1,900 (Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives $ (100 ) $ 8,500

Fair Value of Financial Instr25

Fair Value of Financial Instruments (Tables)	12 Months Ended
Fair Value of Financial Instruments (Tables)	Dec. 31, 2016
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, 2016 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity puts $ - $ - $ - $ - As of December 31, 2015 Derivative assets, gross Commodity puts $ - $ 13,400 $ - $ 13,400

Certain Relationships and Rel26

Certain Relationships and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Administrative fees $ 49,700 $ 51,000 Supervision fees 223,300 229,400 Transportation fees 25,700 31,200 Direct Costs 134,700 141,300 Total $ 433,400 $ 452,900

Supplemental Gas and Oil Info27

Supplemental Gas and Oil Information (Unaudited) (Tables)	12 Months Ended
Supplemental Gas and Oil Information (Unaudited) (Tables)	Dec. 31, 2016
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, 2014 772,500 5,500 Revisions (1) (636,900 ) (4,700 ) Production (135,600 ) (800 ) Balance, December 31, 2015 (2) - - Revisions - - Production - - Balance, December 31, 2016 (2) - - (1) The downward revision in natural gas forecasts is primarily due to a decrease in the SEC base pricing from the prior year, resulting in a shorter economic life. (2) We have experienced significant downward revisions of our natural gas and oil reserves volumes and values to zero in 2016 and 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 years presented, 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, 2016 2015 Natural gas and oil properties: Leasehold interest $ 254,600 $ 254,600 Wells and related equipment 18,721,700 18,721,700 Accumulated depletion, accretion and impairment (18,637,800 ) (18,439,300 ) Net capitalized costs $ 338,500 $ 537,000
Results of Operations from 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, 2016 2015 Revenues $ 216,400 $ 264,800 Production costs (328,500 ) (346,100 ) Depletion (36,400 ) (27,600 ) Impairment (162,100 ) (457,200 ) $ (310,600 ) $ (566,100 )

Basis of Presentation (Details)

Basis of Presentation (Details)	12 Months Ended
Basis of Presentation (Details)	Dec. 31, 2016
Basis Of Presentation [Line Items]
Atlas America Public #9 LTD.	Jul. 27, 2000
Atlas Energy Group, LLC \| Titan Energy, LLC \| Preferred Member Interest
Basis Of Presentation [Line Items]
Percentage of preferred interest	2.00%

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2016USD ($)Customer	Dec. 31, 2015USD ($)Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for Uncollectible Accounts Receivable	$ 0	$ 0
Federal or state deferred income tax	0
Income tax, penalties and interest expense	$ 0	$ 0
Number of major customers \| Customer	4	4
Unbilled Revenues	$ 41,700	$ 29,600
Customer Concentration Risk \| Customer 1 \| Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	28.00%	27.00%
Customer Concentration Risk \| Customer 2 \| Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	23.00%	17.00%
Customer Concentration Risk \| Customer 3 \| Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	16.00%	12.00%
Customer Concentration Risk \| Customer 4 \| Sales Revenues
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage	15.00%	12.00%

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Reconciliation of the Partnership's Asset Retirement Receivable ) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Receivable Disclosure [Abstract]
Asset retirement receivable – affiliate, beginning of year	$ 188,100	$ 9,900
Asset retirement estimates withheld	194,400	178,200
Asset retirement receivable –affiliate, end of year	$ 382,500	$ 188,100

Participation in Revenues and31

Participation in Revenues and Costs (Narrative) (Details)	12 Months Ended
Participation in Revenues and Costs (Narrative) (Details)	Dec. 31, 2016
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, 2016
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	0.00%
Intangible Drilling Costs \| Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	100.00%
Tangible Equipment Costs \| Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	100.00%
Tangible Equipment Costs \| Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	0.00%
Revenues \| Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	35.00%	[1]
Revenues \| Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	65.00%	[1]
Operating Costs, Administrative Costs, Direct and All Other Costs \| Managing General Partner
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	35.00%	[2]
Operating Costs, Administrative Costs, Direct and All Other Costs \| Limited Partners
Capital Unit [Line Items]
Participation In Revenues And Costs, Percentage	65.00%	[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, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 18,976,300	$ 18,976,300
Accumulated depletion and impairment	(18,637,800)	(18,439,300)
Gas and oil properties, net	338,500	537,000
Leasehold interest
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	254,600	254,600
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 18,721,700	$ 18,721,700

Property, Plant and Equipment34

Property, Plant and Equipment (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Depletion of natural gas and oil properties	$ 36,400	$ 27,600
Asset impairment	$ 162,100	$ 457,200

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 382,500	$ 188,100

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Beginning of year	$ 1,879,800	$ 1,778,100
Accretion expense	68,500	101,700
End of year	$ 1,948,300	$ 1,879,800

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net derivative assets	$ 0	$ 13,400
Current portion of put premiums payable-affiliate	$ 0	$ 6,200

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, 2016	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gain reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues	$ 700	$ 1,900
(Loss) gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$ (100)	$ 8,500

Fair Value of Financial Instr39

Fair Value of Financial Instruments (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - Commodity Puts	Dec. 31, 2015USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 13,400
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value Asset	$ 13,400

Fair Value of Financial Instr40

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	$ 162,100	$ 457,200
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	162,100	457,200
Asset Retirement Obligation
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Adjustments to retirement obligations	$ 0	$ 0

Certain Relationships and Rel41

Certain Relationships and Related Party Transactions (Narrative) (Details) - MGP and Affiliates	12 Months Ended
	Dec. 31, 2016$ / mo
General and administrative expenses
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
Supervision fees
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	337
Production
Related Party Transaction [Line Items]
Transportation Fees Rate As Percentage Of Natural Gas Sales Price	13.00%

Certain Relationships and Rel42

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 433,400	$ 452,900
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	49,700	51,000
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	223,300	229,400
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	25,700	31,200
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 134,700	$ 141,300

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details)	12 Months Ended
Commitments and Contingencies (Narrative) (Details)	Dec. 31, 2016USD ($)$ / mo	Dec. 31, 2015USD ($)
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 \| $	$ 382,500	$ 188,100

Supplemental Gas and Oil Info44

Supplemental Gas and Oil Information (Unaudited) (Changes in Proved Reserve Quantities) (Details)	12 Months Ended
	Dec. 31, 2015Mcfbbl
Gas (Mcf)
Reserve Quantities [Line Items]
Balance \| Mcf	772,500
Revisions \| Mcf	(636,900)	[1]
Production \| Mcf	(135,600)
Oil (Bbls)
Reserve Quantities [Line Items]
Balance \| bbl	5,500
Revisions \| bbl	(4,700)	[1]
Production \| bbl	(800)

[1]	The downward revision in natural gas forecasts is primarily due to a decrease in the SEC base pricing from the prior year, resulting in a shorter economic life.

Supplemental Gas and Oil Info45

Supplemental Gas and Oil Information (Unaudited) (Capitalized Costs Relating to Gas and Oil Producing Activities) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Natural Gas and Oil Producing Activities [Abstract]
Natural gas and oil properties: Leasehold interest	$ 254,600	$ 254,600
Natural gas and oil properties: Wells and related equipment	18,721,700	18,721,700
Accumulated depletion, accretion and impairment	(18,637,800)	(18,439,300)
Net capitalized costs	$ 338,500	$ 537,000

Supplemental Gas and Oil Info46

Supplemental Gas and Oil Information (Unaudited) (Results of Operations from Gas and Oil Producing Activities) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Natural Gas and Oil Producing Activities [Abstract]
Revenues	$ 216,400	$ 264,800
Production costs	(328,500)	(346,100)
Depletion	(36,400)	(27,600)
Impairment	(162,100)	(457,200)
Total Results of Operations from Gas and Oil Producing Activities	$ (310,600)	$ (566,100)