Atlas Resources Series 28-2010 10-Q 14 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - Jun. 30, 2015 - shares	Total
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Entity Registrant Name	Atlas Resources Series 28-2010 L.P.
Entity Central Index Key	1,487,561
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED BALANCE SHEETS

CONDENSED BALANCE SHEETS - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable trade -affiliate	1,665,000	2,847,400
Asset retirement receivable-affiliate	72,700	40,400
Current portion of derivative assets	744,600	892,300
Total current assets	2,482,300	3,780,100
Gas and oil properties, net	34,356,300	35,750,600
Long-term derivative assets	244,500	398,200
TOTAL ASSETS	37,083,100	39,928,900
Current liabilities:
Accrued liabilities	131,800	184,500
Current portion of put premiums payable-affiliate	142,300	132,400
Total current liabilities	274,100	316,900
Asset retirement obligations	3,956,300	3,846,300
Long-term put premiums payable-affiliate	$ 75,900	$ 151,500
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	$ 6,557,600	$ 7,423,600
Limited partners’ interest (7,500 units)	26,062,900	27,927,700
Accumulated other comprehensive income	156,300	262,900
Total partners’ capital	32,776,800	35,614,200
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 37,083,100	$ 39,928,900

CONDENSED BALANCE SHEETS (Paren

CONDENSED BALANCE SHEETS (Parenthetical)	Jun. 30, 2015shares
Statement Of Financial Position [Abstract]
Limited partners' units	7,500

CONDENSED STATEMENTS OF OPERATI

CONDENSED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Natural gas	$ 1,631,400	$ 5,322,500	$ 3,997,300	$ 10,883,000
Gain on mark-to-market derivatives	96,800		172,300
Total revenues	1,728,200	5,322,500	4,169,600	10,883,000
COSTS AND EXPENSES
Production	1,276,400	1,697,100	2,352,600	3,165,400
Depletion	647,200	1,717,700	1,244,300	3,448,700
Accretion of asset retirement obligation	55,000	22,900	110,000	45,800
General and administrative	35,000	27,400	69,200	62,500
Total costs and expenses	2,013,600	3,465,100	3,776,100	6,722,400
Net (loss) income	(285,400)	1,857,400	393,500	4,160,600
Allocation of net (loss) income:
Managing general partner	14,400	1,113,900	261,100	2,452,900
Limited partners	$ (299,800)	$ 743,500	$ 132,400	$ 1,707,700
Net (loss) income per limited partnership unit	$ (40)	$ 99	$ 18	$ 228

CONDENSED STATEMENTS OF COMPREH

CONDENSED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income	$ (285,400)	$ 1,857,400	$ 393,500	$ 4,160,600
Other comprehensive (loss) income:
Unrealized holding gain (loss) on cash flow hedging contracts		146,800		(478,400)
Difference in estimated hedge gains receivable	(178,800)	(436,500)	(80,200)	52,200
Less: reclassification adjustment for realized loss (gain) of cash flow hedges in net (loss) income	123,800	337,900	(26,400)	46,500
Total other comprehensive (loss) income	(55,000)	48,200	(106,600)	(379,700)
Comprehensive (loss) income	$ (340,400)	$ 1,905,600	$ 286,900	$ 3,780,900

CONDENSED STATEMENT OF CHANGES

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL - 6 months ended Jun. 30, 2015 - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2014	$ 35,614,200	$ 7,423,600	$ 27,927,700	$ 262,900
Participation in revenues, costs and expenses:
Net production revenues	1,644,700	579,000	1,065,700
Gain on mark-to-market derivatives	172,300		172,300
Depletion	(1,244,300)	(250,600)	(993,700)
Accretion of asset retirement obligation	(110,000)	(41,300)	(68,700)
General and administrative	(69,200)	(26,000)	(43,200)
Net (loss) income	393,500	261,100	132,400
Other comprehensive loss	(106,600)			(106,600)
Subordination		(553,200)	553,200
Working interest adjustment		(5,600)	5,600
Distributions to partners	(3,124,300)	(568,300)	(2,556,000)
Ending balance at Jun. 30, 2015	$ 32,776,800	$ 6,557,600	$ 26,062,900	$ 156,300

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net income	$ 393,500	$ 4,160,600
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	1,244,300	3,448,700
Non-cash loss on derivative value	129,100	44,100
Accretion of asset retirement obligation	110,000	45,800
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate	1,182,400	(1,189,000)
Increase in asset retirement receivable-affiliate	(32,300)	(13,500)
(Decrease) increase in accrued liabilities	(52,700)	15,300
Net cash provided by operating activities	2,974,300	6,512,000
Cash flows from investing activities:
Proceeds from the sale of tangible equipment		17,000
Proceeds from the sale of oil and gas properties	150,000	405,700
Net cash provided by investing activities	150,000	422,700
Cash flows from financing activities:
Distributions to partners	(3,124,300)	(8,191,700)
Net cash used in financing activities	(3,124,300)	(8,191,700)
Net change in cash and cash equivalents		(1,257,000)
Cash and cash equivalents at beginning of period	0	1,257,000
Cash and cash equivalents at end of period	$ 0	0
Supplemental Schedule of non-cash investing and financing activities:
Tangible drilling costs		10,800
Intangible drilling costs		3,300
Total assets contributed by managing general partner		$ 14,100

Description of Business

Description of Business	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
DESCRIPTION OF BUSINESS	NOTE 1 - DESCRIPTION OF BUSINESS Atlas Resources Series 28-2010 L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 1, 2010 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of ARP’s general partner interest. The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, Indiana and Colorado. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling. The accompanying condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2014, which is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014. The results of operations for the three and six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued. In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission (“SEC”). Use of Estimates The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “ - Revenue Recognition” Accounts Receivable Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable. Gas and Gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $1,244,300 and $3,448,700 for the six months ended June 30, 2015 and 2014, respectively. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets. As a result of retirements, the Partnership reclassified $2,637,500 from gas and oil properties to accumulated depletion for the six months ended June 30, 2015. The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 5,449,100 $ 5,599,100 Wells and related equipment 168,698,500 171,186,000 Total natural gas and oil properties 174,147,600 176,785,100 Accumulated depletion and impairment (139,791,300 ) (141,034,500 ) Gas and oil properties, net $ 34,356,300 $ 35,750,600 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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of natural gas and oil 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 gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $40,388,700. 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, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. Working Interest The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% 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 expenses 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 and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. For the six months ended June 30, 2015, the Partnership recorded a decrease to the MGP’s capital account and an increase in the limited partners’ capital account of $5,600. Revenue Recognition The Partnership generally sells natural gas and crude oil at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See “ - Use of Estimates” ). The Partnership had unbilled revenues at June 30, 2015 and December 31, 2014 of $764,200 and $1,567,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets. Comprehensive (Loss) Income Comprehensive (loss) income includes net (loss) income 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) income. These changes, other than net (loss) income, are referred to as "other comprehensive (loss) income” on the Partnership’s financial statements and, at June 30, 2015, for the Partnership, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive (loss) income. Recently Issued Accounting Standards In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Property, Plant and Equipment, Intangibles – Goodwill and Other .

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 3 - ASSET RETIREMENT OBLIGATIONS The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. 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 Partnership also considers the estimated salvage value in the calculation of depletion. 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. As of June 30, 2015, the MGP has withheld $72,700 of net production revenue for future plugging and abandonment costs. A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Asset retirement obligation at beginning of period $ 3,901,300 $ 1,567,600 $ 3,846,300 $ 1,544,700 Accretion expense 55,000 22,900 110,000 45,800 Asset retirement obligation at end of period $ 3,956,300 $ 1,590,500 $ 3,956,300 $ 1,590,500

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	NOTE 4 - 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. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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. On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings. During the quarter ended June 30, 2015, the Partnership determined $197,600 of gains on mark-to-market derivatives for the quarter ended March 31, 2015 were included within natural gas revenue. The Partnership corrected this error in the quarter ended June 30, 2015, which resulted in second quarter gains on mark-to-market derivatives to be higher and natural gas revenue to be lower by $197,600. Total revenues and Partnership distributions were not impacted by this error. 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 $989,100 and $1,290,500 at June 30, 2015 and December 31, 2014, respectively. The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (Losses) gains reclassified from accumulated other comprehensive income into natural gas and oil revenues $ (123,800 ) $ (337,900 ) $ 26,400 $ (46,500 ) Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives $ 96,800 $ - $ 172,300 $ - 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 been recorded at their fair values. At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas Fixed Price Swaps - Limited Partners Production Volumes Average Fair Value (2 ) (MMBtu) (1) (per MMBtu) (1) 2015 288,000 $ 4.224 $ 378,700 2016 229,700 4.460 292,600 $ 671,300 Natural Gas Put Options - Limited Partners Production Volumes Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2015 98,900 $ 4.00 $ 109,200 2016 197,800 4.15 208,600 $ 317,800 Limited Partner’s Commodity Derivatives, net $ 989,100 (1) (2) At June 30, 2015, ARP had a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under ARP’s revolving credit facility, ARP is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and are guaranteed by ARP. ARP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. As of June 30, 2015, only the Partnership’s natural gas swaps are included in the secured hedge facility. 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 three and six months ended June 30, 2015 and 2014 for hedge ineffectiveness. Put Premiums Payable During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At June 30, 2015 and December 31, 2014, $142,300 and $132,400, respectively, the put premiums were recorded as short-term payables to affiliate $75,900 and $151,500, respectively, were recorded as long-term payables to affiliate. Accumulated Other Comprehensive Income As a result of the put options, swaps, and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $156,300 as of June 30, 2015. Included in accumulated other comprehensive income are unrealized gains of $442,300, net of the MGP interest, that were recognized in income as a result of gas and oil property impairments during prior periods. During the six months ended June 30, 2015, $104,500 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $156,300 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $125,600 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining gains of $30,700 in later periods.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	NOTE 5 - 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 values 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 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument. Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2015 Derivative assets, gross Commodity swaps $ - $ 671,300 $ - $ 671,300 Commodity puts - 317,800 - 317,800 Total derivative assets, gross $ - $ 989,100 $ - $ 989,100 Level 1 Level 2 Level 3 Total As of December 31, 2014 Derivative assets, gross Commodity swaps $ - $ 911,300 $ - $ 911,300 Commodity puts - 379,200 - 379,200 Total derivative assets, gross $ - $ 1,290,500 $ - $ 1,290,500 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014.

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	NOTE 6 - 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 statements of operations, are payable at $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells, and for Colorado wells a fee of $400 is charged per well per month for operating and maintaining the wells. The following table provides information with respect to these costs and the periods incurred. Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Administrative fees $ 18,300 $ 17,300 $ 36,700 $ 35,500 Supervision fees 211,000 191,200 425,400 401,000 Transportation fees 179,600 589,800 411,400 1,298,800 Direct costs 902,500 926,200 1,548,300 1,492,600 Total $ 1,311,400 $ 1,724,500 $ 2,421,800 $ 3,227,900 In addition, assets contributed from the MGP, which are disclosed on the Partnership’s statement of cash flows as a non-cash investing and financing activity were $14,100 for the six months ended June 30, 2014 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 of the Partnership to the benefit of the limited partners for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination period, 10% of their net subscriptions in each of the next three 12-month subordination periods, and 8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the limited partners (March 2011) and expiring 60 months from that date. The MGP subordinated $553,200 of its net production revenues to the limited partners for the six months ended June 30, 2015.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 7 - COMMITMENTS AND CONTINGENCIES General Commitments Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation. Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of June 30, 2015, the MGP has withheld $72,700 of net production revenue for future plugging and abandonment costs. Legal Proceedings The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations. Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Summary of Significant Accoun15

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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, impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “ - Revenue Recognition”
Account Receivable	Accounts Receivable Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.
Gas and Oil Properties	Gas and Gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized. The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet. The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $1,244,300 and $3,448,700 for the six months ended June 30, 2015 and 2014, respectively. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depletion within its balance sheets. As a result of retirements, the Partnership reclassified $2,637,500 from gas and oil properties to accumulated depletion for the six months ended June 30, 2015. The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 5,449,100 $ 5,599,100 Wells and related equipment 168,698,500 171,186,000 Total natural gas and oil properties 174,147,600 176,785,100 Accumulated depletion and impairment (139,791,300 ) (141,034,500 ) Gas and oil properties, net $ 34,356,300 $ 35,750,600
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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The determination of natural gas and oil 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 gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $40,388,700. 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, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.
Working Interest	Working Interest The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% 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 expenses 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 and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. For the six months ended June 30, 2015, the Partnership recorded a decrease to the MGP’s capital account and an increase in the limited partners’ capital account of $5,600.
Revenue Recognition	Revenue Recognition The Partnership generally sells natural gas and crude oil at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices (See “ - Use of Estimates” ). The Partnership had unbilled revenues at June 30, 2015 and December 31, 2014 of $764,200 and $1,567,000, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive (Loss) Income	Comprehensive (Loss) Income Comprehensive (loss) income includes net (loss) income 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) income. These changes, other than net (loss) income, are referred to as "other comprehensive (loss) income” on the Partnership’s financial statements and, at June 30, 2015, for the Partnership, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive (loss) income.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Property, Plant and Equipment, Intangibles – Goodwill and Other .

Summary of Significant Accoun16

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Gas and Oil Properties	The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, Proved properties: Leasehold interests $ 5,449,100 $ 5,599,100 Wells and related equipment 168,698,500 171,186,000 Total natural gas and oil properties 174,147,600 176,785,100 Accumulated depletion and impairment (139,791,300 ) (141,034,500 ) Gas and oil properties, net $ 34,356,300 $ 35,750,600

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
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: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Asset retirement obligation at beginning of period $ 3,901,300 $ 1,567,600 $ 3,846,300 $ 1,544,700 Accretion expense 55,000 22,900 110,000 45,800 Asset retirement obligation at end of period $ 3,956,300 $ 1,590,500 $ 3,956,300 $ 1,590,500

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges	The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (Losses) gains reclassified from accumulated other comprehensive income into natural gas and oil revenues $ (123,800 ) $ (337,900 ) $ 26,400 $ (46,500 ) Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives $ 96,800 $ - $ 172,300 $ -
Commodity Derivatives	At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas Fixed Price Swaps - Limited Partners Production Volumes Average Fair Value (2 ) (MMBtu) (1) (per MMBtu) (1) 2015 288,000 $ 4.224 $ 378,700 2016 229,700 4.460 292,600 $ 671,300 Natural Gas Put Options - Limited Partners Production Volumes Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2015 98,900 $ 4.00 $ 109,200 2016 197,800 4.15 208,600 $ 317,800 Limited Partner’s Commodity Derivatives, net $ 989,100 (1) (2)

Fair Value of Financial Instr19

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Assets Measured at Fair Value on a Recurring Basis	Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2015 Derivative assets, gross Commodity swaps $ - $ 671,300 $ - $ 671,300 Commodity puts - 317,800 - 317,800 Total derivative assets, gross $ - $ 989,100 $ - $ 989,100 Level 1 Level 2 Level 3 Total As of December 31, 2014 Derivative assets, gross Commodity swaps $ - $ 911,300 $ - $ 911,300 Commodity puts - 379,200 - 379,200 Total derivative assets, gross $ - $ 1,290,500 $ - $ 1,290,500

Certain Relationships and Rel20

Certain Relationships and Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	The following table provides information with respect to these costs and the periods incurred. Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 Administrative fees $ 18,300 $ 17,300 $ 36,700 $ 35,500 Supervision fees 211,000 191,200 425,400 401,000 Transportation fees 179,600 589,800 411,400 1,298,800 Direct costs 902,500 926,200 1,548,300 1,492,600 Total $ 1,311,400 $ 1,724,500 $ 2,421,800 $ 3,227,900

Description of Business (Detail

Description of Business (Details)	Feb. 27, 2015	Jun. 30, 2015
Description Of Business [Line Items]
Atlas Resources Series 28-2010 L.P. Formation Date		Apr. 1, 2010
Atlas Energy Group | Atlas Energy | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders	100.00%

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Allowance for Uncollectible Accounts Receivable	$ 0		$ 0		$ 0
Depletion of Oil and Gas Properties	647,200	$ 1,717,700	1,244,300	$ 3,448,700
Reclassification of oil and gas properties to accumulated depletion			2,637,500
Impairment	0	$ 0	$ 0	$ 0	40,388,700
Additional working interest			10.00%
Net earnings resulting from working interest adjustment reclassified			$ 5,600
Unbilled Revenues	$ 764,200		$ 764,200		$ 1,567,000

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 174,147,600	$ 176,785,100
Accumulated depletion and impairment	(139,791,300)	(141,034,500)
Gas and oil properties, net	34,356,300	35,750,600
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	5,449,100	5,599,100
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 168,698,500	$ 171,186,000

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 72,700

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 3,901,300	$ 1,567,600	$ 3,846,300	$ 1,544,700
Accretion expense	55,000	22,900	110,000	45,800
Asset retirement obligation at end of period	$ 3,956,300	$ 1,590,500	$ 3,956,300	$ 1,590,500

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	3 Months Ended			6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivative [Line Items]
Gain on mark-to-market derivatives	$ 96,800			$ 172,300
Natural gas	1,631,400		$ 5,322,500	3,997,300	$ 10,883,000
Net derivative assets	989,100			989,100		$ 1,290,500
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	0		$ 0	0	$ 0
Current portion of put premiums payable-affiliate	142,300			142,300		132,400
Long-term put premiums payable-affiliate	75,900			75,900		151,500
Accumulated other comprehensive income	156,300			156,300		$ 262,900
Other Comprehensive Income
Derivative [Line Items]
Unrealized gains (losses) due to natural gas and oil property impairments				442,300
Net Derivative Gains (Losses) Limited Partner				104,500
Cash Flow Hedge Gains (Loss) to be Reclassified within Twelve Months				125,600
Net Deferred Gains (Losses) to be Reclassified into Net Income in Later Periods				$ 30,700
Oil and Gas Revenue [Member]
Derivative [Line Items]
Gain on mark-to-market derivatives		$ 197,600
Adjustment for Q1 [Member]
Derivative [Line Items]
Gain on mark-to-market derivatives	197,600
Natural gas	$ (197,600)

Derivative Instruments (Summary

Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
(Losses) gains reclassified from accumulated other comprehensive income into natural gas and oil revenues	$ (123,800)	$ (337,900)	$ 26,400	$ (46,500)
Gains subsequent to December 31, 2014 recognized in gain on mark-to-market derivatives	$ 96,800		$ 172,300

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivatives) (Details)		6 Months Ended
		Jun. 30, 2015USD ($)MMBTU$ / MMBTU	Dec. 31, 2014USD ($)
Derivative [Line Items]
Fair Value Asset		$ 989,100	$ 1,290,500
Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Fair Value Asset	[1]	317,800
Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Fair Value Asset	[1]	671,300
Limited Partner's Commodity Derivatives, net
Derivative [Line Items]
Fair Value Asset	[1]	$ 989,100
Production Period Ending December 31, 2015 | Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[2]	98,900
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4
Fair Value Asset	[1]	$ 109,200
Production Period Ending December 31, 2015 | Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[2]	288,000
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.224
Fair Value Asset	[1]	$ 378,700
Production Period Ending December 31, 2016 | Natural Gas Put Options - Limited Partners
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[2]	197,800
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[1]	$ 208,600
Production Period Ending December 31, 2016 | Natural Gas Fixed Price Swaps - Limited Partners
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	[2]	229,700
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.460
Fair Value Asset	[1]	$ 292,600
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	“MMBtu” represents million British Thermal Units.

Fair Value of Financial Instr29

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 989,100	$ 1,290,500
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	989,100	1,290,500
Commodity Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	671,300	911,300
Commodity Swaps | Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	671,300	911,300
Commodity Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	317,800	379,200
Commodity Puts | Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 317,800	$ 379,200

Fair Value of Financial Instr30

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Fair Value Disclosures [Abstract]
Assets measured at fair value on nonrecurring basis	$ 0	$ 0
Liabilities measured at fair value on nonrecurring basis	$ 0	$ 0

Certain Relationships and Rel31

Certain Relationships and Related Party Transactions (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015USD ($)$ / mo	Jun. 30, 2014USD ($)
Related Party Transaction [Line Items]
Assets contributed from the MGP | $		$ 14,100
Managing General Partner Maximum Subordination Percentage Of Share Of Net Production Revenues	50.00%
Managing General Partner
Related Party Transaction [Line Items]
Subordination | $	$ (553,200)
Managing General Partner | First 12 Month Subordination Period
Related Party Transaction [Line Items]
Subordination Target Return Rate For Limited Partner Subscriptions	12.00%
Managing General Partner | Next Three 12 Month Subordination Periods
Related Party Transaction [Line Items]
Subordination Target Return Rate For Limited Partner Subscriptions	10.00%
Managing General Partner | Fifth 12 Month Subordination Period
Related Party Transaction [Line Items]
Subordination Target Return Rate For Limited Partner Subscriptions	8.00%
Limited Partners
Related Party Transaction [Line Items]
Subordination | $	$ 553,200
MGP and Affiliates | Administrative
Related Party Transaction [Line Items]
Monthly Administrative Costs Per Well	75
MGP and Affiliates | Production
Related Party Transaction [Line Items]
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	16.00%
MGP and Affiliates | Production | Marcellus wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	975
MGP and Affiliates | Production | New Albany Wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	1,500
MGP and Affiliates | Production | Colorado Wells
Related Party Transaction [Line Items]
Monthly Supervision Fees Per Well	400

Certain Relationships and Rel32

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 1,311,400	$ 1,724,500	$ 2,421,800	$ 3,227,900
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	18,300	17,300	36,700	35,500
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	211,000	191,200	425,400	401,000
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	179,600	589,800	411,400	1,298,800
Direct costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 902,500	$ 926,200	$ 1,548,300	$ 1,492,600

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - 6 months ended Jun. 30, 2015	USD ($)$ / mo
Commitments And Contingencies Disclosure [Abstract]
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly | $ / mo	200
Net production revenue for future plugging and abandonment costs	$ 72,700