pub11-10q_20160331.htm

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

	March 31, 2016			December 31, 2015
ASSETS
Current assets:
Cash	$	-		$	-
Accounts receivable trade–affiliate		38,800			37,900
Current portion of derivative assets		16,500			19,900
Total current assets		55,300			57,800
Gas and oil properties, net		1,537,200			1,537,200
Long-term asset retirement receivable-affiliate		420,700			321,700
Total assets	$	2,013,200		$	1,916,700

LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable trade-affiliate	$	753,000		$	579,100
Accrued liabilities		15,600			10,100
Put premiums payable-affiliate		6,600			9,200
Total current liabilities		775,200			598,400
Asset retirement obligations		4,162,500			4,124,800
Commitments and contingencies (Note 6)
Partners’ deficit:
Managing general partner’s deficit		(1,437,700	)		(1,395,500	)
Limited partners’ deficit (3,126.55 units)		(1,487,400	)		(1,411,900	)
Accumulated other comprehensive income		600			900
Total partners’ deficit		(2,924,500	)		(2,806,500	)
Total liabilities and partners’ deficit	$	2,013,200		$	1,916,700

	Three Months Ended
	March 31,
	2016			2015
REVENUES
Natural gas, oil and liquids	$	64,600		$	123,700
Gain on mark-to-market derivatives		2,900			2,500
Total revenues		67,500			126,200
COSTS AND EXPENSES
Production		114,300			162,000
Depletion		-			3,600
Accretion of asset retirement obligations		37,700			55,800
General and administrative		33,200			39,600
Total costs and expenses		185,200			261,000
Net loss	$	(117,700	)	$	(134,800	)
Allocation of net loss:
Managing general partner	$	(42,200	)	$	(49,000	)
Limited partners	$	(75,500	)	$	(85,800	)
Net loss per limited partnership unit	$	(24	)	$	(27	)

	Three Months Ended March 31,
	2016			2015
Net loss	$	(117,700	)	$	(134,800	)
Other comprehensive loss:
Difference in estimated hedge receivable		-			1,600
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		(300	)		(2,300	)
Total other comprehensive loss		(300	)		(700	)
Comprehensive loss	$	(118,000	)	$	(135,500	)

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2015	$	(1,395,500	)	$	(1,411,900	)	$	900		$	(2,806,500	)
Participation in revenues, costs and expenses:
Net production expenses		(17,400	)		(32,300	)		-			(49,700	)
Gain on mark-to-market derivatives		-			2,900			-			2,900
Accretion of asset retirement obligations		(13,200	)		(24,500	)		-			(37,700	)
General and administrative		(11,600	)		(21,600	)		-			(33,200	)
Net loss		(42,200	)		(75,500	)		-			(117,700	)
Other comprehensive loss		-			-			(300	)		(300	)
Balance at March 31, 2016	$	(1,437,700	)	$	(1,487,400	)	$	600		$	(2,924,500	)

	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(117,700	)	$	(134,800	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		-			3,600
Non-cash loss (gain) on derivative value, net		500			(3,300	)
Accretion of asset retirement obligations		37,700			55,800
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable trade-affiliate		(900	)		74,800
Increase in asset retirement receivable-affiliate		(99,000	)		-
Increase in accounts payable trade-affiliate		173,900			1,300
Increase in accrued liabilities		5,500			2,600
Net cash provided by operating activities		-			-

Cash flows from investing activities:
Net cash used in investing activities		-			-

Cash flows from financing activities:
Net cash used in financing activities		-			-
Net change in cash		-			-
Cash at beginning of period		-			-
Cash at end of period	$	-		$	-

Atlas America Public #11-2002 LTD. (the “Partnership”) is a Delaware limited partnership, formed on June 5, 2002 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). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas America Public #11-2002 LTD.

Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS) manages 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 and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas, oil and NGL. Produced natural gas, oil and NGL is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas, oil and NGL will be sold are uncertain and the Partnership is not guaranteed a specific price for the sale of its production. Changes in natural gas, oil and NGL prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas, oil and NGL prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas, oil and NGL that the Partnership can produce economically.

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines throughout 2015 and have continued to decline and remain low in 2016. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern. To the extent commodity prices remain low or decline further, ARP experiences disruptions in the financial markets impacting its respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

ARP’s revolving credit facility is currently in the process of its semi-annual redetermination. Based on projected market conditions, continued declines in commodity prices and recent conversations with its administrative agent, ARP expects that its borrowing base will be redetermined to a level below its outstanding borrowings as of March 31, 2016. If ARP’s borrowing base is redetermined below its current outstanding borrowings and ARP is unable to repay the deficiency or deposit additional collateral to eliminate such deficiency, or if ARP experiences any other event of default on its debt obligations, or if other debt agreements cross-default, and the lenders accelerate the maturity of any other outstanding debts, the MGP, may not have sufficient liquidity to continue the Partnership’s operations and to fund the Partnership’s obligations, and as a result, there would be substantial doubt regarding the Partnership’s ability to continue as a going concern.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

The condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2015, which is derived from audited financial statements, have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to those rules and regulations, although we believe that the disclosures made are adequate to make the information not misleading. 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, 2015. The results of operations for the three months ended March 31, 2016 may not necessarily be indicative of the results of operations for the year ended December 31, 2016.

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 months ended March 31, 2016 and 2015 represent actual results in all material respects.

	March 31, 2016			December 31, 2015
Proved properties:
Leasehold interests	$	695,700		$	695,700
Wells and related equipment		41,887,000			41,887,000
Total natural gas and oil properties		42,582,700			42,582,700
Accumulated depletion and impairment		(41,045,500	)		(41,045,500	)
Gas and oil properties, net	$	1,537,200		$	1,537,200

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at March 31, 2016 and December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values.

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements.

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements and its method of adoption.

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally put contracts, in connection with the Partnership’s commodity price risk management activities. The Partnership does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized in earnings.

The Partnership enters into commodity put contracts to achieve more predictable cash flows by hedging the Partnership’s 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. These contracts have been recorded at their fair values.

The Partnership reflected net derivative assets on its balance sheets of $16,500 and $19,900 at March 31, 2016 and December 31, 2015, respectively.

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

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 months ended March 31, 2016 and 2015 for hedge ineffectiveness.

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. The Partnership separates the fair value of its financial instruments into three levels (Levels 1, 2 and 3) based on its assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. As of March 31, 2016 and December 31, 2015, all derivative financial instruments were classified as Level 2.

Information for assets measured at fair value at March 31, 2016 and December 31, 2015 was as follows:

	Level 1		Level 2		Level 3		Total
As of March 31, 2016
Derivative assets, gross
Commodity puts	$	-	$	16,500	$	-	$	16,500

	Level 1		Level 2		Level 3		Total
As of December 31, 2015
Derivative assets, gross
Commodity puts	$	-	$	19,900	$	-	$	19,900

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 $320 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

The following table provides information with respect to these costs and the periods incurred:

	Three Months Ended March 31,
	2016		2015
Administrative fees	$	19,400	$	25,300
Supervision fees		82,800		108,100
Transportation fees		7,500		14,400
Direct costs		37,800		53,800
Total	$	147,500	$	201,600

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s balance sheets includes the net production expense due to the MGP.

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 March 31, 2016, the MGP withheld $420,700 of net production revenue for future plugging and abandonment costs.

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.

When used in this Form 10-Q, the words “believes”, “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. Such statements are subject to certain risks and uncertainties, which could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.

Atlas America Public #11-2002 LTD. (“we”, “us”, or the “Partnership”) is a Delaware limited partnership, formed on June 5, 2002 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). Unless the context otherwise requires, references to “the Partnership,” “we,” “us” and “our”, refer to Atlas America Public #11-2002 LTD.

Atlas Energy Group, LLC manages ARP’s operations and activities through its ownership of the ARP’s general partner interest.

We have drilled and currently operate wells located in Pennsylvania and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Group, for administrative services.

We intend to continue to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. We expect that no other wells will be drilled and no additional funds will be required for drilling.

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which produce primarily natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of March 31, 2016, our MGP withheld $420,700 of net production revenues for this purpose.

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas and oil producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2016 and 2015, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended March 31,
	2016			2015
Production revenues (in thousands):
Gas	$	58		$	116
Oil		6			7
Liquids		1			1
Total	$	65		$	124
Production volumes:
Gas (mcf/day) ⁽¹⁾		455			557
Oil (bbl/day) ⁽¹⁾		2			2
Liquids (bbl/day) ⁽¹⁾		-			-
Total (mcfe/day) ⁽¹⁾		467			569
Average sales prices: ⁽²⁾
Gas (per mcf) ⁽¹⁾	$	1.39		$	2.54
Oil (per bbl)	$	31.34		$	43.85
Liquids (per bbl) ⁽¹⁾	$	18.73		$	35.61
Production costs:
As a percent of revenues		177	%		131	%
Per mcfe ⁽¹⁾	$	2.67		$	3.16
Depletion per mcfe	$	-		$	0.07

Natural Gas Revenues. Our natural gas revenues were $57,600 and $115,800 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $58,200 (50%). The $58,200 decrease in natural gas revenues for the three months ended March 31, 2016 as compared to the prior year similar period was attributable to a $38,300 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions, and a $19,900 decrease in production volumes. Our production volumes decreased to 455 mcf per day for the three months ended March 31, 2016 from 557 mcf per day for the three months ended March 31, 2015, a decrease of 102 mcf per day (18%). The decrease in production volumes is mostly due to the normal decline inherent in the life of the wells in addition to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

Oil Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $6,500 and $7,000 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $500 (7%). The $500 decrease in oil revenues for the three months ended March 31, 2016 as compared to the prior year similar period was attributable to a $2,600 decrease in oil prices, partially offset by a $2,100 increase in production volumes. Our production volumes increased to 2.27 bbls per day for the three months ended March 31, 2016 from 1.76 bbls per day for the three months ended March 31, 2015, an increase of 0.51 bbls per day (29%).

Natural Gas Liquids Revenue. The majority of our wells produce “dry gas”, which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas”, which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $500 and $900 for the three months ended March 31, 2016 and 2015, respectively. Our production volumes were 0.32 and 0.29 bbls per day for the three months ended March 31, 2016 and 2015, respectively.

Gain on Mark-to-Market Derivatives. On January 1, 2015, we discontinued hedge accounting for our qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain on mark-to-market derivatives on our statements of operations. The fair values of these commodity derivative instruments as of December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on our balance sheet, will be reclassified to our statements of operations in the future at the time the originally hedged physical transactions settle.

We recognized a gain on mark-to-market derivatives of $2,900 and $2,500 for the periods ended March 31, 2016 and 2015, respectively. These gains were due to mark-to-market gains primarily related to the change in natural gas prices during the periods.

Costs and Expenses. Production expenses were $114,300 and $162,000 for the three months ended March 31, 2016 and 2015, respectively, a decrease of $47,700 (29%). This decrease was mostly attributable to a decrease in supervision fees due to wells being shut-in and a decrease in transportation.

For the three months ended March 31, 2016, there was no depletion recorded due to the recent significant declines in commodity prices and associated recorded impairment charges. Therefore, the remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. For the three months ended March 31, 2015, depletion of gas and oil properties as a percentage of gas and oil revenues was 3%.

General and administrative expenses for the three months ended March 31, 2016 and 2015 were $33,200 and $39,600, respectively, a decrease of $6,400 (16%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs charged to us and services provided to us.

We are generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines throughout 2015 and have continued to decline and remain low in 2016. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact our outlook. We have experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. Our MGP continues to implement various cost saving measures to reduce our operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. Our MGP will continue to be opportunistic and aggressive in managing our cost structure and, in turn, liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate our operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations have been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our ability to continue as a going concern. To the extent commodity prices remain low or decline further, ARP experiences disruptions in the financial markets impacting its respective longer-term access to or cost of capital, or ARP experiences any of the other impacts to its liquidity discussed below, the MGP’s ability to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months, as necessary, may be impacted.

There was no cash provided by operating activities for the three months ended March 31, 2016 and 2015. The change in asset retirement receivable-affiliate decreased $99,000, the change in accounts receivable trade-affiliate decreased $75,700, and net earnings before depletion and accretion decreased $4,600. The change in accounts payable trade-affiliate increased $172,600, the change in non-cash gain (loss) on derivative value increase $3,800 and the change in accrued liabilities increase $2,900.

Our MGP may withhold funds for future plugging and abandonment costs. Through March 31, 2016, our MGP withheld $420,700 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

For a more complete discussion of the accounting policies and estimates that we have identified as critical in the preparation of our condensed consolidated financial statements, please refer to our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in the Partnership’s internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Delaware		02-0600231
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA		15275
(Address of principal executive offices)		(zip code)

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	x

		PAGE
PART I.	FINANCIAL INFORMATION (Unaudited)

Item 1:

	Condensed Balance Sheets as of March 31, 2016 and December 31, 2015	3

	Condensed Statements of Operations for the Three Months ended March 31, 2016 and 2015	4

	Condensed Statements of Comprehensive Loss for the Three Months ended March 31, 2016 and 2015	5

	Condensed Statement of Changes in Partners’ Deficit for the Three Months ended March 31, 2016	6

	Condensed Statements of Cash Flows for the Three Months ended March 31, 2016 and 2015	7

	Notes to Condensed Financial Statements	8

Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 4:	Controls and Procedures	16

PART II.	OTHER INFORMATION

Item 1:	Legal Proceedings	17

Item 6:	Exhibits	18

SIGNATURES		19

CERTIFICATIONS

Production Period Ending December 31,	Volumes	Average Fixed Price		Fair Value Asset ⁽²⁾
	(MMBtu) ⁽¹⁾		(per MMBtu)⁽¹⁾

2016	8,600	$	4.15	$	16,500

Exhibit No.		Description
4.0		Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #11-2002 LTD.⁽¹⁾

31.1		Certification Pursuant to Rule 13a-14/15(d)-14

31.2		Certification Pursuant to Rule 13a-14/15(d)-14

32.1		Section 1350 Certification

32.2		Section 1350 Certification

101		Interactive Data File

		ATLAS AMERICA PUBLIC #11-2002 LTD.

		By: Atlas Resources, LLC, its Managing General Partner

Date: May 23, 2016		By: /s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chief Executive Officer and President of the Managing General Partners