Document_and_Entity_Informatio
| Document and Entity Information (USD $) | 12 Months Ended |
| Dec. 31, 2013 | |
| Document Document And Entity Information [Line Items] | ' |
| Document Type | '10-K |
| Amendment Flag | 'false |
| Document Period End Date | 31-Dec-13 |
| Document Fiscal Year Focus | '2013 |
| Document Fiscal Period Focus | 'FY |
| Entity Registrant Name | 'ATLAS AMERICA Public #15-2006 (B) L.P. |
| Entity Central Index Key | '0001357361 |
| Current Fiscal Year End Date | '--12-31 |
| Entity Filer Category | 'Smaller Reporting Company |
| Entity Common Stock, Shares Outstanding | 0 |
| Entity Public Float | $0 |
| Entity Current Reporting Status | 'Yes |
| Entity Well-known Seasoned Issuer | 'No |
| Entity Voluntary Filers | 'No |
BALANCE_SHEETS
| BALANCE SHEETS (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Current assets: | ' | ' |
| Cash and cash equivalents | $167,100 | $102,500 |
| Accounts receivable trade–affiliate | 937,400 | 984,100 |
| Accounts receivable monetized gains-affiliate | 56,200 | 296,000 |
| Current portion of derivative assets | 6,700 | 14,400 |
| Total current assets | 1,167,400 | 1,397,000 |
| Oil and gas properties, net | 13,336,000 | 16,218,600 |
| Long-term derivative assets | 35,400 | 58,500 |
| TOTAL ASSETS | 14,538,800 | 17,674,100 |
| Current liabilities: | ' | ' |
| Accrued liabilities | 6,700 | 5,300 |
| Total current liabilities | 6,700 | 5,300 |
| Asset retirement obligations | 7,692,200 | 8,117,800 |
| Long-term put premiums payable-affiliate | 63,600 | 17,300 |
| Commitments and contingencies | ' | ' |
| Partners’ capital: | ' | ' |
| Managing general partner’s interest | 3,278,400 | 3,811,900 |
| Limited partners’ interest (14,772.60 units) | 3,542,800 | 5,848,900 |
| Accumulated other comprehensive loss | -44,900 | -127,100 |
| Total partners’ capital | 6,776,300 | 9,533,700 |
| TOTAL LIABILITIES AND PARTNERS' CAPITAL | $14,538,800 | $17,674,100 |
BALANCE_SHEETS_Parenthetical
| BALANCE SHEETS (Parenthetical) | Dec. 31, 2013 |
| Limited partners' units | 14,772.60 |
STATEMENTS_OF_OPERATIONS
| STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| REVENUES | ' | ' |
| Natural gas and oil | $5,156,000 | $4,077,800 |
| Interest income | ' | 100 |
| Total revenues | 5,156,000 | 4,077,900 |
| COST AND EXPENSES | ' | ' |
| Production | 3,053,600 | 3,007,500 |
| Depletion | 2,030,800 | 1,789,600 |
| Asset impairment | ' | 1,094,300 |
| Accretion of asset retirement obligation | 441,400 | 401,400 |
| General and administrative | 431,500 | 457,700 |
| Total costs and expenses | 5,957,300 | 6,750,500 |
| Net loss | -801,300 | -2,672,600 |
| Allocation of net loss: | ' | ' |
| Managing general partner | 3,300 | -466,500 |
| Limited partners | ($804,600) | ($2,206,100) |
| Net loss per limited partnership unit | ($54) | ($149) |
STATEMENTS_OF_COMPREHENSIVE_LO
| STATEMENTS OF COMPREHENSIVE LOSS (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Net loss | ($801,300) | ($2,672,600) |
| Other comprehensive income (loss): | ' | ' |
| Unrealized holding loss on cash flow hedging contracts | -53,400 | -35,900 |
| Difference in estimated hedge gains receivable | 185,900 | 2,200 |
| Reclassification adjustment for gains realized in net loss from cash flow hedges | -50,300 | -116,000 |
| Total other comprehensive income (loss) | 82,200 | -149,700 |
| Comprehensive loss | ($719,100) | ($2,822,300) |
STATEMENTS_OF_CHANGES_IN_PARTN
| STATEMENTS OF CHANGES IN PARTNERS' CAPITAL (USD $) | Total | Managing General Partner | Limited Partners | Accumulated Other Comprehensive Income (Loss) |
| Balance at Dec. 31, 2011 | $13,983,600 | $4,489,300 | $9,471,700 | $22,600 |
| Participation in revenue and costs and expenses: | ' | ' | ' | ' |
| Net production revenues | 1,070,300 | 386,900 | 683,400 | ' |
| Interest income | 100 | ' | 100 | ' |
| Depletion | -1,789,600 | -368,000 | -1,421,600 | ' |
| Asset impairment | -1,094,300 | -199,700 | -894,600 | ' |
| Accretion of asset retirement obligation | -401,400 | -133,500 | -267,900 | ' |
| General and administrative | -457,700 | -152,200 | -305,500 | ' |
| Net loss | -2,672,600 | -466,500 | -2,206,100 | ' |
| Other comprehensive income (loss) | -149,700 | ' | ' | -149,700 |
| Distributions to partners | -1,627,600 | -210,900 | -1,416,700 | ' |
| Balance at Dec. 31, 2012 | 9,533,700 | 3,811,900 | 5,848,900 | -127,100 |
| Participation in revenue and costs and expenses: | ' | ' | ' | ' |
| Net production revenues | 2,102,400 | 709,900 | 1,392,500 | ' |
| Depletion | -2,030,800 | -416,300 | -1,614,500 | ' |
| Accretion of asset retirement obligation | -441,400 | -146,800 | -294,600 | ' |
| General and administrative | -431,500 | -143,500 | -288,000 | ' |
| Net loss | -801,300 | 3,300 | -804,600 | ' |
| Other comprehensive income (loss) | 82,200 | ' | ' | 82,200 |
| Distributions to partners | -2,038,300 | -536,800 | -1,501,500 | ' |
| Balance at Dec. 31, 2013 | $6,776,300 | $3,278,400 | $3,542,800 | ($44,900) |
STATEMENTS_OF_CASH_FLOWS
| STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Cash flows from operating activities: | ' | ' |
| Net loss | ($801,300) | ($2,672,600) |
| Adjustments to reconcile net loss to net cash provided by operating activities: | ' | ' |
| Depletion | 2,030,800 | 1,789,600 |
| Asset impairment | ' | 1,094,300 |
| Non-cash loss on derivative value, net | 399,100 | 738,400 |
| Accretion of asset retirement obligation | 441,400 | 401,400 |
| Asset retirement obligations settled | -26,000 | -11,600 |
| Changes in operating assets and liabilities: | ' | ' |
| Decrease in accounts receivable trade-affiliate | 46,700 | 130,600 |
| (Increase) decrease in accrued liabilities | 1,400 | -33,400 |
| Net cash provided by operating activities | 2,092,100 | 1,436,700 |
| Cash flows from investing activities: | ' | ' |
| Sale of tangible equipment | 11,900 | 3,100 |
| Purchase of tangible equipment | -1,100 | ' |
| Net cash provided by investing activities | 10,800 | 3,100 |
| Cash flows from financing activities: | ' | ' |
| Distributions to partners | -2,038,300 | -1,627,600 |
| Net cash used in financing activities | -2,038,300 | -1,627,600 |
| Net change in cash and cash equivalents | 64,600 | -187,800 |
| Cash and cash equivalents at beginning of year | 102,500 | 290,300 |
| Cash and cash equivalents at end of period | 167,100 | 102,500 |
| Supplemental schedule of non-cash investing and financing activities: | ' | ' |
| Asset retirement obligation revision | ($841,000) | ($150,600) |
Basis_of_Presentation
| Basis of Presentation | 12 Months Ended |
| Dec. 31, 2013 | |
| BASIS OF PRESENTATION | ' |
| NOTE 1—BASIS OF PRESENTATION | |
| Atlas America Public #15-2006 (B) L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 9, 2006 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). | |
| In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP. | |
| On February 17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”). | |
| The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling. |
Summary_of_Significant_Account
| Summary of Significant Accounting Policies | 12 Months Ended |
| Dec. 31, 2013 | |
| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ' |
| NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
| Use of Estimates | |
| The preparation of 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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates. | |
| Cash Equivalents | |
| The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. | |
| Receivables | |
| Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realization 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, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. | |
| Oil and Gas Properties | |
| Oil and gas 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 oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas. | |
| The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. | |
| Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets. | |
| Impairment of Long-Lived Assets | |
| The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value. | |
| The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion 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 discounted future cash flows) and the carrying value of the assets. | |
| The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In 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. | |
| There was no impairment of oil and gas properties recorded by us for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized an impairment of oil and gas properties of $1,094,300. 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, 2013 and 2012. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. | |
| Derivative Instruments | |
| The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in 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. | |
| Asset Retirement Obligations | |
| The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. | |
| Income Taxes | |
| The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability. | |
| 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, 2013 and 2012. | |
| 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 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013. | |
| 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, 2013 and 2012. | |
| 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, 2013, the Partnership had two customers that individually accounted for approximately 64% and 10%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had three customers that individually accounted for approximately 58%, 10%, and 10% of the Partnership natural gas and oil combined revenues, excluding the impact of all financial derivative activity. | |
| Revenue Recognition | |
| The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. | |
| The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $738,300 and $790,900, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. | |
| Comprehensive Loss | |
| Comprehensive loss includes net 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 loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. | |
| Recently Adopted Accounting Standards | |
| In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures. | |
| In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payable are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures. | |
| Recently Issued Accounting Standards | |
| In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. | |
Participation_in_Revenues_and_
| Participation in Revenues and Costs | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| PARTICIPATION IN REVENUES AND COSTS | ' | |||||||
| NOTE 3—PARTICIPATION IN REVENUES AND COSTS | ||||||||
| Working Interest | ||||||||
| Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). Our 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 will generally participate in revenues and costs in the following manner: | ||||||||
| Managing | ||||||||
| General | Limited | |||||||
| Partner | Partners | |||||||
| Organization and offering cost | 100% | 0% | ||||||
| Lease costs | 100% | 0% | ||||||
| Revenues (1) | 33% | 67% | ||||||
| Operating costs, administrative costs, direct and all other costs (2) | 33% | 67% | ||||||
| Intangible drilling costs | 3% | 97% | ||||||
| Tangible equipment costs | 66% | 34% | ||||||
| -1 | Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues. | |||||||
| -2 | These costs will be charged to the partners in the same ratio as the related production revenues are credited. | |||||||
Property_Plant_and_Equipment
| Property, Plant and Equipment | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| PROPERTY, PLANT AND EQUIPMENT | ' | |||||||
| NOTE 4—PROPERTY, PLANT AND EQUIPMENT | ||||||||
| The following is a summary of natural gas and oil properties at the dates indicated: | ||||||||
| December 31, | ||||||||
| 2013 | 2012 | |||||||
| Proved properties: | ||||||||
| Leasehold interest | $ | 4,179,600 | $ | 4,188,000 | ||||
| Wells and related equipment | 183,397,500 | 184,618,600 | ||||||
| Total natural gas and oil properties | 187,577,100 | 188,806,600 | ||||||
| Accumulated depletion and impairment | (174,241,100 | ) | (172,588,000 | ) | ||||
| Oil and gas properties, net | $ | 13,336,000 | $ | 16,218,600 | ||||
| The Partnership recorded depletion expense on natural gas and oil properties of $2,030,800 and $1,789,600 for the years ended December 31, 2013 and 2012, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. As a result of retirements, the Partnership reclassified $377,700 from oil and gas properties to accumulated depletion for the year ended December 31, 2013. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations. | ||||||||
| There was no impairment of oil and gas properties recorded by us for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized an impairment of oil and gas properties of $1,094,300. 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, 2013 and 2012. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. | ||||||||
Asset_Retirement_Obligations
| Asset Retirement Obligations | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| ASSET RETIREMENT OBLIGATIONS | ' | |||||||
| NOTE 5—ASSET RETIREMENT OBLIGATIONS | ||||||||
| The Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, 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 the Partnership’s 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. | ||||||||
| A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Asset retirement obligations, beginning of year | $ | 8,117,800 | $ | 7,878,600 | ||||
| Accretion of asset retirement obligation | 441,400 | 401,400 | ||||||
| Asset retirement obligation revision | (841,000 | ) | (150,600 | ) | ||||
| Liabilities settled | (26,000 | ) | (11,600 | ) | ||||
| Asset retirement obligations, end of period | $ | 7,692,200 | $ | 8,117,800 | ||||
Derivative_Instruments
| Derivative Instruments | 12 Months Ended | ||||||||||||
| Dec. 31, 2013 | |||||||||||||
| DERIVATIVE INSTRUMENTS | ' | ||||||||||||
| NOTE 6—DERIVATIVE INSTRUMENTS | |||||||||||||
| The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. 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. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged. | |||||||||||||
| The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on market-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur. | |||||||||||||
| The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $42,100 and $72,900 at December 31, 2013 and 2012, respectively. | |||||||||||||
| The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values. | |||||||||||||
| At December 31, 2013, the Partnership had the following commodity derivatives: | |||||||||||||
| Natural Gas Put Options | |||||||||||||
| Production | Volumes | Average | Fair Value | ||||||||||
| Period Ending | (MMBtu)(1) | Fixed Price | Asset (2) | ||||||||||
| December 31, | (per MMBtu)(1) | ||||||||||||
| 2014 | 55,300 | $ | 3.8 | $ | 6,700 | ||||||||
| 2015 | 44,200 | 4 | 14,900 | ||||||||||
| 2016 | 44,200 | 4.15 | 20,500 | ||||||||||
| $ | 42,100 | ||||||||||||
| -1 | “MMBtu” represents million British Thermal Units. | ||||||||||||
| -2 | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||
| Effects of Derivative Instruments on Statements of Operations: | |||||||||||||
| The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012: | |||||||||||||
| Years Ended December 31, | |||||||||||||
| 2013 | 2012 | ||||||||||||
| Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues | $ | 50,300 | $ | 116,000 | |||||||||
| As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2013 and 2012, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges. | |||||||||||||
| Monetized Gains | |||||||||||||
| Prior to February 17, 2011 Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2013 and 2012, remaining hedge monetization cash proceeds of $88,100 and $322,900, respectively, related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. There were no long-term monetized gains receivable-affiliate at December 31, 2013. At December 31, 2012, $64,600 of monetized gains receivable-affiliate were included in long-term put premiums payable-affiliate on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts. | |||||||||||||
| During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. 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, 2013 and 2012, the put premiums were recorded as short-term payables to affiliate of $31,900 and $26,900, respectively, and long-term payables to affiliate of $63,600 and $81,900, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only. | |||||||||||||
| The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated: | |||||||||||||
| Offsetting Assets | Gross | Gross | Net Amount of Assets | ||||||||||
| Amounts of | Amounts | Presented in the | |||||||||||
| Recognized | Offset in the | Balance Sheets | |||||||||||
| Assets | Balance Sheets | ||||||||||||
| As of December 31, 2013 | |||||||||||||
| Accounts receivable monetized gains-affiliate | $ | 88,100 | $ | (31,900 | ) | $ | 56,200 | ||||||
| Total | $ | 88,100 | $ | (31,900 | ) | $ | 56,200 | ||||||
| As of December 31, 2012 | |||||||||||||
| Accounts receivable monetized gains-affiliate | $ | 322,900 | $ | (26,900 | ) | $ | 296,000 | ||||||
| Long-term receivable monetized gains-affiliate | 64,600 | (64,600 | ) | - | |||||||||
| Total | $ | 387,500 | $ | (91,500 | ) | $ | 296,000 | ||||||
| Offsetting Liabilities | Gross | Gross | Net Amount of | ||||||||||
| Amounts of | Amounts | Liabilities Presented | |||||||||||
| Recognized | Offset in the | in the Balance Sheets | |||||||||||
| Liabilities | Balance Sheets | ||||||||||||
| As of December 31, 2013 | |||||||||||||
| Put premiums payable-affiliate | $ | (31,900 | ) | $ | 31,900 | $ | - | ||||||
| Long-term put premiums payable-affiliate | (63,600 | ) | - | (63,600 | ) | ||||||||
| Total | $ | (95,500 | ) | $ | 31,900 | $ | (63,600 | ) | |||||
| As of December 31, 2012 | |||||||||||||
| Put premiums payable-affiliate | $ | (26,900 | ) | $ | 26,900 | $ | - | ||||||
| Long-term put premiums payable-affiliate | (81,900 | ) | 64,600 | (17,300 | ) | ||||||||
| Total | $ | -108,800 | $ | 91,500 | $ | (17,300 | ) | ||||||
| Accumulated Other Comprehensive Loss | |||||||||||||
| As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $44,900 as of December 31, 2013. Included in accumulated other comprehensive loss are unrealized gains of $79,600, net of the MGP interest, that were recognized into income as a result of oil and gas property impairments during prior periods. During the current year, $32,700 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $44,900 of net unrealized losses in accumulated other comprehensive loss, the Partnership will reclassify $16,600 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $28,300 in later periods. | |||||||||||||
Fair_Value_of_Financial_Instru
| Fair Value of Financial Instruments | 12 Months Ended | ||||||||||||||||
| Dec. 31, 2013 | |||||||||||||||||
| 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 carrying value of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short-term maturities of such financial instruments. 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. 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 pricing formula utilized in the derivative instrument. | |||||||||||||||||
| Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows: | |||||||||||||||||
| As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Derivative assets, gross | |||||||||||||||||
| Commodity puts | $ | - | $ | 42,100 | $ | - | $ | 42,100 | |||||||||
| Derivative liabilities, gross | |||||||||||||||||
| Commodity puts | - | - | - | - | |||||||||||||
| Total derivative, fair value, net | $ | - | $ | 42,100 | $ | - | $ | 42,100 | |||||||||
| As of December 31, 2012 | |||||||||||||||||
| Derivative assets, gross | |||||||||||||||||
| Commodity puts | $ | - | $ | 72,900 | $ | - | $ | 72,900 | |||||||||
| Derivative liabilities, gross | |||||||||||||||||
| Commodity puts | - | - | - | - | |||||||||||||
| Total derivative, fair value, net | $ | - | $ | 72,900 | $ | - | $ | 72,900 | |||||||||
| Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis | |||||||||||||||||
| 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. | |||||||||||||||||
| 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. There were no adjustments for retirement obligations measured at fair value on a nonrecurring basis for the years ended December 31, 2013 and 2012. | |||||||||||||||||
| The Partnership estimates the fair value of its long-lived assets in conjunction with the review of asset 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. No impairments were recognized for the year ended December 31, 2013. For the year ended December 31, 2012, the Partnership recognized a $1,094,300, impairment of long-lived assets which were defined as a Level 3 fair value measurement (see Note 2 – Impairment of Long-Lived Assets). | |||||||||||||||||
Certain_Relationships_and_Rela
| Certain Relationships and Related Party Transactions | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| 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 expense in the Partnership’s statement of operations, are payable at $296 per well per month for operating and maintaining the wells. Transportation fees, which are included in production expenses in the Partnership’s statements of operations, 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, | ||||||||
| 2013 | 2012 | |||||||
| Administrative | $ | 364,800 | $ | 389,000 | ||||
| Supervision | 1,441,500 | 1,533,000 | ||||||
| Transportation | 698,000 | 616,900 | ||||||
| Direct Costs | 980,800 | 926,300 | ||||||
| Total | $ | 3,485,100 | $ | 3,465,200 | ||||
| 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. | ||||||||
| Subordination by Managing General Partner | ||||||||
| Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues so that the limited partners receive a return of at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (March 2007) and expiring 60 months from that date. | ||||||||
Commitments_and_Contingencies
| Commitments and Contingencies | 12 Months Ended |
| Dec. 31, 2013 | |
| COMMITMENTS AND CONTINGENCIES | ' |
| NOTE 9—COMMITMENTS AND CONTINGENCIES | |
| General Commitments | |
| Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the 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, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and 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. |
Subsequent_Events
| Subsequent Events | 12 Months Ended |
| Dec. 31, 2013 | |
| SUBSEQUENT EVENTS | ' |
| NOTE 10—SUBSEQUENT EVENTS | |
| Management has considered for disclosure any material subsequent events through the date the financial statements were issued. | |
Supplemental_Oil_and_Gas_Infor
| Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | ' | |||||||
| NOTE 11—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | ||||||||
| Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Public #15-2006 (B) L.P. annual Form 10-K for the years ended December 31, 2013 and 2012 (see Note 2). For the periods presented, Wright and 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 37 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 MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 15 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 Chief Operating Officer. | ||||||||
| The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2013 and 2012 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, 2013 and 2012 and 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 oil and gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas 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 (unaudited): | ||||||||
| Gas (Mcf) | Oil (Bbls) | |||||||
| Balance, December 31, 2011 | 10,266,000 | 15,600 | ||||||
| Revisions(1) | (4,444,000 | ) | (3,600 | ) | ||||
| Production | (1,299,500 | ) | (3,200 | ) | ||||
| 4,522,500 | 8,800 | |||||||
| Balance, December 31, 2012 | ||||||||
| Revisions (2) | 5,768,100 | 5,700 | ||||||
| Production | (1,279,000 | ) | (3,000 | ) | ||||
| 9,011,600 | 11,500 | |||||||
| Balance, December 31, 2013 | ||||||||
| -1 | The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses. | |||||||
| -2 | The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from prior year, resulting in longer economic life. | |||||||
| Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Natural gas and oil properties: | ||||||||
| Leasehold interest | $ | 4,179,600 | $ | 4,188,000 | ||||
| Wells and related equipment | 183,397,500 | 184,618,600 | ||||||
| Accumulated depletion, accretion and impairment | (174,241,100 | ) | (172,588,000 | ) | ||||
| Net capitalized costs | $ | 13,336,000 | $ | 16,218,600 | ||||
| Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Revenues | $ | 5,156,000 | $ | 4,077,800 | ||||
| Production costs | (3,053,600 | ) | (3,007,500 | ) | ||||
| Depletion | (2,030,800 | ) | (1,789,600 | ) | ||||
| Long-lived asset impairment | - | (1,094,300 | ) | |||||
| $ | 71,600 | $ | (1,813,600 | ) | ||||
| Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Future cash inflows | $ | 34,531,500 | $ | 13,515,100 | ||||
| Future production costs | (21,318,900 | ) | (9,725,100 | ) | ||||
| Future net cash flows | 13,212,600 | 3,790,000 | ||||||
| Less 10% annual discount for estimated timing of cash flows | (5,172,700 | ) | (1,089,100 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 8,039,900 | $ | 2,700,900 | ||||
Summary_of_Significant_Account1
| Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
| Dec. 31, 2013 | |
| Use of Estimates | ' |
| Use of Estimates | |
| The preparation of 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 the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates. | |
| Cash Equivalents | ' |
| Cash Equivalents | |
| The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. | |
| Receivables | ' |
| Receivables | |
| Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realization 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, 2013 and 2012, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets. | |
| Oil and Gas Properties | ' |
| Oil and Gas Properties | |
| Oil and gas 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 oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas. | |
| The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. | |
| Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets. | |
| Impairment of Long-Lived Assets | ' |
| Impairment of Long-Lived Assets | |
| The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value. | |
| The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion 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 discounted future cash flows) and the carrying value of the assets. | |
| The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In 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. | |
| There was no impairment of oil and gas properties recorded by us for the year ended December 31, 2013. During the year ended December 31, 2012, we recognized an impairment of oil and gas properties of $1,094,300. 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, 2013 and 2012. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. | |
| Derivative Instruments | ' |
| Derivative Instruments | |
| The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in 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. | |
| Asset Retirement Obligations | ' |
| Asset Retirement Obligations | |
| The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. | |
| Income Taxes | ' |
| Income Taxes | |
| The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction, or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability. | |
| 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, 2013 and 2012. | |
| 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 2009. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2013. | |
| 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, 2013 and 2012. | |
| 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, 2013, the Partnership had two customers that individually accounted for approximately 64% and 10%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2012, the Partnership had three customers that individually accounted for approximately 58%, 10%, and 10% of the Partnership natural gas and oil combined revenues, excluding the impact of all financial derivative activity. | |
| Revenue Recognition | ' |
| Revenue Recognition | |
| The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. | |
| The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2013 and 2012 of $738,300 and $790,900, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. | |
| Comprehensive Income (Loss) | ' |
| Comprehensive Loss | |
| Comprehensive loss includes net 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 loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges. | |
| Recently Adopted Accounting Standards | ' |
| Recently Adopted Accounting Standards | |
| In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures. | |
| In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-01 clarifies that ordinary trade receivables and payable are not in scope of ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification or subject to a master netting arrangement or similar agreement. The amendments are effective for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures. | |
| Recently Issued Accounting Standards | ' |
| Recently Issued Accounting Standards | |
| In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures. |
Participation_in_Revenues_and_1
| Participation in Revenues and Costs (Tables) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| Schedule of Participation In Revenues And Costs, Allocation | ' | |||||||
| The MGP and the limited partners will generally participate in revenues and costs in the following manner: | ||||||||
| Managing | ||||||||
| General | Limited | |||||||
| Partner | Partners | |||||||
| Organization and offering cost | 100% | 0% | ||||||
| Lease costs | 100% | 0% | ||||||
| Revenues (1) | 33% | 67% | ||||||
| Operating costs, administrative costs, direct and all other costs (2) | 33% | 67% | ||||||
| Intangible drilling costs | 3% | 97% | ||||||
| Tangible equipment costs | 66% | 34% | ||||||
| -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_T
| Property, Plant and Equipment (Tables) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| Property, Plant and Equipment | ' | |||||||
| The following is a summary of natural gas and oil properties at the dates indicated: | ||||||||
| December 31, | ||||||||
| 2013 | 2012 | |||||||
| Proved properties: | ||||||||
| Leasehold interest | $ | 4,179,600 | $ | 4,188,000 | ||||
| Wells and related equipment | 183,397,500 | 184,618,600 | ||||||
| Total natural gas and oil properties | 187,577,100 | 188,806,600 | ||||||
| Accumulated depletion and impairment | (174,241,100 | ) | (172,588,000 | ) | ||||
| Oil and gas properties, net | $ | 13,336,000 | $ | 16,218,600 | ||||
Asset_Retirement_Obligations_T
| Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| Schedule of Asset Retirement Obligations | ' | |||||||
| A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Asset retirement obligations, beginning of year | $ | 8,117,800 | $ | 7,878,600 | ||||
| Accretion of asset retirement obligation | 441,400 | 401,400 | ||||||
| Asset retirement obligation revision | (841,000 | ) | (150,600 | ) | ||||
| Liabilities settled | (26,000 | ) | (11,600 | ) | ||||
| Asset retirement obligations, end of period | $ | 7,692,200 | $ | 8,117,800 | ||||
Derivative_Instruments_Tables
| Derivative Instruments (Tables) | 12 Months Ended | ||||||||||||
| Dec. 31, 2013 | |||||||||||||
| Effects of Derivative Instruments on Statements of Operations | ' | ||||||||||||
| Effects of Derivative Instruments on Statements of Operations: | |||||||||||||
| The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2013 and 2012: | |||||||||||||
| Years Ended December 31, | |||||||||||||
| 2013 | 2012 | ||||||||||||
| Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues | $ | 50,300 | $ | 116,000 | |||||||||
| Offsetting Assets | ' | ||||||||||||
| The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated: | |||||||||||||
| Offsetting Assets | Gross | Gross | Net Amount of Assets | ||||||||||
| Amounts of | Amounts | Presented in the | |||||||||||
| Recognized | Offset in the | Balance Sheets | |||||||||||
| Assets | Balance Sheets | ||||||||||||
| As of December 31, 2013 | |||||||||||||
| Accounts receivable monetized gains-affiliate | $ | 88,100 | $ | (31,900 | ) | $ | 56,200 | ||||||
| Total | $ | 88,100 | $ | (31,900 | ) | $ | 56,200 | ||||||
| As of December 31, 2012 | |||||||||||||
| Accounts receivable monetized gains-affiliate | $ | 322,900 | $ | (26,900 | ) | $ | 296,000 | ||||||
| Long-term receivable monetized gains-affiliate | 64,600 | (64,600 | ) | - | |||||||||
| Total | $ | 387,500 | $ | (91,500 | ) | $ | 296,000 | ||||||
| Offsetting Liabilities | ' | ||||||||||||
| Offsetting Liabilities | Gross | Gross | Net Amount of | ||||||||||
| Amounts of | Amounts | Liabilities Presented | |||||||||||
| Recognized | Offset in the | in the Balance Sheets | |||||||||||
| Liabilities | Balance Sheets | ||||||||||||
| As of December 31, 2013 | |||||||||||||
| Put premiums payable-affiliate | $ | (31,900 | ) | $ | 31,900 | $ | - | ||||||
| Long-term put premiums payable-affiliate | (63,600 | ) | - | (63,600 | ) | ||||||||
| Total | $ | (95,500 | ) | $ | 31,900 | $ | (63,600 | ) | |||||
| As of December 31, 2012 | |||||||||||||
| Put premiums payable-affiliate | $ | (26,900 | ) | $ | 26,900 | $ | - | ||||||
| Long-term put premiums payable-affiliate | (81,900 | ) | 64,600 | (17,300 | ) | ||||||||
| Total | $ | -108,800 | $ | 91,500 | $ | (17,300 | ) | ||||||
| Natural Gas Put Options | ' | ||||||||||||
| Commodity Derivatives | ' | ||||||||||||
| At December 31, 2013, the Partnership had the following commodity derivatives: | |||||||||||||
| Natural Gas Put Options | |||||||||||||
| Production | Volumes | Average | Fair Value | ||||||||||
| Period Ending | (MMBtu)(1) | Fixed Price | Asset (2) | ||||||||||
| December 31, | (per MMBtu)(1) | ||||||||||||
| 2014 | 55,300 | $ | 3.8 | $ | 6,700 | ||||||||
| 2015 | 44,200 | 4 | 14,900 | ||||||||||
| 2016 | 44,200 | 4.15 | 20,500 | ||||||||||
| $ | 42,100 | ||||||||||||
| -1 | “MMBtu” represents million British Thermal Units. | ||||||||||||
| -2 | Fair value based on forward NYMEX natural gas prices, as applicable. | ||||||||||||
Fair_Value_of_Financial_Instru1
| Fair Value of Financial Instruments (Tables) | 12 Months Ended | ||||||||||||||||
| Dec. 31, 2013 | |||||||||||||||||
| Schedule of Fair Value Derivative Instruments | ' | ||||||||||||||||
| Information for assets and liabilities measured at fair value at December 31, 2013 and 2012 was as follows: | |||||||||||||||||
| As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| Derivative assets, gross | |||||||||||||||||
| Commodity puts | $ | - | $ | 42,100 | $ | - | $ | 42,100 | |||||||||
| Derivative liabilities, gross | |||||||||||||||||
| Commodity puts | - | - | - | - | |||||||||||||
| Total derivative, fair value, net | $ | - | $ | 42,100 | $ | - | $ | 42,100 | |||||||||
| As of December 31, 2012 | |||||||||||||||||
| Derivative assets, gross | |||||||||||||||||
| Commodity puts | $ | - | $ | 72,900 | $ | - | $ | 72,900 | |||||||||
| Derivative liabilities, gross | |||||||||||||||||
| Commodity puts | - | - | - | - | |||||||||||||
| Total derivative, fair value, net | $ | - | $ | 72,900 | $ | - | $ | 72,900 | |||||||||
Certain_Relationships_and_Rela1
| Certain Relationships and Related Party Transactions (Tables) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| Costs Incurred From Related Party Transactions | ' | |||||||
| The following table provides information with respect to these costs and the periods incurred: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Administrative | $ | 364,800 | $ | 389,000 | ||||
| Supervision | 1,441,500 | 1,533,000 | ||||||
| Transportation | 698,000 | 616,900 | ||||||
| Direct Costs | 980,800 | 926,300 | ||||||
| Total | $ | 3,485,100 | $ | 3,465,200 | ||||
Supplemental_Oil_and_Gas_Infor1
| Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended | |||||||
| Dec. 31, 2013 | ||||||||
| Changes in Proved Reserve Quantities | ' | |||||||
| Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited): | ||||||||
| Gas (Mcf) | Oil (Bbls) | |||||||
| Balance, December 31, 2011 | 10,266,000 | 15,600 | ||||||
| Revisions(1) | (4,444,000 | ) | (3,600 | ) | ||||
| Production | (1,299,500 | ) | (3,200 | ) | ||||
| 4,522,500 | 8,800 | |||||||
| Balance, December 31, 2012 | ||||||||
| Revisions (2) | 5,768,100 | 5,700 | ||||||
| Production | (1,279,000 | ) | (3,000 | ) | ||||
| 9,011,600 | 11,500 | |||||||
| Balance, December 31, 2013 | ||||||||
| -1 | The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses. | |||||||
| -2 | The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from prior year, resulting in longer economic life. | |||||||
| Capitalized Costs Relating to Oil and Gas Producing Activities | ' | |||||||
| Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Natural gas and oil properties: | ||||||||
| Leasehold interest | $ | 4,179,600 | $ | 4,188,000 | ||||
| Wells and related equipment | 183,397,500 | 184,618,600 | ||||||
| Accumulated depletion, accretion and impairment | (174,241,100 | ) | (172,588,000 | ) | ||||
| Net capitalized costs | $ | 13,336,000 | $ | 16,218,600 | ||||
| Results of Operations for Oil and Gas Producing Activities | ' | |||||||
| Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Revenues | $ | 5,156,000 | $ | 4,077,800 | ||||
| Production costs | (3,053,600 | ) | (3,007,500 | ) | ||||
| Depletion | (2,030,800 | ) | (1,789,600 | ) | ||||
| Long-lived asset impairment | - | (1,094,300 | ) | |||||
| $ | 71,600 | $ | (1,813,600 | ) | ||||
| Standardized Measure of Discounted Future Cash Flows | ' | |||||||
| Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2013 and 2012, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations: | ||||||||
| Years Ended December 31, | ||||||||
| 2013 | 2012 | |||||||
| Future cash inflows | $ | 34,531,500 | $ | 13,515,100 | ||||
| Future production costs | (21,318,900 | ) | (9,725,100 | ) | ||||
| Future net cash flows | 13,212,600 | 3,790,000 | ||||||
| Less 10% annual discount for estimated timing of cash flows | (5,172,700 | ) | (1,089,100 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 8,039,900 | $ | 2,700,900 | ||||
Basis_of_Presentation_Details
| Basis of Presentation (Details) | 12 Months Ended |
| Dec. 31, 2013 | |
| Atlas America Public #15-2006 (B) L.P. Formation Date | 9-May-06 |
Summary_of_Significant_Account2
| Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Allowance for Uncollectible Accounts Receivable | $0 | $0 |
| Impairment of Long-Lived Assets Held-for-use | 0 | 1,094,300 |
| Unbilled Revenues | $738,300 | $790,900 |
| Current Year Customer 1 | ' | ' |
| Concentration Risk, Percentage | 64.00% | ' |
| Current Year Customer 2 | ' | ' |
| Concentration Risk, Percentage | 10.00% | ' |
| Prior Year Customer 1 | ' | ' |
| Concentration Risk, Percentage | ' | 58.00% |
| Prior Year Customer 2 | ' | ' |
| Concentration Risk, Percentage | ' | 10.00% |
| Prior Year Customer3 | ' | ' |
| Concentration Risk, Percentage | ' | 10.00% |
Participation_in_Revenues_and_2
| Participation in Revenues and Costs (Details) | 12 Months Ended | |
| Dec. 31, 2013 | ||
| Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Additional partnership revenues to receive, Percentage | 7.00% | |
| Organization And Offering Cost | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 100.00% | |
| Organization And Offering Cost | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 0.00% | |
| Lease Costs | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 100.00% | |
| Lease Costs | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 0.00% | |
| Revenues | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 33.00% | [1] |
| Revenues | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 67.00% | [1] |
| Operating Costs, Administrative Costs, Direct And All Other Costs | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 33.00% | [2] |
| Operating Costs, Administrative Costs, Direct And All Other Costs | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 67.00% | [2] |
| Intangible Drilling Costs | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 3.00% | |
| Intangible Drilling Costs | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 97.00% | |
| Tangible Equipment Costs | Managing General Partner | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 66.00% | |
| Tangible Equipment Costs | Limited Partners | ' | |
| Capital Unit [Line Items] | ' | |
| Participation In Revenues And Costs, Percentage | 34.00% | |
| [1] | Subject to the MGPbs 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 | |
Participation_in_Revenues_and_3
| Participation in Revenues and Costs (Narrative) (Details) (Managing General Partner) | 12 Months Ended |
| Dec. 31, 2013 | |
| Managing General Partner | ' |
| Capital Unit [Line Items] | ' |
| Additional partnership revenues to receive, Percentage | 7.00% |
Property_Plant_and_Equipment_D
| Property, Plant and Equipment (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Property Plant And Equipment [Line Items] | ' | ' |
| Natural gas and oil properties | $187,577,100 | $188,806,600 |
| Accumulated depletion and impairment | -174,241,100 | -172,588,000 |
| Oil and gas properties, net | 13,336,000 | 16,218,600 |
| Leaseholds Interest | ' | ' |
| Property Plant And Equipment [Line Items] | ' | ' |
| Natural gas and oil properties | 4,179,600 | 4,188,000 |
| Wells and related equipment | ' | ' |
| Property Plant And Equipment [Line Items] | ' | ' |
| Natural gas and oil properties | $183,397,500 | $184,618,600 |
Property_Plant_and_Equipment_N
| Property, Plant and Equipment (Narrative) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Property Plant And Equipment [Line Items] | ' | ' |
| Depletion of Oil and Gas Properties | $2,030,800 | $1,789,600 |
| Reclassification From Oil And Gas Properties To Accumulated Depletion Due To Asset Retirements | 377,700 | ' |
| Impairment of Long-Lived Assets Held-for-use | $0 | $1,094,300 |
Asset_Retirement_Obligations_D
| Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Asset Retirement Obligations [Abstract] | ' | ' |
| Asset retirement obligations, beginning of year | $8,117,800 | $7,878,600 |
| Accretion of asset retirement obligation | 441,400 | 401,400 |
| Asset retirement obligation revision | -841,000 | -150,600 |
| Liabilities settled | -26,000 | -11,600 |
| Asset retirement obligations, end of period | $7,692,200 | $8,117,800 |
Derivative_Instruments_Commodi
| Derivative Instruments (Commodity Derivatives) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | ||||
| Natural Gas Put Options | Natural Gas Put Options | Natural Gas Put Options | Natural Gas Put Options | |||||||
| Production Period Ending December 31, 2014 | Production Period Ending December 31, 2015 | Production Period Ending December 31, 2016 | ||||||||
| MMBTU | MMBTU | MMBTU | ||||||||
| Derivative [Line Items] | ' | ' | ' | ' | ' | ' | ||||
| Volumes (MMBtu) | ' | ' | ' | 55,300 | [1] | 44,200 | [1] | 44,200 | [1] | |
| Average Fixed Price (per MMBtu) | ' | ' | ' | 3.8 | [1] | 4 | [1] | 4.15 | [1] | |
| Fair Value Asset | $42,100 | $72,900 | $42,100 | [2] | $6,700 | [2] | $14,900 | [2] | $20,500 | [2] |
| [1] | b MMBtub represents million British Thermal Units. | |||||||||
| [2] | Fair value based on forward NYMEX natural gas prices, as applicable. | |||||||||
Derivative_Instruments_Effects
| Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Derivative Instruments And Hedging Activities Disclosure [Abstract] | ' | ' |
| Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues | $50,300 | $116,000 |
Derivative_Instruments_Offsett
| Derivative Instruments (Offsetting Assets) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | $88,100 | $387,500 |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets | -31,900 | -91,500 |
| Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets | 56,200 | 296,000 |
| Accounts receivable monetized gains-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | 88,100 | 322,900 |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets | -31,900 | -26,900 |
| Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets | 56,200 | 296,000 |
| Long-term receivable monetized gains-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | ' | 64,600 |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets | ' | -64,600 |
| Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets | ' | ' |
Derivative_Instruments_Offsett1
| Derivative Instruments (Offsetting Liabilities) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities | ($95,500) | ($108,800) |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets | 31,900 | 91,500 |
| Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets | -63,600 | -17,300 |
| Put premiums payable-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities | -31,900 | -26,900 |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets | 31,900 | 26,900 |
| Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets | ' | ' |
| Long-term put premiums payable-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities | -63,600 | -81,900 |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets | ' | 64,600 |
| Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets | ($63,600) | ($17,300) |
Derivative_Instruments_Narrati
| Derivative Instruments (Narrative) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Derivative [Line Items] | ' | ' |
| Fair Value Asset/(Liability) | $42,100 | $72,900 |
| Gain (Loss) on Fair Value Hedge Ineffectiveness, Net | 0 | 0 |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | 88,100 | 387,500 |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities | 95,500 | 108,800 |
| Accumulated other comprehensive (loss) income | -44,900 | -127,100 |
| Unrealized gains (losses) due to natural gas and oil property impairments | ' | ' |
| Derivative [Line Items] | ' | ' |
| Accumulated other comprehensive (loss) income | -44,900 | ' |
| Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | -16,600 | ' |
| Net Deferred Gain (Loss) To Be Reclassified Into Net Income In Later Periods | 28,300 | ' |
| Other Comprehensive Income (Loss) | ' | ' |
| Derivative [Line Items] | ' | ' |
| Unrealized gains (losses) due to natural gas and oil property impairments | ' | 79,600 |
| Allocation To Limited Partner Only | Other Comprehensive Income (Loss) | ' | ' |
| Derivative [Line Items] | ' | ' |
| Net Derivative Gains (Losses) Limited Partner | -32,700 | ' |
| Accounts receivable monetized gains-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | 88,100 | 322,900 |
| Accounts receivable monetized gains-affiliate | Allocation To Limited Partner Only | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | 88,100 | 322,900 |
| Long-term receivable monetized gains-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | ' | 64,600 |
| Long-term receivable monetized gains-affiliate | Allocation To Limited Partner Only | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets | 0 | 64,600 |
| Put premiums payable-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities | 31,900 | 26,900 |
| Put premiums payable-affiliate | Allocation To Limited Partner Only | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities | 31,900 | 26,900 |
| Long-term put premiums payable-affiliate | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities | 63,600 | 81,900 |
| Long-term put premiums payable-affiliate | Allocation To Limited Partner Only | ' | ' |
| Derivative [Line Items] | ' | ' |
| Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities | $63,600 | $81,900 |
Fair_Value_of_Financial_Instru2
| Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative, Fair Value, Total | $42,100 | $72,900 |
| Commodity Puts | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative assets, gross | 42,100 | 72,900 |
| Derivative liabilities, gross | ' | ' |
| Fair Value, Inputs, Level 1 | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative, Fair Value, Total | ' | ' |
| Fair Value, Inputs, Level 1 | Commodity Puts | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative assets, gross | ' | ' |
| Derivative liabilities, gross | ' | ' |
| Fair Value, Inputs, Level 2 | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative, Fair Value, Total | 42,100 | 72,900 |
| Fair Value, Inputs, Level 2 | Commodity Puts | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative assets, gross | 42,100 | 72,900 |
| Derivative liabilities, gross | ' | ' |
| Fair Value, Inputs, Level 3 | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative, Fair Value, Total | ' | ' |
| Fair Value, Inputs, Level 3 | Commodity Puts | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Derivative assets, gross | ' | ' |
| Derivative liabilities, gross | ' | ' |
Fair_Value_of_Financial_Instru3
| Fair Value of Financial Instruments (Narrative) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Impairment of Long-Lived Assets Held-for-use | $0 | $1,094,300 |
| Asset Retirement Obligation | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Adjustment related to retirement obligation | 0 | 0 |
| Fair Value, Inputs, Level 3 | ' | ' |
| Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ' | ' |
| Impairment of Long-Lived Assets Held-for-use | $0 | $1,094,300 |
Certain_Relationships_and_Rela2
| Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Related Party Transaction [Line Items] | ' | ' |
| Related Party Transaction, Expenses from Transactions with Related Party | $3,485,100 | $3,465,200 |
| Administrative | ' | ' |
| Related Party Transaction [Line Items] | ' | ' |
| Related Party Transaction, Expenses from Transactions with Related Party | 364,800 | 389,000 |
| Supervision | ' | ' |
| Related Party Transaction [Line Items] | ' | ' |
| Related Party Transaction, Expenses from Transactions with Related Party | 1,441,500 | 1,533,000 |
| Transportation | ' | ' |
| Related Party Transaction [Line Items] | ' | ' |
| Related Party Transaction, Expenses from Transactions with Related Party | 698,000 | 616,900 |
| Direct Costs | ' | ' |
| Related Party Transaction [Line Items] | ' | ' |
| Related Party Transaction, Expenses from Transactions with Related Party | $980,800 | $926,300 |
Certain_Relationships_and_Rela3
| Certain Relationships and Related Party Transactions (Details) (USD $) | 12 Months Ended |
| Dec. 31, 2013 | |
| Related Party Transaction [Line Items] | ' |
| Subordination, Expiration From The First Distribution To The Limited Partners | '60 months |
| Date Of First Distribution To The Limited Partners | 1-Mar-07 |
| Managing General Partner | ' |
| Related Party Transaction [Line Items] | ' |
| Managing General Partner Maximum Subordination Percentage Of Share Of Net Production Revenues | 50.00% |
| Subordination Target Return Rate For Limited Partner Subscriptions | 10.00% |
| Administrative | ' |
| Related Party Transaction [Line Items] | ' |
| Monthly Administrative Costs Per Well | 75 |
| Supervision | ' |
| Related Party Transaction [Line Items] | ' |
| Monthly Supervision Fees Per Well | 296 |
| Transportation | ' |
| Related Party Transaction [Line Items] | ' |
| Transportation Fee Rate As Percentage Of Natural Gas Sales Price | 13.00% |
Commitments_and_Contingencies_
| Commitments and Contingencies (Narrative) (Details) (USD $) | 12 Months Ended |
| Dec. 31, 2013 | |
| Disclosure Commitments And Contingencies Details [Line Items] | ' |
| 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 | $200 |
Supplemental_Oil_and_Gas_Infor2
| Supplemental Oil and Gas Information (Unaudited) (Changes In Proved Reserve Quantities) (Details) | 12 Months Ended | |||
| Dec. 31, 2013 | Dec. 31, 2012 | |||
| Mcf | Mcf | |||
| Gas (Mcf) | ' | ' | ||
| Reserve Quantities [Line Items] | ' | ' | ||
| Balance | 4,522,500 | 10,266,000 | ||
| Revisions | 5,768,100 | [1] | -4,444,000 | [2] |
| Production | -1,279,000 | -1,299,500 | ||
| Balance | 9,011,600 | 4,522,500 | ||
| Oil (Bbls) | ' | ' | ||
| Reserve Quantities [Line Items] | ' | ' | ||
| Balance | 8,800 | 15,600 | ||
| Revisions | 5,700 | [1] | -3,600 | [2] |
| Production | -3,000 | -3,200 | ||
| Balance | 11,500 | 8,800 | ||
| [1] | The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from prior year, resulting in longer economic life. | |||
| [2] | The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses. | |||
Supplemental_Oil_and_Gas_Infor3
| Supplemental Oil and Gas Information (Unaudited) (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
| Natural Gas and Oil Producing Activities [Abstract] | ' | ' |
| Natural gas and oil properties: Leasehold interest | $4,179,600 | $4,188,000 |
| Natural gas and oil properties: Wells and related equipment | 183,397,500 | 184,618,600 |
| Accumulated depletion, accretion and impairment | -174,241,100 | -172,588,000 |
| Net capitalized costs | $13,336,000 | $16,218,600 |
Supplemental_Oil_and_Gas_Infor4
| Supplemental Oil and Gas Information (Unaudited) (Results of Operations for Oil and Gas Producing Activities) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Natural Gas and Oil Producing Activities [Abstract] | ' | ' |
| Revenues | $5,156,000 | $4,077,800 |
| Production costs | -3,053,600 | -3,007,500 |
| Depletion and amortization | -2,030,800 | -1,789,600 |
| Long-lived asset impairment | ' | -1,094,300 |
| Total Results from Operations from Oil and Gas Producing Activities | $71,600 | ($1,813,600) |
Supplemental_Oil_and_Gas_Infor5
| Supplemental Oil and Gas Information (Unaudited) (Standardized Measure of Discounted Future Cash Flows) (Details) (USD $) | 12 Months Ended | |
| Dec. 31, 2013 | Dec. 31, 2012 | |
| Natural Gas and Oil Producing Activities [Abstract] | ' | ' |
| Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Cash Inflows | $34,531,500 | $13,515,100 |
| Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Production Costs | -21,318,900 | -9,725,100 |
| Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows, Total | 13,212,600 | 3,790,000 |
| Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows | -5,172,700 | -1,089,100 |
| Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure, Total | $8,039,900 | $2,700,900 |