UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2014~~2015

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 000-52168

ATLAS AMERICA ~~Public~~PUBLIC #15-2006 (B) L.P.

(Exact name of registrant as specified in its charter)

Delaware		20-3208390
(State or other jurisdiction or incorporation or organization)		(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, Suite 400 Pittsburgh, PA		15275
(Address of principal executive offices)		Zip code

Registrant’s telephone number, including area code: (412) 489-0006

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
None		None

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Units representing Limited Partnership Interests

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 definitions of “large accelerated filer”, “accelerated filer”, and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company x

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

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

			Page
PART I	Item 1:	Business	6
	Item 2:	Properties	18
	Item 3:	Legal Proceedings	20
	Item 4:	Mine Safety Disclosures (Not Applicable)	20
PART II	Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	2021
	Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
	Item 8:	Financial Statements and Supplementary Data	2830
	Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
	Item 9A:	Controls and Procedures	48
PART III	Item 10:	Directors, Executive Officers and Corporate Governance	49
	Item 11:	Executive Compensation	50
	Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	5150
	Item 13:	Certain Relationships and Related Transactions	51
	Item 14:	Principal Accountant Fees and Services	51
PART IV	Item 15:	Exhibits	52
SIGNATURES			53

GLOSSARY OF TERMS

Bbl. One ~~stock~~barrel ~~tank~~of ~~barrel~~crude oil, condensate, or other liquid hydrocarbons equal to 42 United States gallons ~~liquid volume~~.

Bpd. Barrels per day.

Condensate. ACondensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. ~~Acres~~The ~~spaced~~number of acres which are allocated or ~~assigned~~assignable to ~~productive~~producing wells or wells capable of production.

Development well. A well drilled within athe proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. AnA ~~exploratory, development or extension~~ well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil ~~and~~or gas well.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

~~GAAP~~Fractionation. ~~Generally~~The ~~Accepted~~process ~~Accounting~~used ~~Principles.~~to separate a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles in the United States of America.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of crude oil, condensate, or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

~~NGL~~Natural Gas Liquids or NGLs —A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. ~~Natural~~NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas ~~liquids~~plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, ~~which~~propane, ~~are~~butanes) as well as the ~~hydrocarbon~~pentanes-plus ~~liquids~~(the ~~contained~~main ~~within~~constituent ~~gas.~~of condensates).

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

Oil. Crude oil and condensate.

Productive well. A producing well or a well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Proved developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved gas and oil reserves are those quantities of gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

~~PV-10.~~(i) ~~Present~~The ~~value~~area of ~~future net revenues. See~~ the ~~definition~~reservoir ofconsidered ~~“standardized~~as ~~measure”.~~proved includes:

(a)	The area identified by drilling and limited by fluid contacts, if any, and

(b)	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

~~Reserves.~~(ii) ~~Reserves~~In ~~are~~the ~~estimated~~absence ~~remaining quantities~~ of ~~gas~~data ~~and~~on ~~oil~~fluid ~~and related substances anticipated to be economically producible~~contacts, asproved ofquantities in a ~~given~~reservoir ~~date,~~are limited by ~~application~~the oflowest ~~development projects to~~ known ~~accumulations.~~hydrocarbons In(LKH) ~~addition,~~as ~~there~~seen ~~must~~in ~~exist, or there must be~~ a ~~reasonable~~well ~~expectation~~penetration ~~that~~unless ~~there will exist~~geoscience, ~~the legal right to produce or a revenue interest in the production~~engineering, ~~installed means of delivering gas and oil~~ or ~~related~~performance ~~substances~~data ~~to market,~~ and ~~all~~reliable ~~permits~~technology ~~and~~establishes ~~financing~~a ~~required~~lower tocontact ~~implement~~with ~~the~~reasonable ~~project~~certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(a)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(b)	The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure”.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful well. A well capable of producing gas and/or oil in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas and oil regardless of whether such acreage contains proved reserves.

Working interest. ~~The~~An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill, ~~produce~~for and ~~conduct~~produce ~~operating~~oil ~~activities~~and natural gas on the ~~property~~leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates, and projections. While we believe these expectations, assumptions, estimates, and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. The following and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

the demand for natural gas, oil, NGLs and condensate;

the price volatility of natural gas, oil, NGLs and condensate;

changes in the differential between benchmark prices for oil and natural gas and wellhead prices that we receive;

changes in the market price of our common units;

future financial and operating results;

resource potential;

economic conditions and instability in the financial markets;

the accuracy of estimated natural gas and oil reserves;

the financial and accounting impact of hedging transactions;

the limited payment of distributions, or failure to declare a distribution;

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations at a reasonable cost and within applicable environmental rules;

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

impact fees and severance taxes;

changes and potential changes in the regulatory and enforcement environment in the areas in which we conduct business;

the effects of intense competition in the natural gas and oil industry;

general market, labor and economic conditions and uncertainties;

the ability to retain certain key customers;

dependence on the gathering and transportation facilities of third parties;

the availability of drilling rigs, equipment and crews;

potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

uncertainties with respect to the success of drilling wells at identified drilling locations;

uncertainty regarding leasing operating expenses, general and administrative expenses and funding and development costs;

exposure to financial and other liabilities of the managing general partner;

the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our business and operations;

restrictions on hydraulic fracturing;

exposure to new and existing litigation;

development of alternative energy resources; and

· the effects of a cyber -event or terrorist attack.

Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments, except as may be required by law.

PART I.

ITEM 1: BUSINESS

Overview

Atlas America Public #15-2006 (B) L.P. (“we, “us” or the “Partnership”) is a Delaware limited partnership and was formed on May 9, 2006 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). ARP is a publicly traded master limited partnership and an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests, to finance a portion of its natural gas and oil production activities.

On ~~October~~February 1327, ~~2014~~2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”) ~~(NYSE: ATLS)~~, ~~and~~which ~~its~~was ~~midstream~~a ~~subsidiary,~~publicly ~~Atlas~~traded ~~Pipeline~~master-limited ~~Partners~~partnership, ~~L.P.~~was ~~(“APL”), entered into definitive agreements to be~~ acquired by Targa Resources Corp. and ~~Targa~~distributed ~~Resources Partners LP, respectively. Immediately prior~~ to ~~the acquisition,~~ Atlas Energy’s ~~distributed to its~~ unitholders 100% of the limited liability company interests in ARP’s general partner, ~~which changed its name to~~ Atlas Energy Group, LLC (“~~New~~ Atlas Energy Group”; OTCQX: ATLS). Atlas ~~and~~Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, ~~New~~ Atlas Energy Group continues to ~~hold~~manage ~~the Partnership’s business as well as~~ ARP’s ~~general~~operations ~~partner interest~~ and ~~incentive~~activities ~~distribution~~through ~~rights,~~its ~~and~~ownership ~~now~~of ~~holds~~ the ~~non-midstream assets and~~ ARP’s ~~limited~~general partner ~~units previously held by Atlas Energy~~interest.

InThe ~~March~~Partnership ~~2012,~~has ~~Atlas~~drilled ~~Energy~~and ~~contributed~~currently tooperate ~~ARP~~wells located in Pennsylvania, aTennessee ~~newly-formed~~and ~~exploration~~Ohio. We have no employees and ~~production~~rely ~~master~~on ~~limited~~our ~~partnership,~~MGP ~~substantially~~for ~~all~~management, ofwhich ~~Atlas~~in ~~Energy’s~~turn, ~~natural~~relies ~~gas~~on ~~and~~its ~~oil~~parent ~~development~~company, ~~and~~Atlas ~~production~~Energy ~~assets~~Group ~~and~~(February ~~its~~27, ~~partnership~~2015 ~~management~~and ~~business~~prior, ~~including~~Atlas ~~ownership~~Energy), offor ~~our~~administrative ~~MGP~~services. (See Item 11: “Executive Compensation”).

OnThe ~~February~~Partnership’s ~~17,~~operating ~~2011,~~cash ~~Atlas~~flows ~~Energy,~~are agenerated ~~then-majority~~from ~~owned~~its ~~subsidiary~~wells, ofwhich ~~Atlas~~produce ~~Energy,~~natural ~~Inc.~~gas and ~~parent~~oil. ofProduced ~~the~~natural ~~general~~gas ~~partner~~and ofoil ~~APL,~~is ~~completed~~then andelivered ~~acquisition~~to ofmarket ~~assets~~through ~~from~~affiliated ~~Atlas~~and/or ~~Energy,~~third-party ~~Inc.,~~gas ~~which~~gathering ~~included~~systems. ~~its~~The ~~investment~~Partnership ~~partnership~~intends ~~business,~~to produce its ~~gas~~wells ~~and~~until ~~oil~~they ~~exploration,~~are ~~development,~~depleted ~~and~~or ~~production~~become ~~activities~~uneconomical ~~conducted~~to inproduce ~~Tennessee,~~at ~~Indiana~~which ~~and~~time ~~Colorado,~~they ~~certain~~will ~~shallow~~be ~~wells~~plugged and ~~leases~~abandoned inor ~~New~~sold. ~~York~~The ~~and~~Partnership ~~Ohio,~~does ~~and~~not ~~certain~~expect ~~well~~to ~~interests~~drill inadditional ~~Pennsylvania~~wells and ~~Michigan~~expects ~~and~~no ~~its~~additional ~~ownership~~funds ~~and~~will ~~management~~be ofrequired ~~investments~~for ~~in Lightfoot Capital Partners, L~~drilling.P. ~~and related entities (the “Transferred Business”).~~

~~After~~The ~~formation,~~economic weviability ~~received~~of ~~total~~the ~~cash~~Partnership’s ~~subscriptions~~production ~~from~~is ~~investors~~based on a variety of ~~$147,513,100,~~factors ~~which~~including ~~were~~proved ~~paid~~developed toreserves ~~our~~that ~~MGP~~it ~~acting~~can asexpect ~~operator~~to ~~and~~recover ~~general~~through ~~drilling~~existing ~~contractor~~wells ~~under~~with ~~our~~existing ~~drilling~~equipment and operating ~~agreement.~~methods ~~Our~~or ~~MGP~~in ~~contributed~~which ~~leases,~~the ~~tangible~~cost of additional required extraction equipment, ~~and~~is ~~paid~~relatively ~~all~~minor ~~syndication~~compared ~~and~~to ~~offering~~the ~~costs~~cost ~~for~~of a ~~total~~new ~~capital~~well; ~~contribution~~and ofthrough ~~$52,509,500.~~currently Weinstalled ~~have~~extraction ~~drilled~~equipment ~~551~~and ~~development~~related ~~wells~~infrastructure ~~within~~which is operational at the ~~Clinton/Medina,~~time ~~Upper~~of ~~Devonian~~the ~~Sandstones~~reserves estimate (if the extraction is by means not involving drilling, ~~Southern~~completing ~~Appalachia~~or ~~Shale~~reworking ~~and~~a ~~Marcellus~~well). ~~Shale~~There ~~geological~~are ~~formations~~numerous uncertainties inherent in ~~Pennsylvania,~~estimating ~~Tennessee~~quantities of proven reserves and ~~Ohio.~~in projecting future net revenues.

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

Historically, there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations and distributions to the partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.

After formation, we received total cash subscriptions from investors of $147,513,100, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $52,509,500. We have drilled 551 development wells within the Clinton/Medina, Upper Devonian Sandstones, Southern Appalachia Shale and Marcellus Shale geological formations in Pennsylvania, Tennessee, and Ohio.

We have drilled and currently operate wells located in Pennsylvania, Tennessee and Ohio. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy (after February 27, 2015, New Atlas), for administrative services. (See Item 11: “Executive Compensation”).

Business Strategy

We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling (See Item 2: Properties” for information concerning our wells).

The MGP continues to manage our exposure to commodity price risk. To limit our exposure to changing commodity prices and enhance and stabilize our cash flow, our MGP uses financial hedges for a portion of our natural gas ~~and oil~~ production. Principally, the MGP uses fixed price swaps and puts on our behalf as the mechanism for the financial hedging of our commodity prices.

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The majority of our natural gas is delivered into the Laurel Mountain Midstream, LLC (“Laurel Mountain”) gas gathering system. ~~Laurel Mountain owns and operates all of APL’s previously owned Northern Appalachian assets.~~ Our MGP entered into new gas gathering agreements with Laurel Mountain, whereby they pay to Laurel Mountain a gathering fee based on a range, generally from $0.35 per Mcf to the amount of the competitive gathering fee which is currently defined as 16% of the gross sales price received for our gas.

Our ongoing operating and maintenance costs have been ~~and~~or are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We ~~pay~~are charged by our MGP a monthly well supervision fee of $296 per well per month as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

●

Well tending, routing maintenance and adjustment;

●

Reading meters, recording production, pumping, maintaining appropriate books and records; and

●

Preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment and materials and brine disposal. If these expenses are incurred, we ~~pay~~are charged the costs 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 cost of the well. As of December 31, ~~2014~~2015, our MGP withheld $95140,~~100~~500 of net production revenue for this purpose.

Gas and Oil Production

Production Volumes

The following table presents our total net natural gas and oil production volumes for the years ended December 31, ~~2014~~2015 and ~~2013~~2014:

	Years Ended December 31,
	2014		2013
	2015		2014
Production:(1)
Natural gas (Mcf)		1986,~~154,044~~066		1,~~278~~154,~~951~~044
Oil (Bbl)		21,~~499~~730		32,~~012~~499
Total (Mcfe)		1996,~~169,038~~446		1,~~297~~169,~~023~~038

(1)

Production quantities consist of the sum of our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells.

Production Revenues, Prices and Costs

The MGP markets the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline and Transco Leidy Line.

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas. The following table presents our production revenues and average sales prices for our natural gas and oil production for the years ended December 31, 2014 and 2013, along with our average production costs in each of the reported periods: 7

	Years Ended December 31,
	2014		2013
Production revenues (in thousands):
Natural gas revenue	$	4,184	$	4,875
Oil revenue		224		281
Total revenues	$	4,408	$	5,156
Average sales price: (1)
Natural gas (per Mcf) (2)	$	3.69	$	4.12
Oil (per Bbl)	$	89.37	$	93.22
Production costs (per Mcfe)	$	2.36	$	2.35

Our production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas. The following table presents our production revenues and average sales prices for our natural gas and oil production for the years ended December 31, 2015 and 2014, along with our average production costs in each of the reported years:

	Years Ended December 31,
	2015		2014
Production revenues (in thousands):
Natural gas revenue	$	1,619	$	4,184
Oil revenue		78		224
Total revenues	$	1,697	$	4,408
Average sales price:⁽¹⁾
Natural gas (per Mcf) ⁽²⁾	$	1.64	$	3.69
Oil (per Bbl)	$	45.36	$	89.37

Production costs (per Mcfe)	$	2.05	$	2.36

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(2) Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $79,600 ~~and $399,400~~ for the ~~years~~year ended December 31, 2014 ~~and 2013, respectively~~.

Drilling Activity

We received total cash subscriptions from investors of $147,513,100, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $52,509,500. We have drilled 551 development wells within the Clinton/Medina, Upper Devonian Sandstones, Southern Appalachia Shale and Marcellus Shale geological formations in Pennsylvania, Tennessee and Ohio~~, respectively~~. We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by the Partnership:

	Gross		Net
Gas and/or oil wells drilled		546.00		496.92
Dry hole		5.00		5.00
Total wells drilled		551.00		501.92

Natural Gas and Oil Leases

The MGP has contributed all the undeveloped leases or lease interests necessary to drill each of the partnership’s wells. The MGP has received a credit to its capital account equal to the cost of each lease or the fair market value of each lease if the MGP has reason to believe that cost is materially more than the fair market value.

Contractual Revenue Arrangements

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically linked to a regional index. The pricing indices for the majority of our production areas are as follows:

Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5.

We attempt to sell the majority of our natural gas at monthly, fixed index prices and a smaller portion at index daily prices.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

For the year ended December 31, ~~2014~~2015, Chevron Natural Gas and Atmos Energy Marketing LLC accounted for approximately 6362% and 1116%, respectively, of our total natural gas, oil, and NGL production revenues, with no other single customer accounting for more than 10% of revenues for this period.

9Natural Gas Hedging

~~Natural~~The ~~Gas~~MGP provides greater stability in our cash flows through its use of financial hedges for our natural gas production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with the MGP’s secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, ~~Oil~~the MGP has a management committee to assure that all financial trading is done in compliance with its hedging policies and ~~NGL~~procedures. ~~Hedging~~The MGP does not intend to contract for positions that we cannot offset with actual production.

The MGP provides greater stability in our cash flows through its use of financial hedges for our natural gas, oil and natural gas liquids production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with the MGP’s secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the MGP has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. The MGP does not intend to contract for positions that we cannot offset with actual production.

Natural Gas Gathering Agreements

Virtually all natural gas produced is gathered through one or more pipeline systems before sale or delivery to a marketer or an interstate pipeline. A gathering fee can be charged for each gathering activity that is utilized and by each separate gatherer providing the service. Fees will vary depending on the distance the gas travels and whether additional services such as compression, blending, or contaminant removal are provided.

In Appalachia, we have gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”). Under these agreements, we dedicate our natural gas production in certain areas within southwest Pennsylvania to Laurel Mountain for transportation to interstate pipeline systems or local distribution companies, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas subject to certain conditions. The greater of $0.35 per mcf or 16% of the gross sales price of the natural gas is charged by Laurel Mountain for the majority of the gas. A lesser fee does apply to a small number of specific wells in the area.

Competition

We operate in a highly competitive environment for acquiring properties and other energy companies, attracting capital, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for mineral property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. Our competitors may be able to pay more for hydrocarbon properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, crude oil, and natural gas liquids. Many of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their hydrocarbon production more effectively than we do.

Markets

The availability of a ready market for natural gas, oil and natural gas liquids and the price obtained, depends upon numerous factors beyond our control. Product availability and price are the principal means of competition in selling natural gas, oil and NGLs. During the years ended December 31, ~~2014~~2015 and ~~2013~~2014, we did not experience problems in selling our natural gas, oil and NGLs, although prices have varied significantly during those periods.

109

Seasonal Nature of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations.

Environmental Matters and Regulation

~~Overview.~~ Our operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

restricting the way waste disposal is handled;

limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by threatened or endangered species;

requiring the acquisition of various permits before the commencement of drilling;

requiring the installation of expensive pollution control equipment and water treatment facilities;

restricting the types, quantities and concentration of various substances that can be released into the environment in connection with siting, drilling, completion, production, and plugging activities;

requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;

imposing substantial liabilities for pollution resulting from operations; and

requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

We believe that our operations are in substantial compliance with applicable environmental laws and regulations, and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

Environmental laws and regulations that could have a material impact on our operations include the following:

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“USEPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that USEPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that ~~they~~we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that they are required under such laws and regulations. Although we do not believe the current costs of managing wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase the costs to manage and dispose of such wastes.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. However, none of these spills or releases appears to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by USEPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of our natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

On April 21, 2014, the U.S. Army Corps of Engineers and USEPA proposed a rule that would define ‘Waters of the United States,’ i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers). The U.S. Army Corps of Engineers and USEPA have stated that the proposed rule would enhance protection for nationwide public health and aquatic resources, and increase Clean Water Act program predictability and consistency. The public comment period concluded on November 14, 2014. USEPA is in the process of reviewing the more than 800,000 comments received on the proposed rule, and has indicated that a final rule may be issued in 2015. As drafted, this proposed rule may increase the costs of compliance and result in additional permitting requirements for some of our existing or future facilities. Additionally, USEPA’s Science Advisory Board released its review of USEPA’s Office of Research and Development’s draft “Connectivity of Streams and Wetlands to Downstream Waters: A Review and Synthesis of the Scientific Evidence” report issued October 17, 2014. USEPA released the final report publicly on January 15, 2015.11

On April 21, 2014, the U.S. Army Corps of Engineers (“USACE”) and USEPA proposed a rule that would define ‘Waters of the United States’ (“WOTUS”), i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers). The public comment period concluded on November 14, 2014 and USEPA received hundreds of thousands of comments on the proposed rule. On May 27, 2015, USEPA and USACE announced the final rule redefining the extent of the agencies’ jurisdiction over WOTUS, and the final rule was published in the Federal Register on June 29, 2015 with an effective date of August 28, 2015. The final rule was immediately challenged by multiple parties, including individual states, in both United States District Courts and U.S. Circuit Courts of Appeals. On October 9, 2015, the 6^th Circuit Court of Appeals found that the petitioners, totaling 18 states, demonstrated a “substantial possibility of success on the merits of the claim” and issued a nationwide stay of the WOTUS final rule. Currently, this nationwide stay is in place and the litigation in both the U.S. District and Circuit Courts is ongoing. Additionally, there have been legislative efforts by the General Assembly to nullify the rule, specifically a joint resolution of Congress passed under authority of the Congressional Review Act that was vetoed by President Obama on January 19, 2016. As drafted, the final rule is broader in scope then the current rule, and will increase the costs of compliance and result in additional permitting requirements for some of our existing or future facilities.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Such laws and regulations may require obtaining pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions,. ~~obtain~~Air ~~and comply with air~~ permits ~~containing~~contain various emissions and operational limitations, orand ~~utilize~~may require specific emission control technologies to limit emissions. Various air quality regulations are periodically reviewed by USEPA and are amended as deemed necessary. USEPA may also issue new regulations based on changing environmental concerns.

Recent revisions to federal ~~NSPS~~Clean ~~and~~Air ~~NESHAP~~Act rules impose additional emissions control requirements and practices on our operations. ~~Some~~New offacilities, ~~our~~if ~~new~~any, ~~facilities~~ may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations.

While we will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions, we believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

OSHA and Other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA”, and comparable state statutes. The OSHA hazard communication standard, USEPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

~~Greenhouse~~On ~~Gas~~October ~~Regulation~~22, ~~and Climate Change. To date~~2015, ~~legislative~~USEPA ~~and~~responded ~~regulatory initiatives relating~~ to ~~greenhouse~~an ~~gas~~October ~~emissions~~24, ~~have~~2012 ~~not~~petition ~~had~~to aUSEPA ~~material~~requesting ~~impact~~that onthe ~~our~~oil ~~business.~~and ~~However,~~gas ~~Congress~~extraction ~~has~~industrial ~~been~~sector ~~actively~~be ~~considering~~added ~~climate~~to ~~change~~the ~~legislation.~~sectors ~~More~~with ~~directly,~~reporting ~~USEPA~~requirements ~~has~~covered ~~begun~~by ~~regulating~~Section ~~greenhouse~~313 ~~gas~~of ~~emissions under~~ the ~~Clean~~Emergency ~~Air~~Planning ~~Act.~~and InCommunity ~~response~~ Right-to-Know Act (the ~~Supreme~~Toxics ~~Court’s~~Release ~~decision~~Inventory inor ~~Massachusetts v~~“TRI”). ~~EPA,~~In ~~549~~its ~~U.S.~~response, ~~497~~USEPA ~~(2007)~~stated ~~(holding~~ that ~~greenhouse~~it ~~gases~~intends ~~are~~to ~~air~~propose ~~pollutants~~a ~~covered~~rulemaking bythat ~~the~~would ~~Clean~~subject ~~Air~~natural ~~Act),~~gas ~~USEPA~~processing ~~made~~facilities ~~a final determination~~ that ~~greenhouse~~employ ~~gases~~more ~~endangered~~than ~~public~~10 ~~health~~people ~~and~~to ~~welfare,~~annual 74TRI ~~Fed. Reg. 66~~reporting,~~496~~ ~~(December~~but ~~15,~~that ~~2009).~~USEPA ~~This~~will ~~finding~~not ~~led~~propose tothat ~~the~~well ~~regulation~~sites, ofcompressor ~~greenhouse~~stations, ~~gases~~pipelines, ~~under~~and ~~the~~other ~~Clean~~oil ~~Air~~and ~~Act.~~gas ~~Currently,~~extraction ~~USEPA~~industrial ~~has~~sector ~~promulgated~~facilities ~~two~~be ~~rules~~subject ~~that~~to ~~will~~TRI ~~affect our businesses~~reporting.

First, USEPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010). Both the federal preconstruction review program, known as “PSD”, and the operating permit program are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain the requisite operating permits. 12

~~On June 23~~Additionally, ~~2014,~~ the ~~United~~White ~~States~~House ~~Supreme~~Office ~~Court~~of ~~ruled~~Management onand ~~challenges~~Budget toreceived ~~the~~OSHA’s ~~Tailoring~~final ~~Rule~~“Occupational inExposure ~~the~~to ~~case~~Crystalline ofSilica” ~~Utility~~rule ~~Air~~on ~~Regulatory~~December ~~Group~~21, v2015. ~~EPA,~~The ~~134~~final S.rule ~~Ct.~~has ~~2427~~not ~~(2014).~~been ~~The~~published, ~~Court~~but ~~limited~~is ~~the~~expected ~~applicability~~to offollow ~~the~~OSHA’s ~~PSD~~proposed ~~program~~rule ~~and~~from ~~Tailoring~~September ~~Rule~~12, to2013 ~~only~~that ~~new~~would ~~sources~~impose ora ~~modifications~~new ~~that~~exposure ~~would~~limit ~~trigger~~for ~~PSD~~silica ~~for~~and ~~another~~with ~~criteria~~it ~~pollutant~~various ~~such~~new ~~that~~requirements. ~~projects~~The ~~cannot~~federal ~~trigger~~2015 ~~PSD~~Fall ~~based~~Unified ~~solely~~Agenda onand ~~greenhouse~~Regulatory ~~gas~~Plan ~~emissions.~~lists ~~However,~~February if2016 ~~PSD~~as isthe ~~triggered~~target release date for ~~another~~the ~~pollutant,~~final ~~greenhouse~~rulemaking. ~~gases~~OSHA ~~could~~has bepreviously ~~subject~~addressed torespirable asilica ~~control~~from ~~technology~~the ~~review~~oil ~~process.~~and ~~The~~gas ~~Court’s~~industry ~~decision~~operations ~~also~~back ~~means~~in ~~that~~December ~~sources~~2014 ~~cannot~~when ~~trigger~~it released a ~~federal~~“Hydraulic ~~operating~~Fracturing ~~permit~~and ~~requirement~~Flowback ~~based~~Hazards ~~solely~~Other onthan ~~greenhouse~~Respirable ~~gas~~Silica” ~~emissions~~safety alert. ~~Overall~~If finalized, wethe ~~expect~~rule ~~that~~would ~~the~~likely ~~Tailoring~~result ~~Rule~~in ~~after~~significant costs for the ~~Court’s~~oil ~~decision~~and isgas ~~unlikely~~industry to ~~have~~comply ~~much,~~with ifthe ~~any,~~new ~~impact on our operations~~requirements.

~~Second, USEPA finalized its Mandatory Reporting of~~ Greenhouse ~~Gases~~Gas ~~rule~~Regulation inand ~~2009,~~Climate ~~74 Fed~~Change. ~~Reg.~~To 56date,~~260~~ ~~(October~~legislative ~~30,~~and ~~2009).~~regulatory ~~Subsequent~~initiatives ~~revisions,~~relating ~~additions~~to ~~and~~greenhouse ~~clarification~~gas ~~rules~~emissions ~~were~~have ~~promulgated,~~not ~~including~~had a ~~rule~~material ~~specifically~~impact ~~addressing~~on ~~the~~our ~~natural~~business. ~~gas~~However, ~~industry.~~Congress ~~This~~has ~~subpart~~been ~~was~~actively ~~most~~considering ~~recently~~climate ~~revised~~change inlegislation. ~~November~~More ~~2014~~directly, ~~when~~ USEPA ~~finalized~~has ~~changes~~begun toregulating ~~calculation~~greenhouse ~~methods,~~gas ~~monitoring~~emissions ~~and~~under ~~data~~the ~~reporting~~federal ~~requirements,~~Clean ~~and~~Air ~~other provisions~~Act. ~~Shortly~~ ~~thereafter,~~In inresponse ~~December~~to ~~2014,~~the ~~USEPA~~Supreme ~~proposed~~Court’s ~~additional~~decision ~~revisions~~in toMassachusetts ~~this subpart for public comment~~v. In ~~general~~EPA, ~~the~~549 ~~Greenhouse~~U.S. ~~Gas~~497 ~~Reporting~~(2007) ~~Rule~~(holding ~~requires certain industry sectors~~ that ~~emit~~ greenhouse gases ~~above~~are aair ~~specified~~pollutants ~~threshold~~covered toby ~~report~~the ~~greenhouse~~Clean ~~gas~~Air ~~emissions~~Act), to USEPA onmade ana ~~annual~~final ~~basis.~~determination ~~The~~that ~~natural~~greenhouse ~~gas~~gases ~~industry~~endangered ispublic ~~covered~~health byand ~~the~~welfare, ~~rule~~74 ~~and~~Fed. ~~requires~~Reg. ~~annual~~66,496 ~~greenhouse~~(Dec. ~~gas~~15, ~~emissions~~2009). toThis befinding ~~reported~~led byto ~~March~~the 31regulation of ~~each~~greenhouse ~~year~~gases ~~for~~under the ~~emissions~~Clean ~~during~~Air ~~the preceding calendar year~~Act. ~~This~~Currently, ~~rule~~USEPA ~~imposes~~has ~~additional~~promulgated ~~obligations~~two onfinal usrules relating to ~~determine whether the~~ greenhouse ~~gas~~gases ~~reporting~~that ~~applies~~will ~~and~~affect ifour ~~so, to calculate and report greenhouse gas emissions~~businesses.

InFirst, ~~addition~~USEPA topromulgated ~~these~~the ~~existing~~so-called ~~rules,~~“Tailoring ~~the~~Rule” ~~Obama~~which ~~Administration~~established ~~announced~~emission inthresholds ~~January~~for ~~2015~~greenhouse ~~that~~gases itunder isthe ~~developing~~Clean ~~additional~~Air ~~rules~~Act topermitting ~~curb~~programs, ~~greenhouse~~75 ~~gas~~Fed. ~~emissions~~Reg. ~~from~~31,514 (June 3, 2010). Both the ~~oil~~federal ~~and~~preconstruction ~~gas~~review ~~sector~~program, known as ~~part~~“Prevention of aSignificant ~~new~~Deterioration” ~~national~~(“PSD”), ~~strategy~~and ~~for~~the ~~reducing~~operating ~~methane~~permit ~~emissions~~program ~~from~~are ~~the~~now ~~sector~~implicated by 40emissions –of ~~45%~~greenhouse ~~from~~gases. ~~2012~~These ~~levels~~programs, as modified by the ~~year~~Tailoring ~~2025.~~Rule, ~~Among~~could ~~other~~require ~~steps~~some ~~being~~new ~~taken~~facilities asto ~~part~~obtain ofa ~~this~~PSD ~~national~~permit ~~methane~~depending ~~strategy,~~on ~~USEPA~~the issize ~~expected~~of tothe ~~build~~new onfacilities. ~~the~~In ~~2012~~addition, ~~NSPS~~existing infacilities aas ~~rulemaking~~well ~~action~~as ~~aimed~~new atfacilities ~~reducing~~that ~~both~~exceed ~~methane~~the ~~and~~emissions ~~VOC~~thresholds ~~emissions~~could ~~from~~be ~~the~~required ~~oil~~to ~~and~~obtain ~~gas~~the ~~sector~~requisite operating permits.

On June 23, 2014, the United States Supreme Court ruled on challenges to the Tailoring Rule in the case of Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014). The Court limited the applicability of the PSD program and Tailoring Rule to only new sources or modifications that would trigger PSD for another criteria pollutant such that projects cannot trigger PSD based solely on greenhouse gas emissions. However, if PSD is triggered for another pollutant, greenhouse gases could be subject to a control technology review process. The Court’s decision also means that sources cannot trigger a federal operating permit requirement based solely on greenhouse gas emissions. Overall, the impact of the Tailoring Rule after the Court’s decision is that it is unlikely to have much, if any, impact on our operations. However, USEPA is still in the process of responding to the Court’s decision through rulemakings.

Second, USEPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (Oct. 2009). Subsequent revisions, additions and clarifications were promulgated, including a rule subpart specifically addressing the natural gas industry. This particular subpart was most recently revised in October 2015, 80 Fed. Reg. 64262 (Oct. 22, 2015), when USEPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions. Shortly thereafter, in January 2016, USEPA proposed additional revisions to the broader Greenhouse Gas Reporting for public comment. In general, the Greenhouse Gas Reporting Rule requires certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to USEPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

In addition to these existing rules, the Obama Administration announced in January 2015 that it was developing additional rules to curb greenhouse gas emissions from the oil and gas sector, as part of a new national strategy for reducing methane emissions from the sector by 40 – 45% from 2012 levels by the year 2025. This national methane reduction strategy targeting the oil and gas sector is related to the Obama Administration’s broader Climate Action Plan of 2013. Multiple federal agencies, including USEPA and the U.S. Department of the Interior’s Bureau of Land Management, which we refer to as the BLM, are involved in implementing the national methane reduction strategy.

In August 2015, USEPA proposed a broad suite of regulatory measures to implement the national methane reduction strategy, as well as to reduce emissions of ozone-forming volatile organic compounds (“VOCs”) and clarify air permitting requirements for the oil and gas sector. The proposed measures include: (1) a revised New Source Performance Standards (“NSPS”) rule for oil and natural gas production, transmission, and distribution that would expand existing requirements for sources of VOCs and establish new requirements for sources of methane; (2) draft Control Techniques Guidelines that direct states to adopt regulations for reducing VOC emissions from existing oil and gas facilities in certain ozone nonattainment areas and states in the Ozone Transport Region; (3) a Federal Implementation Plan for certain oil and gas operations located in Indian country; and (4) a rule defining the circumstances in which oil and gas equipment and activities are to be considered part of a source that is subject to “major source” permitting requirements under the Clean Air Act. USEPA accepted public comments on these proposals through early December 2015. The proposals are expected to be finalized in 2016.

Consistent with the Obama Administration’s methane reduction strategy, on January 22, 2016, BLM released a proposed rule to update standards for venting, flaring, and equipment leaks from oil and gas production activities on onshore Federal and Indian leases. BLM’s existing requirements are more than three decades old. According to BLM, the proposed rule would ensure that operators use modern best practices to minimize waste of produced natural gas and reduce emissions of methane and VOCs.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus, future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

14In addition to domestic regulatory developments, the United States is a participant in multi-national discussions intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements (e.g., the “Paris Agreement”, reached at the United Nations Conference on Climate Change in December 2015) that could have an impact on our business.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussions intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our business.

Finally, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our business, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

Energy Policy Act. Much of our natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974, or ~~the~~ “SDWA”. This amendment effectively excluded hydraulic fracturing for oil, gas or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on our business and operations. For instance, USEPA ~~published a draft “Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels” on May 10, 2012. In February 2014, USEPA~~ released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels in February 2014, along with responses to selected substantive public comments on USEPA’s previous draft guidance, a fact sheet and a memorandum to USEPA’s regional offices regarding implementation of the guidance. The process for implementing USEPA’s final guidance document may vary across states depending on the regulatory authority responsible for implementing the SDWA UIC program in each state.

The U.S. Senate and House of Representatives considered legislative bills in the 111th, 112th, and 113th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act,” or “Frac Act”, the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. IfThe Frac Act was re-introduced in the current 114th Session of Congress and referred to the Committee on Environment and Public Works; if enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording and recordkeeping requirements for us.

We believe our operations are in substantial compliance with existing SDWA requirements. However, future compliance with the SDWA could result in additional requirements and costs due to the possibility that new or amended laws, regulations or policies could be implemented or enacted in the future.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. WeThe ~~employ~~MGP employs numerous safety precautions at ~~its~~our operations to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our ~~or its~~ wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2015, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.

~~State~~States ~~Regulation~~may ~~and~~regulate ~~Taxation~~rates of ~~Drilling.~~production ~~The~~and ~~various~~may ~~states~~establish ~~regulate~~maximum ~~the~~limits ~~drilling~~on ~~for,~~daily ~~and the~~ production, ~~gathering~~allowable ~~and~~from ~~sale of,~~ natural gas, ~~including~~wells ~~imposing~~based ~~severance~~on ~~taxes~~market ~~and~~demand ~~requirements~~or ~~for~~resource ~~obtaining~~conservation, ~~drilling~~or ~~permits~~both. ~~For~~States ~~example,~~do ~~Pennsylvania~~not ~~has~~regulate ~~imposed~~wellhead anprices ~~impact~~or ~~fee~~engage onin ~~wells~~other ~~drilled~~similar ~~into~~direct aneconomic ~~unconventional formation~~regulation, ~~which~~but ~~includes~~there ~~the~~can ~~Marcellus~~be ~~Shale.~~no ~~The~~assurance ~~impact~~that ~~fee,~~they ~~which~~will ~~changes~~not ~~from~~do ~~year~~so toin ~~year, is based on~~ the ~~average~~future. ~~annual~~The ~~price~~effect of ~~natural~~these ~~gas~~regulations asmay ~~determined~~be byto ~~the~~limit ~~NYMEX price, as reported by~~ the ~~Wall~~amounts ~~Street Journal for the last trading day~~ of ~~each calendar month. For example, based upon~~ natural gas ~~prices~~that ~~for~~may ~~2014,~~be ~~the~~produced ~~impact~~from ~~fee~~our ~~for qualifying unconventional horizontal~~ wells ~~spudded during 2014 was $50~~,~~300~~ ~~per well, while~~ the ~~impact~~type ~~fee~~of ~~for unconventional vertical~~ wells ~~was~~that ~~$10,100~~may ~~per~~be ~~well.~~drilled ~~The~~in ~~payment structure for~~ the ~~impact~~future ~~fee~~in ~~makes~~proximity ~~the~~to ~~fee~~existing ~~due~~wells ~~the year after an unconventional well is spudded,~~ and ~~the~~to ~~fee~~limit ~~will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate~~ the ~~method~~number of ~~developing new fields, the spacing and operation of~~ wells ~~and~~or ~~the~~locations ~~prevention~~from ofwhich ~~waste~~we ofcan ~~natural gas resources~~drill.

States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The ~~effect~~petroleum ofindustry ~~these~~is ~~regulations~~also ~~may~~subject be to ~~limit~~compliance ~~the~~with ~~amounts~~various ofother ~~natural gas that may be produced from our wells~~federal, ~~the~~state ~~type of wells that may be drilled in the future in proximity to existing wells~~ and tolocal ~~limit~~regulations ~~the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate~~ and ~~oil produced and an oil field clean up regulatory fee of $0~~laws.~~000667~~ ~~per~~Some ~~Mcf~~ of ~~gas~~those ~~produced~~laws ~~and~~relate ~~$.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up~~ to ~~3.75%~~occupational ~~of the value of oil and gas produced~~safety, aresource conservation ~~tax of up to 0.24% of the oil~~ and ~~gas~~equal ~~sold,~~employment ~~and a school emergency tax of up to 3~~opportunity.~~15%~~ ~~for~~We ~~oil~~do ~~and~~not 4%believe ~~for~~that ~~gas.~~compliance ~~Alabama~~with ~~imposes~~these alaws ~~production~~will ~~tax~~have ~~of up to 2% on oil or gas and~~ a ~~privilege~~material ~~tax~~adverse ofeffect ~~up to 8%~~ on ~~oil~~our ~~or gas~~business. ~~Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 7% per Mcf of natural gas and a petroleum excise tax of $0.095 on the gross production of oil and gas.~~

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Oil Spills and Hydraulic Fracturing. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

A number of federal agencies, including USEPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, USEPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. On December 9, 2013, USEPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with USEPA’s study were published in July 2014. On June 4, 2015, the EPA released its draft “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” (the “Draft Assessment”), in addition to nine new peer-reviewed scientific reports that formed the basis for certain findings included in the Draft Assessment. The scope of the Draft Assessment focuses on potential impacts to drinking water resources by hydraulic fracturing, specifically the following water activities that the EPA has identified as the “hydraulic fracturing water cycle” in the Draft Assessment: water acquisition from ground or surface waters; chemical mixing at the well site; well injection of hydraulic fracturing fluids; the collection and handling of wastewater from hydraulic fracturing (such as flowback and produced water); and wastewater treatment and waste disposal. The EPA revealed in its Draft Assessment that it has not found any evidence that hydraulic fracturing activities are performed in a way that leads to widespread, systemic impacts on drinking water resources. The EPA did identify specific instances where hydraulic fracturing activities may have led to impacts to drinking water; however, the EPA noted that those instances are minimal when compared to the number of hydraulically fractured wells in the United States. Notice of the Draft Assessment was published in the June 5, 2015 Federal Register, and several public teleconference calls and a public meeting were held by the USEPA’s Science Advisory Board (SAB) to discuss the Draft Assessment. On January 7, 2016, the SAB released a Draft Review of the USEPA’s Draft Assessment. The Draft Review includes many recommendations to USEPA that SAB believes USEPA should consider to improve the Draft Assessment. These recommendations include, but are not limited to: revising its draft finding that USEPA found no “evidence that hydraulic fracturing mechanisms have led to widespread, systemic impacts on drinking water resources,” as the SAB found the statement to be ambiguous and therefore require clarification and additional explanation; adding further discussion on the Pavillion, Wyoming; Parker County, Texas; and Dimock, Pennsylvania investigations; collecting and add new data regarding the chemicals used during hydraulic fracturing and the content of flowback water; and adding Best Management Practices and suggested improvements to each stage of the hydraulic fracturing process.

BLM proposed a rule on May 11, 2012 that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, BLM published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. On March 26, 2015, BLM issued a final rule updating the regulations governing hydraulic fracturing on federal and Indian lands. Among the many new requirements, the final rule requires operators planning to conduct hydraulic fracturing to design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, as well as requires operators to monitor cementing operations during well completion. Additionally, the final rule requires that companies publicly disclose the chemicals used in the hydraulic fracturing process, subject to limited exceptions for trade secret materials; comply with safety standards for storage of produced water in rigid enclosed, covered, or netted and screened above-ground tanks, with very limited exceptions allowing use of pits that must be approved by BLM on a case-by-case basis; and submit detailed information to the BLM on proposed operations, including but not limited to well geology, location of faults and fractures, estimated volume of fluid to be used, and estimated direction and length of fractures. The final rule also provides that for certain circumstances in which specific state or tribal regulations are equally or more protective than the BLM’s new rules, the state or tribe may obtain a variance for that specific regulation. The final rule was set to go into effect on June 24, 2015. However, on June 23, 2015, the U.S. District Court for the District of Wyoming announced a stay on the effective date of the rule in State of Wyoming v. Dep't of Interior, No. 2:15-cv-00043, a lawsuit that involves several states and industry associations who requested that the Court grant a preliminary injunction of the final rule. On September 30, 2015, the U.S. District Court granted the preliminary injunction, thus enjoining the final rule.

In addition, state and local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, ~~but not be limited to,~~ the following:

requirement that logs and pressure test results are included in disclosures to state authorities;

· disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations;

specific disposal regimens for hydraulic fracturing fluids;

replacement/remediation of contaminated water assets; and

minimum depth of hydraulic fracturing.

Local regulations, which may be preempted by state and federal regulations, have included, but have not been limited to, the following, which may extend to all operations including those beyond hydraulic fracturing:

noise control ordinances;

traffic control ordinances;

limitations on the hours of operations; and

mandatory reporting of accidents, spills and pressure test failures.

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

We do not directly employ any of the persons responsible for our management or operation. In general, personnel employed by Atlas Energy Group manage and operate our business. Some of the officers of our general partner may spend a substantial amount of time managing the business and affairs of our general partner and its affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our MGP’s website at www.atlasresourcepartners.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). To view these reports, click on “Investment Programs”, then “Drilling Program SEC Filings” and finally the respective program of your inquiry. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (800) 251-0171. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

ITEM 2: PROPERTIES

Natural Gas and Oil Reserves

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, ~~2014~~2015 and ~~2013~~2014. Proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc., an independent third-party reserve engineer. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, ~~2014~~2015 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, ~~2014~~2015 and ~~2013~~2014 and are adjusted for basis differentials:

	December 31,
	2014		2013
	2015		2014
Natural gas (per Mcf)	$	42.3559	$	34.6735
Oil (per Bbl)	$	9450.9928	$	9694.7899

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 3839 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our MGP’s internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 1617 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s Senior Engineering Staff and management, with final approval by our MGP’s ~~Chief Operating Officer~~President.

Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced. You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. ~~We base the estimates on operating methods and conditions prevailing as of the dates indicated.~~ Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. We base the estimates on operating methods and conditions prevailing as of the dates indicated:

	Proved Reserves at December 31,
	2014		2013
	2015 (4)		2014
Proved reserves:
Proved developed reserves (3):
Natural gas reserves (Mcf)		82,~~482~~418,~~000~~100		98,~~011~~482,~~600~~000
Oil reserves (Bbl)		73,~~900~~700		117,~~500~~900
Total proved developed reserves (Mcfe)		82,~~529~~440,~~400~~300		98,~~080~~529,~~600~~400
Standardized measure of discounted future cash flows(1)	$	7662,~~150,700~~900	$	87,~~039~~150,~~900~~700
Standardized measure of discounted future cash flows per Limited Partner Unit (2)	$	~~324~~30	$	~~363~~324
Undiscounted future cash flows per Limited Partner Unit	$	~~527~~38	$	~~597~~527

(1) Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, no provision for federal or state income taxes has been included in the December 31, ~~2014~~2015 and ~~2013~~2014 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

(2)

This value per limited partner unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of the unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.

(3)

The Partnership does not have any proved undeveloped reserves as of December 31, 2015 and 2014.

(4)

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells. The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, ~~2014~~2015:

	Number of productive wells
		Gross	Net
Gas and/or oil wells		~~546~~519.00	~~496~~469.92

Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2014:

	Developed Acreage
	Gross		Net
Pennsylvania		9,851.31		9,275.85
Ohio		109.14		81.86
Tennessee		2,160.00		1,638.75
Total		12,120.45		10,996.46

Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2015:

	Developed Acreage
	Gross		Net
Ohio		109.14		81.86
Pennsylvania		9,701.51		9,126.05
Tennessee		2,160.00		1,638.75
Total		11,970.65		10,846.66

The leases for our developed acreage generally have terms that extend for the life of the wells. We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

ITEM 3: LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. (See Item 8: Note 9 Commitments and Contingencies).

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.

ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)

PART II

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our units and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our Partnership Agreement which requires:

●

our MGP’s consent;

●

the transfer not result in materially adverse tax consequences to us; and

●

the transfer does not violate federal or state securities laws.

An assignee of a unit may become a substituted partner only upon meeting the following conditions:

●

the assignor gives the assignee the right;

●

our MGP consents to the substitution;

●

the assignee pays to us all costs and expenses incurred in connection with the substitution; and

●

the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the term of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. As of December 31, ~~2014~~2015, we had 4,~~151~~127 limited partners.

20Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2015 and 2014, we distributed the following:

Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2014 and 2013, we distributed the following:

	Distributions
	2015		2014
Limited Partners	$	-	$	1,243,500
Managing General Partner		-		544,400
Total distributions	$	-	$	1,787,900

	Distributions
	2014		2013
Limited Partners	$	1,243,500	$	1,501,500
Managing General Partner		544,400		536,800
Total distributions	$	1,787,900	$	2,038,300

ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with (“Item 8: Financial Statements and Supplementary Data”), which contains our financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. We believe the assumptions underlying the financial statements are reasonable. However, our financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.

BUSINESS OVERVIEW

Atlas America Public #15-2006 (B) L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership and formed on May 9, 2006 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 Resources Partners, L.P. (“ARP”) (NYSE: ARP).

On October 13, 2014, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), and its midstream subsidiary, Atlas Pipeline Partners, L.P. (“APL”), entered into definitive agreements to be acquired by Targa Resources Corp. and Targa Resources Partners LP, respectively. Immediately prior to the acquisition, Atlas Energy distributed to its unitholders 100% of the limited liability company interests in ARP’s general partner, which changed its name to Atlas Energy Group, LLC (“New Atlas”) and became a separate, publicly traded company as a result of the distribution. Following the distribution, New Atlas continues to hold the Partnership’s business as well as ARP’s general partner interest and incentive distribution rights, and now holds the non-midstream assets and ARP limited partner units previously held by Atlas Energy.

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.

BUSINESS OVERVIEW

On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

The Partnership has drilled and currently operate wells located in Pennsylvania, Tennessee and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services.

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

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

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations has 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.

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 primarily produce 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:

●

Well tending, routine maintenance and adjustment;

●

Reading meters, recording production, pumping, maintaining appropriate books and records; and

●

Preparation of reports for us and government agencies.

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 service 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 December 31, 2014, our MGP withheld $95,100 of net production revenue for this purpose. 22

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 service 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 December 31, 2015, our MGP withheld $140,500 of net production revenue for this purpose.

MARKETS AND COMPETITION

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 ~~2014~~2015 and ~~2013~~2014, 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.

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline, ~~and~~ Transco Leidy Line., Columbia Appalachia, NYMEX and Transco Zone 5.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

For the year ended December 31, ~~2014~~2015, Chevron Natural Gas and Atmos Energy Marketing, LLC, accounted for approximately 6362% and 1116%, respectively, of our total natural gas and oil production revenues, with no other single customer accounting for more than 10% of revenues for this period.

GENERAL TRENDS AND OUTLOOK

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and ~~early~~throughout 2015~~, particularly in December 2014 and January 2015~~. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

Our future gas and oil reserves, production, cash flow, and our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decreases.

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION: The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Years Ended December 31,
	2014			2013
	2015			2014
Production revenues (in thousands):
Gas	$	41,~~184~~619		$	4,~~875~~184
Oil		~~224~~78			~~281~~224
Total	$	41,~~408~~697		$	54,~~156~~408
Production volumes:
Gas (mcf/day)		32,~~162~~702			3,~~504~~162
Oil (bbls/day)		75			87
Total (mcfe/day)		32,~~204~~732			3,~~552~~204
Average sales price: (1)
Gas (per mcf) (2)	$	31.6964		$	43.1269
Oil (per bbl)	$	8945.3736		$	9389.2237
Production costs:
As a percent of revenues		63120	%		5963	%
Per mcfe	$	2.3605		$	2.3536
Depletion per mcfe	$	0.8127		$	10.5781

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

23Natural Gas Revenues. Our natural gas revenues were $1,618,500 and $4,184,200 for the years ended December 31, 2015 and 2014, respectively, a decrease of $2,565,700 (61%). The $2,565,700 decrease in natural gas revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $1,956,700 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions, and $609,000 decrease in production volumes. Our production volumes decreased to 2,702 mcf per day for the year ended December 31, 2015 from 3,162 mcf per day for the year ended December 31, 2014, a decrease of 460 (15%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: “Business-Contractual Revenue Arrangements”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume is mostly due to the normal decline inherent in the life of the wells and a decrease in the number of producing wells due to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

~~Natural~~Oil ~~Gas~~ Revenues. ~~Our~~We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $478,~~184,200~~500 and $4223,~~875,200~~400 for the years ended December 31, ~~2014~~2015 and ~~2013~~2014, respectively, a decrease of $~~691~~144,~~000~~900 (1465%). The $~~691~~144,~~000~~900 decrease in ~~natural~~oil ~~gas~~ revenues for the year ended December 31, ~~2014~~2015 as compared to the prior year was attributable to a $~~476~~76,100 decrease in ~~production~~oil ~~volumes~~prices and a $~~214~~68,~~900~~800 decrease in ~~natural~~production ~~gas prices after the effect of financial hedges, which were driven by market conditions~~volumes. Our production volumes decreased to ~~3,162~~5 ~~mcf~~bbls per day for the year ended December 31, ~~2014~~2015 from ~~3,504~~7 ~~mcf~~bbl per day for the year ended December 31, ~~2013~~2014, a decrease of ~~342~~2 ~~(10%) mcf~~bbl per day. ~~The price we receive for our natural gas is primarily a result of the index driven agreements~~ (~~See Item 1: “Business-Contractual Revenue Arrangements”~~29%). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume is mostly due to the normal decline inherent in the life of the wells.

~~Oil~~Gain ~~Revenues.~~on WeMark-to-Market ~~drill~~Derivatives. ~~wells~~On ~~primarily~~January to1, ~~produce natural gas~~2015, ~~rather~~we ~~than~~discontinued ~~oil,~~hedge ~~but~~accounting ~~some~~for ~~wells~~our ~~have~~qualified ~~limited~~commodity ~~oil production~~derivatives. ~~Our~~As ~~oil~~such, ~~revenues~~subsequent ~~were~~changes ~~$223,400~~in ~~and~~fair ~~$280,800~~value ~~for~~of ~~the~~these ~~years~~derivatives ~~ended~~are ~~December~~recognized ~~31,~~immediately ~~2014~~within ~~and~~gain ~~2013,~~on ~~respectively,~~mark-to-market aderivatives ~~decrease~~on ofour ~~$57,400~~statements ~~(20%)~~of operations. The ~~$57,400~~fair ~~decrease~~values inof ~~oil~~these ~~revenues~~commodity ~~for~~derivative ~~the~~instruments ~~year~~as ~~ended~~of December 31, 2014, aswhich ~~compared~~were torecognized ~~the~~in ~~prior~~accumulated ~~year~~other ~~was~~comprehensive ~~attributable~~income towithin apartners’ ~~$47,800~~capital ~~decrease~~on inour ~~production~~balance ~~volumes and a $9~~sheet,~~600~~ ~~decrease~~will inbe ~~oil~~reclassified ~~prices~~to ~~after~~our ~~the~~statements ~~effect~~ of ~~financial~~operations ~~hedges.~~in ~~Our~~the ~~production~~future ~~volumes~~at ~~decreased to 7 bbl per day for~~ the ~~year~~time ~~ended December 31, 2014 from 8 bbl per day for~~ the ~~year~~originally ~~ended~~hedged ~~December 31,~~physical ~~2013,~~transactions ~~a decrease of 1 bbl per day (13%)~~settle.

Costs and Expenses. Production expenses were $2,762,200 and $3,053,600 for the years ended December 31, 2014 and 2013, respectively, a decrease of $291,400 (10%). This decrease was primarily due to a combination of a decrease in transportation fees and supervision fees. The transportation charges were affected by a decrease in production volumes.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 22% and 39% for the years ended December 31, 2014 and 2013, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $407,800 and $431,500 for the years ended December 31, 2014 and 2013, respectively, a decrease of $23,700 (5%). 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 and services provided to us.

During the year ended December 31, 2014, we recognized $6,914,500 of impairment related to gas and oil properties within property, plant, and equipment on our balance sheet. This impairment related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2014. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices. There was no impairment of gas and oil properties for the year ended December 31, 2013.

Liquidity and Capital Resources. Cash provided by operating activities decreased $472,600 for the year ended December 31, 2014 to $1,619,500 as compared to $2,092,100 the year ended December 31, 2013. This decrease was due to an decrease in net earnings before depletion, impairment, and accretion of $433,300 a decrease in non-cash loss on derivative value of $319,500 and a decrease in the change in asset retirement receivable-affiliate of $95,100, partially offset an increase in the change in accounts receivable trade-affiliate of $348,400, an increase in the change in asset retirement obligations settled of $25,700 and an increase in the change in accrued liabilities of $1,200 for the year ended December 31, 2014 compared to the year ended December 31, 2013.

Cash provided by investing activities was $1,300 during the year ended December 31, 2014 from the sale of tangible equipment. Cash provided by investing activities was $10,800 for year ended December 31, 2013 representing the net of $11,900 in proceeds from the sale of tangible equipment and $1,100 for the purchase of tangible equipment.

Cash used in financing activities decreased $250,400 to $1,787,900 for the year ended December 31, 2014, from $2,038,300 for the year ended December 31, 2013. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2014, our MGP has withheld $95,100 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.

We ~~are~~recognized ~~generally~~a ~~limited~~gain on mark-to-market ~~the~~derivatives ~~amount~~ of ~~funds~~$68,500 ~~generated~~for by the ~~cash~~year ~~flow~~ended ~~from~~December ~~our operations~~31, ~~which~~2015. weThis ~~believe~~gain iswas ~~adequate~~due primarily to ~~fund~~mark-to-market ~~future~~gains ~~operations~~in ~~and~~the ~~distributions~~current year primarily related to ~~our~~the ~~partners.~~change ~~Historically,~~in ~~there~~natural ~~has~~gas ~~been~~prices during the year. There were no ~~need~~gains or losses on mark-to-market ~~borrow~~derivatives ~~funds~~during ~~from~~the ~~our~~year ~~MGP~~ended toDecember ~~fund~~31, ~~operations~~2014.

Costs and Expenses. Production expenses were $2,038,100 and $2,762,200 for the years ended December 31, 2015 and 2014, respectively, a decrease of $724,100 (26%). This decrease was primarily due to a combination of a decrease in transportation fees and operation fees.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 16% and 22% for the years ended December 31, 2015 and 2014, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent, revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $356,400 and $407,800 for the years ended December 31, 2015 and 2014, respectively, a decrease of $51,400 (13%). 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 and services provided to us.

During the year ended December 31, 2015, we recognized $3,053,900 of impairment related to gas and oil properties within property, plant, and equipment on our balance sheet. This impairment related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices. During the year ended December 31, 2014, the Partnership recognized $6,914,500 of impairment related to gas and oil properties within property, plant, and equipment on our balance sheet.

Liquidity and Capital Resources. We are generally limited to the amount of funds generated by the cash flow from our operations to fund our obligations and make distributions to our partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact our outlook. We have experienced downward revisions of our 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, our 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.

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.

Cash provided by operating activities decreased $1,620,100 for the year ended December 31, 2015 to cash used by operating activities of $600 as compared to $1,619,500 for the year ended December 31, 2014. This decrease was due to an decrease in net earnings before depletion, impairment, and accretion of $1,866,600, a decrease in non-cash (gain) loss on derivative value of $130,000, a decrease in the change in the accounts receivable trade-affiliate of $69,900, a decrease in the change in asset retirement obligation liabilities settled of $23,900 and a decrease in the change in accrued liabilities of $4,500, partially offset by an increase in accounts payable trade-affiliate of $425,100 and an increase in the change in asset retirement receivable-affiliate of $49,700 for the year ended December 31, 2015 compared to the year ended December 31, 2014.

Cash provided by investing activities was $600 during the year ended December 31, 2015 from the sale of tangible equipment. Cash provided by investing activities was $1,300 for year ended December 31, 2014 from the sale of tangible equipment.

There was no cash used in financing activities for the year ended December 31, 2015. Cash used in financing activities was $1,787,900 for the year ended December 31, 2014 due to cash distributions to partners for the year ended December 31, 2014. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2015, our MGP has withheld $140,500 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.

Impairment

~~During~~Impairment of gas and oil properties for the ~~year~~years ended December 31, 2015 and 2014, wewas ~~recognized~~$3,053,900 and $6,914,500, respectively. At least annually, we compare the carrying value of ~~impairment~~our ~~related~~proved todeveloped gas and oil producing properties ~~within~~to ~~property,~~their ~~plant,~~estimated ~~and~~fair ~~equipment~~market onvalue. ~~our~~To ~~balance~~the ~~sheet.~~extent ~~This~~our ~~impairment~~carrying ~~related~~value toexceeds the ~~carrying~~estimated ~~amount~~fair ofmarket ~~our~~value, ~~gas~~an ~~and~~impairment ~~oil~~charge ~~properties~~is ~~being~~recognized. inAs ~~excess~~a ofresult ~~our estimate~~ of ~~their~~this ~~fair~~assessment, ~~value~~an atimpairment ~~December 31,~~charge ~~2014.~~was ~~The~~recognized ~~estimate~~for ofthe ~~fair~~years ~~value~~ended ofDecember ~~these~~31, ~~gas~~2015 and ~~oil~~2014. ~~properties~~This ~~was~~charge ~~impacted~~is ~~by,~~based ~~among~~on ~~other~~reserve ~~factors~~quantities, ~~the~~future ~~deterioration~~market ofprices ~~natural gas~~ and ~~oil~~our ~~prices~~carrying value. ~~There~~We ~~was~~cannot noprovide ~~impairment~~any ofassurance ~~gas~~that ~~and~~similar ~~oil~~charges ~~properties~~may ~~for~~or ~~the~~may ~~year~~not ~~ended~~be ~~December~~taken ~~31,~~in ~~2013~~future periods.

ENVIRONMENTAL REGULATION

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (~~See~~see “Item 1: Business —Environmental Matters and ~~Regulations~~Regulation”). We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties,; imposition of remedial requirements,; issuance of injunctions affecting our operations,; or other measures. We have ~~ongoing~~maintained and expect to continue to maintain environmental compliance programs. However, risks of accidental leaks or spills are associated with our operations. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly strict federal, state and local environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that ~~there~~such changes will ~~be continuing changes~~continue. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on ~~activities~~operations, such as emissions of greenhouse gases and other pollutants,; generation and disposal of wastes, including wastes that may have technologically enhanced naturally occurring ~~radioactivity,~~radioactive materials; and use, storage and handling of chemical substances that may impact human health, the environment and/or threatened or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such change, or that our efforts will prevent material costs, if any, from rising.

CHANGES IN PRICES AND INFLATION

Our revenues and the value of our assets have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict.

Inflation affects the operating expenses of our operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion and amortization, impairment, fair value of derivative instruments and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements (See “Item 8: Financial Statements”) included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depletion and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of natural gas and oil properties, less estimated salvage value, is generally depleted on the units-of-production method.

Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.

During the year ended December 31, 2014, we recognized $6,914,500 of impairment within natural gas and oil properties. The impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2014. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. There was no impairment recognized for the year ended December 31, 2013.

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions.

During the year ended December 31, 2015, we recognized $3,053,900 of impairment within natural gas and oil properties. The impairment related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement. During the year ended December 31, 2014, we recognized $6,914,500 of impairment within natural gas and oil properties.

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on our MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value, which requires us 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.

We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our MGP’s credit-adjusted risk-free rate and inflation rates.

Reserve Estimates

Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. We engaged Wright & Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves (See “Item 2: Properties”).

Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of natural gas and oil properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

The estimated liability is based on our 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 our MGP’s assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.

Working Interest

Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). Our MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

2729

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas America Public #15-2006 (B) L.P.

We have audited the accompanying balance sheets of Atlas America Public #15-2006 (B) L.P. (a Delaware limited partnership) (the “Partnership”) as of December 31, ~~2014~~2015 and ~~2013~~2014, and the related statements of operations, comprehensive loss, changes in partners’ ~~capital~~deficit, and cash flows for each of the two years in the period ended December 31, ~~2014~~2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Public #15-2006 (B) L.P. as of December 31, ~~2014~~2015 and ~~2013~~2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, ~~2014~~2015 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

~~March~~April 3114, ~~2015~~2016

2830

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

BALANCE SHEETS

DECEMBER 31, 2015 AND 2014

	2014			2013
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	-		$	167,100
Cash	$	-		$	-
Accounts receivable trade–affiliate		~~542~~217,~~300~~100			~~937~~542,~~400~~300
Asset retirement receivable-affiliate		~~95,100~~-			-95,100
Accounts receivable monetized gains-affiliate		-			56,200
Current portion of derivative assets		103,600			51,700
Current portion of derivative assets		51,700			6,700
Total current assets		320,700			689,100
Total current assets		689,100			1,167,400
Gas and oil properties, net		4,347,300			8,370,300
Gas and oil properties, net		8,370,300			13,336,000
Long-term asset retirement receivable-affiliate		140,500			-
Long-term derivative assets		~~43,300~~-			3543,~~400~~300
	$	9,102,700		$	14,538,800
Total assets	$	4,808,500		$	9,102,700
LIABILITIES AND PARTNERS’ CAPITAL
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accrued liabilities	$	9,300		$	6,700
Accounts payable trade-affiliate	$	425,100		$	-
Current portion of put premiums payable-affiliate		33,200			-
Accrued liabilities		7,400			9,300
Total current liabilities		42,500			6,700
Current portion of put premiums payable-affiliate		47,800			33,200
Asset retirement obligations		11,050,300			7,692,200
Total current liabilities		480,300			42,500
Long-term put premiums payable-affiliate		37,900			63,600
Asset retirement obligations		10,947,300			11,050,300
Commitments and contingencies
Long-term put premiums payable-affiliate		-			37,900
Partners’ capital:
Commitments and contingencies (Note 9)
Managing general partner’s interest		269,300			3,278,400
Partners’ (deficit) capital:
Limited partners’ interest (14,772.60 units)		(2,321,200	)		3,542,800
Managing general partner’s (deficit) interest		(1,382,800	)		269,300
Accumulated other comprehensive income (loss)		23,900			(44,900	)
Limited partners’ deficit (14,772.60 units)		(5,241,700	)		(2,321,200	)
Total partners’ capital		(2,028,000	)		6,776,300
Accumulated other comprehensive income		5,400			23,900
	$	9,102,700		$	14,538,800
Total partners’ deficit		(6,619,100	)		(2,028,000	)
Total liabilities and partners’ deficit	$	4,808,500		$	9,102,700

See accompanying notes to financial statements.

2931

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, ~~2014~~2015 AND ~~2013~~2014

	2014			2013
	2015			2014
REVENUES
Natural gas and oil	$	41,~~407~~697,~~600~~000		$	54,~~156~~407,~~000~~600
Total revenues		4,407,600			5,156,000
Gain on mark-to-market derivatives		68,500			-
COST AND EXPENSES
Total revenues		1,765,500			4,407,600
Production		2,762,200			3,053,600
COSTS AND EXPENSES
Depletion		951,700			2,030,800
Production		2,038,100			2,762,200
Impairment		6,914,500			-
Depletion		267,700			951,700
Accretion of asset retirement obligation		456,600			441,400
Impairment		3,053,900			6,914,500
General and administrative		407,800			431,500
Accretion of asset retirement obligations		622,000			456,600
Total costs and expenses		11,492,800			5,957,300
General and administrative		356,400			407,800
Net loss	$	(7,085,200	)	$	(801,300	)
Total costs and expenses		6,338,100			11,492,800
Net loss	$	(4,572,600	)	$	(7,085,200	)
Allocation of net loss:
Managing general partner	$	(21,~~464~~652,~~700~~100	)	$	3(2,~~300~~464,700	)
Limited partners	$	(42,~~620~~920,500	)	$	(~~804~~4,~~600~~620,500	)
Net loss per limited partnership unit	$	(~~313~~198	)	$	(54313	)

See accompanying notes to financial statements.

3032

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, ~~2014~~2015 AND ~~2013~~2014

	2014			2013
	2015			2014
Net loss	$	(74,~~085~~572,~~200~~600	)	$	(~~801~~7,~~300~~085,200	)
Other comprehensive income:
Other comprehensive (loss) income:
Unrealized holding gain (loss) on cash flow hedging contracts		23,900			(53,400	)
Mark-to-market gains on cash flow hedging contracts		-			23,900
Difference in estimated hedge gains receivable		81(5,~~700~~300	)		~~185~~81,~~900~~700
Reclassification adjustment for gains realized in net loss from cash flow hedges		(36,800	)		(50,300	)
Reclassification adjustment to net loss of mark-to-market gains on cash flow hedges		(13,200	)		(36,800	)
Total other comprehensive income		68,800			82,200
Total other comprehensive (loss) income		(18,500	)		68,800
Comprehensive loss	$	(74,~~016~~591,~~400~~100	)	$	(~~719~~7,~~100~~016,400	)

See accompanying notes to financial statements.

3133

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENTS OF CHANGES IN PARTNERS’ ~~CAPITAL~~DEFICIT

YEARS ENDED DECEMBER 31, ~~2014~~2015 AND ~~2013~~2014

	ManagingGeneralPartner			LimitedPartners			AccumulatedOtherComprehensiveIncome (Loss)			Total
Balance at December 31, 2012	$	3,811,900		$	5,848,900		$	(127,100	)	$	9,533,700
Participation in revenue and costs and expenses:
Net production revenues		709,900			1,392,500			-			2,102,400
Depletion		(416,300	)		(1,614,500	)		-			(2,030,800	)
Accretion of asset retirement obligation		(146,800	)		(294,600	)		-			(441,400	)
General and administrative		(143,500	)		(288,000	)		-			(431,500	)
Net income (loss)		3,300			(804,600	)		-			(801,300	)
Other comprehensive income		-			-			82,200			82,200
Distributions to partners		(536,800	)		(1,501,500	)		-			(2,038,300	)
Balance at December 31, 2013	$	3,278,400		$	3,542,800		$	(44,900	)	$	6,776,300
Participation in revenue and costs and expenses:
Participation in revenues and costs and expenses:
Net production revenues		554,000			1,091,400			-			1,645,400
Depletion		(333,700	)		(618,000	)		-			(951,700	)
Impairment		(2,397,600	)		(4,516,900	)		-			(6,914,500	)
Accretion of asset retirement obligation		(151,800	)		(304,800	)		-			(456,600	)
Accretion of asset retirement obligations		(151,800	)		(304,800	)		-			(456,600	)
General and administrative		(135,600	)		(272,200	)		-			(407,800	)
Net loss		(2,464,700	)		(4,620,500	)		-			(7,085,200	)
Other comprehensive income		-			-			68,800			68,800
Distributions to partners		(544,400	)		(1,243,500	)		-			(1,787,900	)
Balance at December 31, 2014	$	269,300		$	(2,321,200	)	$	23,900		$	(2,028,000	)
Participation in revenues and costs and expenses:
Net production expenses		(118,200	)		(222,900	)		-			(341,100	)
Gain on mark-to-market derivatives		-			68,500			-			68,500
Depletion		(99,000	)		(168,700	)		-			(267,700	)
Impairment		(1,109,600	)		(1,944,300	)		-			(3,053,900	)
Accretion of asset retirement obligations		(206,800	)		(415,200	)		-			(622,000	)
General and administrative		(118,500	)		(237,900	)		-			(356,400	)
Net loss		(1,652,100	)		(2,920,500	)		-			(4,572,600	)
Other comprehensive loss		-			-			(18,500	)		(18,500	)
Balance at December 31, 2015	$	(1,382,800	)	$	(5,241,700	)	$	5,400		$	(6,619,100	)

See accompanying notes to financial statements.

3234

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, ~~2014~~2015 AND ~~2013~~2014

	2014			2013
	2015			2014
Cash flows from operating activities:
Net loss	$	(74,~~085~~572,~~200~~600	)	$	(~~801~~7,~~300~~085,200	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depletion		~~951~~267,700			2951,~~030,800~~700
Impairment		63,~~914~~053,~~500~~900			-6,914,500
Non-cash loss on derivative value		79,600			399,100
Non-cash (gain) loss on derivative value		(50,400	)		79,600
Accretion of asset retirement obligation		456,600			441,400
Accretion of asset retirement obligations		622,000			456,600
Asset retirement obligations settled		(~~300~~24,200	)		(~~26,000~~300	)
Changes in operating assets and liabilities:
Decrease in accounts receivable trade-affiliate		~~395~~325,~~100~~200			46395,~~700~~100
Asset retirement receivable-affiliate		(95,100	)		-
Increase in asset retirement receivable-affiliate		(45,400	)		(95,100	)
Increase in accrued liabilities		2,600			1,400
Increase in accounts payable trade-affiliate		425,100			-
Net cash provided by operating activities		1,619,500			2,092,100
(Decrease) increase in accrued liabilities		(1,900	)		2,600
Net cash (used in) provided by operating activities		(600	)		1,619,500
Cash flows from investing activities:
Proceeds from sale of tangible equipment		~~1,300~~600			111,~~900~~300
Purchase of tangible equipment		-			(1,100	)
Net cash provided by investing activities		600			1,300
Net cash provided by investing activities		1,300			10,800
Cash flows from financing activities:
Distributions to partners		~~(1,787,900~~-	)		(21,~~038~~787,~~300~~900	)
Net cash used in financing activities		~~(1,787,900~~-	)		(21,~~038~~787,~~300~~900	)
Net change in cash and cash equivalents		(167,100	)		64,600
Net change in cash		-			(167,100	)
Cash and cash equivalents at beginning of year		167,100			102,500
Cash at beginning of year		-			167,100
Cash and cash equivalents at end of period	$	-		$	167,100
Cash at end of year	$	-		$	-
Supplemental schedule of non-cash investing and financing activities:
Asset retirement obligation revision	$	2,901,800		$	(841,000	)
Asset retirement obligations revision	$	(700,800	)	$	2,901,800

See accompanying notes to financial statements.

3335

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, ~~2014~~2015 AND ~~2013~~2014

NOTE 1—BASIS OF PRESENTATION

Atlas America Public #15-2006 (B) L.P. (the “Partnership”) is a Delaware limited partnership, formed on May 9, 2006 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

On ~~October~~February 1327, ~~2014~~2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”) ~~(NYSE: ATLS)~~, ~~and~~which ~~its~~was ~~midstream~~a ~~subsidiary,~~publicly ~~Atlas~~traded ~~Pipeline~~master-limited ~~Partners~~partnership, ~~L.P.~~was ~~(“APL”), entered into definitive agreements to be~~ acquired by Targa Resources Corp. and ~~Targa~~distributed ~~Resources Partners LP, respectively. Immediately prior~~ to ~~the acquisition,~~ Atlas Energy’s ~~distributed to its~~ unitholders 100% of the limited liability company interests in ARP’s general partner, ~~which changed its name to~~ Atlas Energy Group, LLC (“~~New~~ Atlas Energy Group”; OTCQX: ATLS). ~~and~~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, ~~New~~ Atlas Energy Group continues to ~~hold~~manage ~~the Partnership’s business as well as~~ ARP’s ~~general~~operations ~~partner interest~~ and ~~incentive~~activities ~~distribution~~through ~~rights,~~its ~~and~~ownership ~~now~~of ~~holds~~ the ~~non-midstream assets and~~ ARP’s ~~limited~~general partner ~~units previously held by Atlas Energy~~interest.

InThe ~~March~~Partnership ~~2012,~~has ~~Atlas~~drilled ~~Energy~~and ~~contributed~~currently tooperates ~~ARP,~~wells alocated ~~newly-formed~~in ~~exploration~~Pennsylvania, Tennessee and ~~production~~Ohio. ~~master~~The ~~limited~~Partnership ~~partnership,~~has ~~substantially~~no ~~all~~employees ofand ~~Atlas~~relies ~~Energy’s~~on ~~natural~~the ~~gas~~MGP ~~and~~for ~~oil~~management, ~~development~~which ~~and~~in ~~production~~turn, ~~assets~~relies ~~and~~on its ~~partnership~~parent ~~management~~company, ~~business~~Atlas Energy Group (February 27, ~~including~~2015, ~~ownership~~and ofprior, ~~the~~Atlas ~~MGP.~~Energy), for administrative services.

On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of APL, completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its gas and oil exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and Ohio. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy (after February 27, 2015, New Atlas), 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.

Liquidity and Capital Resources

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

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the 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.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and ~~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~~revenue 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, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices (see “Revenue Recognition”). Actual results could differ from those estimates.

Cash Equivalents

The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Receivables

Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, ~~2014~~2015 and ~~2013~~2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

Asset retirement receivable – affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnership’s wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells.

The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the years indicated:

	December 31,
	2015			2014
Asset retirement receivable – affiliate, beginning of year	$	95,100		$	-
Asset retirement estimates withheld		69,600			95,100
Plugging and abandonment costs incurred		(24,200	)		-
Asset retirement receivable –affiliate, end of year	$	140,500		$	95,100

Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.

Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated ~~depreciation~~depletion and ~~depletion~~impairment within its balance sheets.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value (see Note 4).

The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

During the year ended December 31, 2014, the Partnership recognized $6,914,500 of impairment related to gas and oil properties. 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. There was no impairment of gas and oil properties for the year ended December 31, 2013.

Derivative Instruments

The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded inon the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (See Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

Income Taxes

The Partnership is not ~~treated~~subject asto aU.S. ~~taxable~~federal ~~entity~~and ~~for~~most ~~federal~~state income ~~tax purposes~~taxes. ~~Any~~The ~~item~~partners of ~~income,~~the ~~gain,~~Partnership ~~loss,~~are ~~deduction,~~liable orfor ~~credit~~income ~~flows~~tax ~~through~~in regard to their distributive share of the ~~partners~~Partnership’s astaxable ~~though~~income. ~~each~~Such ~~partner~~taxable ~~had~~income ~~incurred~~may ~~such~~vary ~~item~~substantially ~~directly.~~from Asnet aincome ~~result,~~reported ~~each~~in ~~partner~~the ~~must~~financial ~~take~~statements. ~~into~~The ~~account~~federal ~~their~~and ~~pro~~state ~~rata~~income ~~share~~taxes ofrelated ~~all~~to ~~items~~the ofPartnership ~~partnership~~were ~~income~~immaterial to the financial statements and ~~deductions~~are recorded in ~~computing~~pre-tax ~~their~~income on a current basis only. Accordingly, no federal or state deferred income tax ~~liability~~has been provided for in the financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, ~~2014~~2015 and ~~2013~~2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to ~~2010~~2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, ~~2014~~2015.

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, ~~2014~~2015 and ~~2013~~2014.

Concentration of Credit Risk

The Partnership sells natural gas and crude oil under contracts to various purchasers in the normal course of business. For the year ended December 31, ~~2014~~2015, the Partnership had two customers that individually accounted for approximately 6362% and 1116%, of the Partnership’s natural gas and oil combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, ~~2013~~2014, the Partnership had two customers that individually accounted for approximately 6463% and 1011% of the Partnership natural gas and oil combined revenues, excluding the impact of all financial derivative activity.

3639

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (See ~~Note 2:~~ “-Use of Estimates” ~~for further description~~). The Partnership had unbilled revenues at December 31, ~~2014~~2015 and ~~2013~~2014 of $~~505~~217,100 and $~~738~~505,~~300~~100, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” ~~and~~on ~~for~~ the Partnership’s financial statements and, at December 31, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 6). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Adopted Accounting Standards

In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Recently Issued Accounting Standards

In ~~January~~August ~~2015~~2014, the FASB ~~issued~~updated ~~ASU~~the ~~2015-01,~~accounting ~~Income~~guidance ~~Statement~~related –to ~~Extraordinary~~the ~~and~~evaluation ~~Unusual~~of ~~Items~~whether ~~(Subtopic~~there ~~225-20):~~is ~~Simplifying~~substantial ~~Income~~doubt ~~Statement~~about ~~Presentation~~an byentity’s ~~Eliminating~~ability ~~the~~to ~~Concept~~continue ofas ~~Extraordinary~~a ~~Items~~going ~~(“Update 2015-01”)~~concern. The ~~amendments~~updated inaccounting ~~Update~~guidance ~~2015-01~~requires ~~simplify~~an ~~the~~entity’s ~~income~~management ~~statement~~to ~~presentation~~evaluate ~~requirements~~whether inthere ~~Subtopic~~are ~~225-20~~conditions byor ~~eliminating the concept of extraordinary items. Extraordinary items are~~ events ~~and~~that ~~transactions~~raise ~~that~~substantial ~~are~~doubt ~~distinguished~~about byits ~~their~~ability ~~unusual~~to ~~nature~~continue ~~and~~as bya ~~the~~going ~~infrequency~~concern ofwithin ~~their~~one ~~occurrence.~~year ~~Eliminating~~from the ~~extraordinary~~date ~~classification simplifies income statement presentation by altogether removing~~ the ~~concept~~financial ofstatements ~~extraordinary items from consideration. The amendments in Update 2015-01~~ are ~~effective~~issued ~~for fiscal years,~~ and ~~interim~~provide ~~periods~~footnote ~~within those fiscal years~~disclosures, ~~beginning~~if ~~after December 15, 2015~~necessary. The Aupdated ~~reporting~~guidance ~~entity~~is ~~may~~effective ~~apply~~as ~~the~~of ~~amendments~~January ~~prospectively.~~1, A2017 ~~reporting~~and ~~entity may also apply~~ the ~~amendments~~Partnership ~~retrospectively~~is tocurrently ~~all prior periods presented~~ in the ~~financial~~process ~~statements.~~of ~~Early~~determining ~~adoption is permitted provided that~~ the ~~guidance~~impact ~~is applied from the beginning~~ of ~~the~~providing ~~fiscal year of adoption. The Partnership will adopt~~ the ~~requirements~~enhanced ofdisclosures, ~~Update~~as ~~2015-01 upon its effective date of January 1~~applicable, ~~2016,~~within ~~and it does not anticipate it having a material impact on~~ its financial ~~position, results of operations or related disclosures~~statements.

In ~~November~~May 2014, the FASB ~~issued~~updated ~~ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether~~ the ~~Host~~accounting ~~Contract~~guidance inrelated ato ~~Hybrid~~revenue ~~Financial~~recognition. ~~Instrument~~The ~~Issued~~updated inaccounting ~~the~~guidance ~~Form~~provides of a ~~Share~~single, iscontract-based ~~More~~revenue ~~Akin~~recognition tomodel ~~Debt or~~ to ~~Equity~~help ~~(“Update~~improve ~~2014-16”).~~financial ~~Certain~~reporting ~~classes~~by ofproviding ~~shares~~clearer ~~include~~guidance ~~features~~on ~~that~~when ~~entitle~~an ~~the~~entity ~~holders~~should torecognize ~~preferences and rights (such as conversion rights~~revenue, ~~redemption rights, voting powers,~~ and ~~liquidation~~by ~~and~~reducing ~~dividend payment preferences) over~~ the ~~other~~number ~~shareholders.~~of ~~Shares~~standards ~~that include embedded derivative features are referred~~ to ~~as hybrid financial instruments,~~ which ~~must~~an beentity ~~separated~~has ~~from~~to ~~the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10~~refer. ~~One~~In ~~criterion~~July ~~requires~~2015, ~~evaluating whether~~ the ~~nature~~FASB ofvoted ~~the host contract is more akin~~ to ~~debt~~defer ~~or to equity and whether~~ the ~~economic~~effective ~~characteristics~~date ~~and~~by ~~risks~~one ofyear ~~the embedded derivative feature are “clearly and closely related”~~ to ~~the host contract. In making that evaluation~~December 15, an2017 ~~issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated~~ for ~~separate~~annual ~~accounting~~reporting orperiods ~~may~~beginning ~~consider~~after ~~all terms and features in the hybrid financial instrument except for the embedded derivative feature~~ that ~~is being evaluated for separate accounting~~date. The ~~use~~updated ~~of different methods can result in different~~ accounting ~~outcomes~~guidance ~~for~~provides ~~economically~~companies ~~similar hybrid financial instruments. Additionally, there is diversity in practice~~ with ~~respect~~alternative tomethods ~~the consideration~~ of ~~redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity~~adoption. The ~~amendments~~Partnership ~~in Update 2014-16 clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that~~ is ~~issued~~currently in the ~~form~~process of adetermining ~~share. The effects of initially adopting~~ the ~~amendments~~impact inthat ~~Update 2014-16 should be applied on a modified retrospective basis to existing hybrid financial instruments issued in~~ the ~~form~~updated ofaccounting aguidance share as of the beginning of the fiscal year for which the amendments are effective. Retrospective application is permitted to all relevant prior periods. The amendments in Update 2014-16 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption, including adoption in an interim period, is permitted. The Partnership will ~~adopt~~have ~~the~~on ~~requirements of Update 2014-16 upon~~ its ~~effective~~financial ~~date~~statements ~~of January 1, 2016,~~ and ~~is evaluating the impact of the adoption on~~ its ~~financial~~method ~~position, results~~ of ~~operations or related disclosures~~adoption.

~~In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-~~40) (“Update 2014-15”). The amendments in Update 2014-15 provide GAAP guidance on the responsibility of an entity’s management in evaluating whether there is substantial doubt about the entity’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, an entity’s management will be required 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. In doing so, the amendments in Update 2014-15 should reduce diversity in the timing and content of footnote disclosures. The amendments in Update 2014-15 are effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Partnership will adopt the requirements of Update 2014-15 upon its effective date of January 1, 2017, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles – Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Partnership will adopt the requirements of Update 2014-09 retrospectively upon its effective date of January 1, 2017, and is evaluating the impact of the adoption on its financial position, results of operations or related disclosures.

NOTE 3—PARTICIPATION IN REVENUES AND COSTS

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

The MGP and the limited partners ~~will~~ generally ~~participate~~participated in revenues and costs in the following manner:

	ManagingGeneralPartner		LimitedPartners
Organization and offering cost		100%		0%
Lease costs		100%		0%
Revenues (1)		33%		67%
Operating costs, administrative costs, direct and all other costs (2)		33%		67%
Intangible drilling costs		3%		97%
Tangible equipment costs		66%		34%
Revenues (1)		33%		67%
Operating costs, administrative costs, direct and all other costs (2)		33%		67%

(1)

Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues.

(2)

These costs will be charged to the partners in the same ratio as the related production revenues are credited.

NOTE 4—PROPERTY, PLANT AND EQUIPMENT

The following is a summary of natural gas and oil properties at the dates indicated:

	December 31,
	2014			2013
	2015			2014
Proved properties:
Leasehold interest	$	43,~~179~~944,~~600~~100		$	4,179,600
Wells and related equipment		~~186~~180,~~298~~678,~~000~~600			~~183~~186,~~397~~298,~~500~~000
Total natural gas and oil properties		~~190~~184,~~477~~622,~~600~~700			~~187~~190,~~577~~477,~~100~~600
Accumulated depletion and impairment		(~~182~~180,~~107~~275,~~300~~400	)		(~~174~~182,~~241~~107,~~100~~300	)
Gas and oil properties, net	$	84,~~370~~347,300		$	138,~~336~~370,~~000~~300

The Partnership recorded depletion expense on natural gas and oil properties of $~~951~~267,700 and $2951,~~030,800~~700 for the years ended December 31, ~~2014~~2015 and ~~2013~~2014, respectively. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. 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 $431,800 from natural gas and oil properties to accumulated depletion for the year ended December 31, 2015. During the year ended December 31, 2015, the Partnership sold 27 net and gross wells. As a result of wells sold, the Partnership reclassified $4,721,700 from gas and oil properties to accumulated depletion and impairment and $700,800 of asset retirement obligations were removed from the Partnership asset and liability accounts.

During the year ended December 31, ~~2014~~2015, the Partnership recognized $63,~~914~~053,~~500~~900 of impairment related to gas and oil properties on its balance sheet. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, ~~2014~~2015. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. ~~There~~During ~~was~~the noyear ~~impairment~~ended December 31, 2014, the Partnership recognized $6,914,500 of impairment related to gas and oil properties ~~for~~on ~~the~~its ~~year~~balance ~~ended December 31, 2013~~sheet.

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such vales and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.

NOTE 5—ASSET RETIREMENT OBLIGATIONS

The ~~Partnership recognizes an~~ estimated liability for ~~the plugging and abandonment of its gas and oil wells and related facilities. It also recognizes a liability for future~~ asset retirement obligations ifwas a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability iswas discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in ~~cost~~ estimates, of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for ~~the~~its ~~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 December 31, ~~2014~~2015, the MGP withheld $95140,~~100~~500 of net production revenue for future plugging and abandonment costs.

A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows:

	Years Ended December 31,
	2014			2013
	2015			2014
Asset retirement obligations, beginning of year	$	7,692,200		$	8,117,800
Beginning of year	$	11,050,300		$	7,692,200
Accretion of asset retirement obligations		456,600			441,400
Accretion expense		622,000			456,600
Asset retirement obligation revision		2,901,800			(841,000	)
Settlements		(24,200	)		(300	)
Liabilities settled		(300	)		(26,000	)
Revisions		(700,800	)		2,901,800
Asset retirement obligations, end of period	$	11,050,300		$	7,692,200
End of year	$	10,947,300		$	11,050,300

NOTE 6—DERIVATIVE INSTRUMENTS

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally ~~swaps,~~put ~~collars and~~ options, in connection with the Partnership’s commodity price risk management activities. Management uses financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. 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 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.

The ~~MGP~~Partnership ~~formally~~enters ~~documents~~into ~~all~~derivative ~~relationships~~contracts ~~between~~with ~~hedging~~various ~~instruments~~financial ~~and the items being hedged~~institutions, ~~including~~utilizing ~~its~~master ~~risk~~contracts ~~management~~based ~~objective~~upon ~~and~~the ~~strategy~~standards ~~for~~set ~~undertaking~~by the ~~hedging~~International ~~transactions.~~Swaps ~~This~~and ~~includes~~Derivatives ~~matching~~Association, ~~the~~Inc. ~~commodity~~These ~~derivative~~ contracts toallow ~~the~~for ~~forecasted~~rights ~~transactions.~~of ~~The~~offset ~~MGP assesses, both~~ at the ~~inception~~time of ~~the~~settlement ~~derivative~~of ~~and on an ongoing basis, whether~~ the ~~derivative~~derivatives. ~~was~~Due ~~effective~~to ~~in offsetting changes in~~ the ~~forecasted~~right ~~cash flow~~ of ~~the~~offset, ~~hedged~~derivatives ~~item.~~are Ifrecorded on the ~~MGP~~Partnership’s ~~determines~~balance ~~that~~sheets ~~a derivative is not effective~~ as aassets ~~hedge~~ or ~~that~~liabilities itat ~~has~~fair ~~ceased~~value toon ~~be an effective hedge due to~~ the ~~loss~~basis of ~~adequate correlation between~~ the ~~hedging~~net ~~instrument~~exposure ~~and~~to ~~the~~each ~~underlying~~counterparty. ~~item~~Potential ~~being~~credit ~~hedged,~~risk ~~the~~adjustments ~~MGP~~are ~~will~~also ~~discontinue~~analyzed ~~hedge~~based ~~accounting~~upon ~~for~~ the ~~derivative~~net ~~and~~exposure ~~subsequent~~to ~~changes~~each incounterparty. ~~the~~Premiums ~~derivative~~paid ~~fair~~for ~~value,~~purchased ~~which~~options are ~~determined~~recorded ~~by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss)~~ on ~~mark-to-market derivatives in~~ the Partnership’s ~~statements~~balance ofsheets ~~operations. For derivatives qualifying~~ as ~~hedges,~~ the ~~Partnership~~initial ~~recognizes the effective portion of changes in fair~~ value of ~~derivative instruments as accumulated other comprehensive income and reclassifies~~ the ~~portion~~options. ~~relating~~The ~~to the~~ Partnership’s ~~commodity~~reflected ~~derivatives~~net toderivative ~~gas~~assets ~~and~~on ~~oil~~its ~~production~~balance ~~revenues~~sheets ~~within the Partnership’s statements~~ of ~~operations~~$103,600 asand ~~the~~$95,000 ~~underlying~~at ~~transactions~~December ~~are~~31, ~~settled.~~2015 ~~For non-qualifying derivatives~~ and ~~for the ineffective portion of qualifying derivatives~~2014, ~~the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur~~respectively.

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 $95,000 and $42~~,100 at December 31, 2014 and 2013, respectively.~~

~~The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices.~~ At ~~any~~December ~~point in time~~31, 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 positions2015, ~~but may be settled by~~ the ~~physical~~Partnership ~~delivery~~had of the following commodity. ~~Crude~~derivatives: oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

At December 31, 2014, the Partnership had the following commodity derivatives:

Natural Gas Put Options

ProductionPeriod EndingDecember 31,	Volumes(MMBtu)(1)		AverageFixed Price(per MMBtu)(1)		Fair ValueAsset (2)
2015		49,400	$	4.00	$	51,700
2016		62,300	$	4.15	$	103,600
2016		49,400		4.15		43,300
					$	95,000

(1)

“MMBtu” represents million British Thermal Units.

(2)

Fair value based on forward NYMEX natural gas prices, as applicable.

~~Effects~~The offollowing ~~Derivative~~table ~~Instruments~~summarizes onthe ~~Statements~~gains or losses recognized within the statements of ~~Operations:~~operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2014 and 2013:

	Years Ended December 31,
	2015		2014
Gains reclassified from accumulated other comprehensive income into natural gas, oil, and liquids revenues	$	13,200	$	36,800
Gains subsequent to hedge accounting recognized in gain on mark-to-market derivatives	$	68,500	$	-

	Years Ended December 31,
	2014		2013
Gains from cash flow hedges reclassified from accumulated other comprehensive loss into natural gas and oil revenues	$	36,800	$	50,300

Put Premiums Payable

AsDuring ~~the~~June ~~underlying~~2012, ~~prices~~a ~~and~~premium ~~terms~~(“put inpremium”) ~~the~~was ~~Partnership’s~~paid ~~derivative~~to ~~contracts~~purchase ~~were~~the ~~consistent~~contracts ~~with~~and ~~the~~will ~~indices~~be ~~used~~allocated to ~~sell its~~ natural gas ~~and~~production ~~oil,~~revenues ~~there~~generated ~~were~~over nothe ~~gains~~contractual orterm ~~losses~~of ~~recognized~~the ~~during~~purchased ~~the~~hedging ~~years~~instruments. ~~ended~~At December 31, ~~2014~~2015 and ~~2013~~2014, ~~for~~the ~~hedge~~put ~~ineffectiveness~~premiums orwere recorded as ashort-term ~~result~~payables to affiliate of ~~the~~$47,800 ~~discontinuance~~and $33,200, respectively, and long-term payables to affiliate of ~~any~~$0 ~~cash~~and ~~flow~~$37,900, ~~hedges~~respectively.

Monetized Gains

At December 31, 2013, remaining hedge monetization cash proceeds of $88,100 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate. The Partnership allocated the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts. There were no amounts for monetized gains remaining due to the Partnership at December 31, 2014.

During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2014 and 2013, the put premiums were recorded as short-term payables to affiliate of $33,200 and $31,900, respectively, and long-term payables to affiliate of $37,900 and $63,600, respectively.

The following table summarizes the gross and net fair values of the Partnership’s affiliate balances on the Partnership’s balance sheets for the periods indicated:

Offsetting Assets	GrossAmounts ofRecognizedAssets			GrossAmountsOffset in theBalance Sheets				Net Amount of AssetsPresented in theBalance Sheets
As of December 31, 2014
Accounts receivable monetized gains-affiliate	$	-	$		-		$		-
Total	$	-	$		-		$		-
As of December 31, 2013
Accounts receivable monetized gains-affiliate	$	88,100	$		(31,900	)	$		56,200
Total	$	88,100			(31,900	)			56,200

Offsetting Liabilities	GrossAmounts ofRecognizedLiabilities			GrossAmountsOffset in theBalance Sheets			Net Amount ofLiabilities Presentedin the Balance Sheets
As of December 31, 2014
Put premiums payable-affiliate	$	(33,200	)		$	-		$	(33,200	)
Long-term put premiums payable-affiliate		(37,900	)			-			(37,900	)
Total	$	(71,100	)		$	-		$	(71,100	)
As of December 31, 2013
Put premiums payable-affiliate	$	(31,900	)		$	31,900		$	-
Long-term put premiums payable-affiliate		(63,600	)			-			(63,600	)
Total	$	(95,500	)		$	31,900		$	(63,600	)

Accumulated Other Comprehensive Loss

As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive loss of $23,900 as of December 31, 2014. During the current year, $20,900 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $23,900 of net unrealized gains in accumulated other comprehensive loss, the Partnership will reclassify $18,500 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining gains of $5,400 in later periods.

NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1–Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2–Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3–Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The ~~carrying 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 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.

Information for assets and liabilities measured at fair value ~~at December 31, 2014 and 2013~~ was as follows:

As of December 31, 2014	Level 1		Level 2		Level 3		Total
As of December 31, 2015	Level 1		Level 2		Level 3		Total
Derivative assets, gross
Commodity puts	$	-	$	95103,~~000~~600	$	-	$	95103,~~000~~600
Derivative liabilities, gross
As of December 31, 2014
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	95,000	$	-	$	95,000
As of December 31, 2013
Derivative assets, gross
Commodity puts	$	-	$	4295,~~100~~000	$	-	$	4295,~~100~~000
Derivative liabilities, gross
Commodity puts		-		-		-		-
Total derivative, fair value, net	$	-	$	42,100	$	-	$	42,100

Other Financial Instruments

The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale of such financial instruments. The Partnership’s other current assets and liabilities on its balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership’s ~~other~~estimates ~~current~~the ~~assets~~fair ~~and~~value ~~liabilities~~of its asset retirement obligations based on ~~its~~discounted ~~balance~~cash ~~sheets~~flow ~~are~~projections ~~considered~~using tonumerous beestimates, ~~financial~~assumptions ~~instruments.~~and ~~The~~judgments ~~estimated~~regarding ~~fair~~factors ~~values~~at the date of ~~these~~establishment ~~instruments~~of ~~approximate~~an ~~their~~asset ~~carrying~~retirement obligation such as: amounts ~~due~~and totiming ~~their~~of ~~short~~settlements, the credit-~~term~~adjusted ~~nature~~risk-free rate of the Partnership and ~~thus~~estimated ~~are~~inflation ~~categorized~~rates (See Note 5:). There were no adjustments to retirement obligations for the year ended December 31, 2015. Adjustments to retirement obligations, defined as Level 13, measured at fair value on a nonrecurring basis was $2,901,800 for the year ended December 31, 2014.

The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the year ended December 31, 2015, the Partnership recognized a $3,053,900 and $6,914,500, respectively, of impairment of long-lived assets which was defined as a Level 3 fair value measurement (See Note 4: Property, Plant, and Equipment)

The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (See Note 5:). Adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis was $2,901,800, for the year ended December 31, 2014. There were no adjustments to retirement obligations, defined as Level 3, measured at fair value on a nonrecurring basis, for the year ended December 31, 2013.

The Partnership estimates the fair value of its long-lived assets in conjunction with the review of assets for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the year ended December 31, 2014, the Partnership recognized a $6,895,900, impairment of long-lived assets which was defined as a Level 3 fair value measurement (See Note 2:– Impairment of Long-Lived Assets). No impairments were recognized for the year ended December 31, 2013.

NOTE 8—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $296 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

	Years Ended December 31,
	2014		2013
	2015		2014
Administrative fees	$	~~348~~296,~~600~~400	$	~~364~~348,~~800~~600
Supervision fees		1,~~377~~171,~~400~~300		1,~~441~~377,~~500~~400
Transportation fees		~~561~~266,~~300~~600		~~698~~561,~~000~~300
Direct Costs		882,700		980,800
Direct costs		660,200		882,700
Total	$	32,~~170~~394,~~000~~500	$	3,~~485~~170,~~100~~000

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

NOTE 9—COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the total outstanding units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2015 and 2014, the MGP withheld $140,500 and $95,100, respectively, of net production revenue for future plugging and abandonment costs.

Legal Proceedings

The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 10—SUBSEQUENT EVENTS

Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

NOTE 11—SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED)

Gas and Oil Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. The ~~accompanying~~ reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas America Public #15-2006 (B) L.P. annual Form 10-K for the years ended December 31, ~~2014~~2015 and ~~2013~~2014 (See Note 2). For the periods presented, Wright & Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 3839 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The MGP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 1617 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the MGP’s Senior Engineering Staff and management, with final approval by the MGP’s ~~Chief Operating Officer~~President.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil, and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. InThe ~~accordance with the prevailing accounting literature, the~~ proved reserves quantities and future net cash flows as of December 31, ~~2014~~2015 and ~~2013~~2014 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, ~~2014~~2015 and ~~2013~~2014, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of gas and oil reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in gas and oil prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows:

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2013		9,011,600			11,500
Revisions⁽¹⁾		624,400			(1,100)
Production		(1,154,000	)		(2,500	)
Balance, December 31, 2014		8,482,000			7,900
Revisions ⁽²⁾		(5,077,800	)		(2,500	)
Production		(986,100	)		(1,700	)
Balance, December 31, 2015 ⁽³⁾		2,418,100			3,700

(1)

The upward revision in natural gas forecasts is primarily due to forecasts adjustments in order to reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustments in order to better reflect actual production.

(2)

The downward revision in natural gas and oil forecasts is primarily due to forecast adjustments in order to reflect actual production.

(3)

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2012		4,522,500			8,800
Revisions(1)		5,768,100			5,700
Production		(1,279,000	)		(3,000	)
Balance, December 31, 2013		9,011,600			11,500
Revisions (2)		624,400			(1,100	)
Production		(1,154,000	)		(2,500	)
Balance, December 31, 2014		8,482,000			7,900

(1) The upward revision in natural gas and oil forecasts is primarily due to an increase in SEC base pricing from prior year, resulting in longer economic life.

(2) The upward revision in natural gas forecasts is primarily due to forecasts adjustments in order to reflect actual production. The downward revision in oil forecasts is primarily due to forecast adjustments in order to better reflect actual production.

Capitalized Costs Related to Gas and Oil Producing Activities. The components of capitalized costs related to gas and oil producing activities of the Partnership during the periods indicated were as follows:

	Years Ended December 31,
	2014			2013
	2015			2014
Natural gas and oil properties:
Leasehold interest	$	43,~~179~~944,~~600~~100		$	4,179,600
Wells and related equipment		~~186~~180,~~298~~678,~~000~~600			~~183~~186,~~397~~298,~~500~~000
Accumulated depletion, accretion and impairment		(~~182~~180,~~107~~275,~~300~~400	)		(~~174~~182,~~241~~107,~~100~~300	)
Net capitalized costs	$	84,~~370~~347,300		$	138,~~336~~370,~~000~~300

Results of Operations from Gas and Oil Producing Activities. The results of operations related to the Partnership’s gas and oil producing activities during the periods indicated were as follows:

	Years Ended December 31,
	2014			2013
	2015			2014
Revenues	$	41,~~407~~697,~~600~~000		$	54,~~156~~407,~~000~~600
Production costs		(2,~~762~~038,~~200~~100	)		(32,~~053~~762,~~600~~200	)
Depletion		(~~951~~267,700	)		(2951,~~030,800~~700	)
Impairment		(63,~~914~~053,~~500~~900	)		-(6,914,500	)
	$	(63,~~220~~662,~~800~~700	)	$	71(6,~~600~~220,800	)

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015 and 2014, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:

	Years Ended December 31,
	2015⁽¹⁾			2014
Future cash inflows	$	4,001,300		$	30,757,500
Future production costs		(3,150,400	)		(19,132,300	)
Future net cash flows		850,900			11,625,200
Less 10% annual discount for estimated timing of cash flows		(188,000	)		(4,474,500	)
Standardized measure of discounted future net cash flows	$	662,900		$	7,150,700

(1)

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of the Partnership’s gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations.

Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved gas and oil reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2014 and 2013, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:

	Years Ended December 31,
	2014			2013
Future cash inflows	$	30,757,500		$	34,531,500
Future production costs		(19,132,300	)		(21,318,900	)
Future net cash flows		11,625,200			13,212,600
Less 10% annual discount for estimated timing of cash flows		(4,474,500	)		(5,172,700	)
Standardized measure of discounted future net cash flows	$	7,150,700		$	8,039,900

ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A: CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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 December 31, ~~2014~~2015, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 Internal Control – Integrated Framework (COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, ~~2014~~2015. This annual report does not include an attestation report by our registered public accounting firm regarding internal control over financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.

There have been no changes in our internal control over financial reporting during ~~the~~our ~~fourth~~most ~~quarter~~recent offiscal ~~2014~~quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us.

Officers and Key Operations Employees of Our General Partner

The following table sets forth information with respect to those persons who serve as the officers of and on the board of directors of, our general partner:

Name	Age		Position(s)
Sean P. McGrath		43	Chief Financial Officer
Jeffrey M. Slotterback		33	Chief Financial Officer
Matthew A. Jones		53	Senior Vice President and President of ARP
Freddie M. Kotek		59	Senior Vice President of Investment Partnership Division

~~Sean~~Daniel PC. ~~McGrath~~Herz has served as Executive Vice President of the MGP since May 2011. He has served as ARP’s Chief ~~Financial~~Executive Officer since August 2015 and as President of ~~our~~Atlas ~~general~~Energy ~~partner~~Group since ~~February~~April ~~2012~~2015. Mr. ~~McGrath~~ Herz has served as ~~Chief~~President ~~Financial~~and ~~Officer~~a director of ~~Atlas~~the ~~Energy’s~~ general partner ~~from~~of ~~February~~Atlas ~~2011~~Growth ~~until~~Partners, ~~February~~L.P. ~~2015~~since its inception in 2013. Mr. ~~McGrath~~ ~~was~~Herz ~~Chief~~served ~~Accounting~~as ~~Officer~~Senior Vice President of Corporate Development and Strategy of Atlas Energy, ~~Inc~~Group from March 2012 to April 2015. ~~and~~Mr. Herz ~~Chief~~served ~~Accounting~~as ~~Officer~~Senior Vice President of Corporate Development and Strategy of Atlas Energy’s ~~Resources,~~general ~~LLC~~partner from ~~December~~February ~~2008~~2011 until February ~~2011~~2015. Mr. ~~McGrath~~Herz ~~served~~was asSenior ~~Chief~~Vice ~~Accounting~~President ~~Officer~~of Corporate Development of Atlas ~~Energy~~Pipeline Partners GP, LLC from ~~January~~August ~~2006~~2007 until ~~November~~February ~~2009~~2015. ~~and~~He asalso ~~Chief~~was ~~Accounting~~Senior ~~Officer~~Vice President of Corporate Development of Atlas ~~Pipeline~~Energy, ~~Partners~~Inc. GPand Atlas Energy Resources, LLC from ~~May~~August ~~2005~~2007 until ~~November~~February ~~2009~~2011. Before that, Mr. ~~McGrath~~Herz was ~~Controller~~Vice President of ~~Sunoco~~Corporate ~~Logistics~~Development ~~Partners~~of ~~L.P.~~Atlas ~~(a publicly-traded partnership that transports~~Energy, ~~terminals~~Inc. and ~~stores~~Atlas ~~refined~~Pipeline ~~products~~Partners ~~and~~GP, ~~crude~~LLC ~~oil)~~ from ~~2002~~December ~~until~~2004 ~~2005.~~and ~~Mr. McGrath~~of isAtlas aEnergy’s ~~Certified~~general ~~Public~~partner ~~Accountant.~~from January 2006.

~~Matthew~~Freddie AM. ~~Jones~~Kotek has ~~served~~been asChairman ~~our general partner’s Senior Vice President and President~~ of ~~ARP~~the MGP since ~~February~~September ~~2015. Before~~2001 ~~that, he was President~~ and ~~Director~~has ofserved ~~our general partner from March 2012 until February 2015, and~~ as its Chief ~~Operating~~Executive Officer ~~from~~and ~~March~~President ~~2012~~since ~~until~~January ~~October 2013~~2002. ~~Mr. Jones~~He has served as aARP’s Senior Vice President of ~~Atlas~~the ~~Energy’s~~Investment ~~general~~Partnership ~~partner~~Division ~~and~~since ~~President~~August 2015 and ~~Chief~~served ~~Operating~~as ~~Officer~~Senior ofVice ~~the~~President ~~exploration~~of ~~and~~Investment ~~production~~Partnership ~~division~~Division of Atlas Energy’s ~~general~~Group ~~partner~~since ~~from~~March ~~February 2011 until February 2015~~2012. Mr. ~~Jones~~ ~~was~~Kotek ~~Chief~~has ~~Financial~~also ~~Officer~~served ofas ~~Atlas~~Executive ~~Energy,~~Vice ~~Inc.~~President ~~from~~and ~~March~~a ~~2005~~director ~~until~~of ~~February~~the ~~2011~~board ~~and~~of ~~Executive~~directors ~~Vice~~of ~~President~~the general partner of Atlas ~~Energy~~Growth Partners, ~~Inc~~L.P. ~~from~~since ~~October~~its ~~2009~~inception ~~until~~in ~~February 2011~~2013. Mr. ~~Jones~~Kotek ~~was~~served ~~Chief~~as ~~Financial~~Senior ~~Officer~~Vice President of ~~Atlas~~the ~~Energy~~Investment ~~Resources,~~Partnership ~~LLC~~Division ~~and~~of Atlas Energy’s ~~Management,~~general ~~Inc.~~partner from ~~June~~February ~~2006~~2011 until February ~~2011~~2015. Mr. ~~Jones~~Kotek ~~served~~was asan ~~Chief~~Executive ~~Financial~~Vice ~~Officer~~President of Atlas Energy GP, ~~LLC~~Inc. from ~~January~~February ~~2006~~2004 until ~~September~~February ~~2009~~2011 and served as a ~~member~~director ~~of the Board of Directors of Atlas Energy GP, LLC~~ from ~~February~~September ~~2006~~2001 tountil February ~~2011~~2004. Mr. ~~Jones~~Kotek ~~served~~also aswas Chief Financial Officer of Atlas ~~Pipeline Partners GP~~Energy, ~~LLC~~Inc. from ~~March~~February ~~2005~~2004 tountil ~~September~~March ~~2009~~2005. ~~From 1996 to 2005,~~ Mr. ~~Jones~~Kotek ~~worked~~was ina ~~the~~Senior ~~Investment~~Vice ~~Banking~~President ~~Group~~of atResource ~~Friedman~~America, ~~Billings~~Inc. ~~Ramsey,~~from ~~concluding~~1995 asuntil ~~Managing~~May ~~Director,~~2004 and inPresident ~~its~~of ~~Energy~~Resource ~~Investment~~Leasing, ~~Banking Group from 1999 to 2005~~Inc. ~~Mr. Jones is~~ (a ~~Chartered~~wholly ~~Financial~~owned ~~Analyst.~~subsidiary ~~Mr. Jones brings extensive financial and operational knowledge to our company and to the board~~ of ~~directors~~Resource ~~of our general partner~~America, ~~derived~~Inc.) from ~~his~~1995 ~~long~~until ~~background~~May ~~of service to our predecessors~~2004.

Jeffrey M. Slotterback has served as Chief Financial Officer of each of the MGP and ARP since September 2015. Mr. Slotterback has served as Chief Financial Officer of Atlas Energy Group since September 2015 and served as its Chief Accounting Officer from March 2012 to October 2015. Mr. Slotterback has also served as the Chief Financial Officer of the general partner of Atlas Growth Partners, L.P. since September 2015 and served as its Chief Accounting Officer from its inception in 2013 to October 2015. Mr. Slotterback served as Chief Accounting Officer of Atlas Energy’s general partner from March 2011 until February 2015. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and then served as the Manager of Financial Reporting for Atlas Energy GP, LLC from February 2011 until March 2011. Mr. Slotterback served as Manager of Financial Reporting for both Atlas Energy GP, LLC and Atlas Pipeline Partners GP, LLC from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.

Freddie M. Kotek has served as Senior Vice President of Investment Partnership Division of our general partner since March 2012. Mr. Kotek served as Senior Vice President of the Investment Partnership Division of Atlas Energy’s general partner from February 2011 until February 2015. Mr. Kotek was an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek also was Chief Financial Officer of Atlas Energy, Inc. from February 2004 until March 2005. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and Chief Executive Officer and President since January 2002. Mr. Kotek was a Senior Vice President of Resource America, Inc. from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly owned subsidiary of Resource America, Inc.) from 1995 until May 2004.

Key Operations Employees

Mark D. Schumacher has served as the Chief Operating Officer of ~~our~~the ~~general~~MGP ~~partner~~since January 2014. He has served as ARP’s President since ~~October~~April ~~2013~~2015 and as a Senior Vice President of Atlas Energy Group since April 2015. Mr. Schumacher served as Chief Operating Officer of Atlas Energy Group from October 2013 to April 2015. Mr. Schumacher has been the Executive Vice President of ~~our~~Operations of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. He served as Executive Vice President of Atlas Energy from July 2012 to October 2013. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which weARP acquired in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher was an engineer with Union Pacific Resources from 1984 to 2000. Mr. Schumacher has over 29 years of experience in drilling, production and reservoir engineering management, operations and business development in East Texas, Austin Chalk, Barnett Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada.

Dave Leopold has served as Senior Vice President of Operations of our general partner since December 2013 and served as Regional Vice President of Operations from March 2013 to December 2013. From March 2008 to February 2013, Mr. Leopold was the Operations Manager for Chesapeake Energy in Fort Worth, Texas where he led the Barnett Shale operations team to become the second largest producer in the play. From August 2000 to September 2006, Mr. Leopold held various management positions at Anadarko Petroleum Corporation, most recently serving as Production Engineering Manager over the Austin Chalk, Bossier Shale and what is now known as the Eagle Ford Shale. From 1991 to 2000, Mr. Leopold held various engineering and management roles with Union Pacific Resources in Fort Worth, Texas. From 1987 to 1991, he held drilling and reservoir engineering roles with Plains Petroleum Operating Company in Kansas and Colorado.

Code of Business Conduct and Ethics

Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a code of business conduct and ethics that applies to the principal executive officer, principal financial officer, and principal accounting officer of our general partner, as well as to persons performing services for us generally. We will make a printed copy of our code of ethics available to any limited partner who so requests. Requests for print copies may be directed to us as follows: Atlas Resource Partners, L.P., Park Place Corporate Center One, 1000 Commerce Drive, 4^th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct is also posted, and any waivers we grant thereunder will be posted, on our website at www.atlasresourcepartners.com.

ITEM 11: EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our general partner and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy Group. Pursuant to our partnership agreement, our general partner manages our operations and activities through its and its affiliates’ employees (including employees of Atlas Energy Group and its general partner). No officer or director of our MGP receives any direct remuneration or other compensation from us. (See “Item 13: Certain Relationships and Related Transactions” for a discussion of compensation paid by us to our MGP).

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, ~~2014~~2015, we had 14,772.60 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us for purchase, the MGP is not obligated by the Partnership Agreement to purchase more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by ~~Atlas Resource Partners~~ARP, whose ultimate parent was Atlas Energy Group at December 31, ~~2014~~2015.

ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our Relationship with Atlas ~~Resource~~Resources, LLC

Gas and Oil Revenues. Our MGP is allocated 33.25% of our gas and oil revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 10.60% of our subscriptions, its payment of 65.83% of the tangible costs and 3.09% of intangible costs of drilling and completing our wells and its contributions to us of all of our gas and oil leases for a total capital contribution of $52,509,500. During the ~~years~~year December 31, 2015, our MGP paid $118,200 for our net production expenses. During the year ended December 31, 2014 ~~and 2013~~, our MGP received $554,000 ~~and~~for ~~$709~~our net production revenues,~~900,~~ respectively. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $296 per well per month for ~~our~~operating ~~net~~and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production ~~revenues~~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.

Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $296 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of working interest in a well. Transportation fees are included in production expenses in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf.

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

	Years Ended December 31,
	2014		2013
	2015		2014
Administrative fees	$	~~348~~296,~~600~~400	$	~~364~~348,~~800~~600
Supervision fees		1,~~377~~171,~~400~~300		1,~~441~~377,~~500~~400
Transportation fees		~~561~~266,~~300~~600		~~698~~561,~~000~~300
Direct Costs		~~882~~660,~~700~~200		~~980~~882,~~800~~700
Total	$	32,~~170~~394,~~000~~500	$	3,~~485~~170,~~100~~000

Other Compensation. For the years ended December 31, ~~2014~~2015 and ~~2013~~2014, our MGP did not advance any funds to us, nor did it provide us with any equipment, supplies or other services.

ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, ~~2014~~2015 and ~~2013~~2014, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:

	Years Ended December 31,
	2014		2013
	2015		2014
Audit fees	$	3330,~~200~~000	$	33,~~700~~200

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during ~~2014~~2015 and ~~2013~~2014.

PART IV

ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT INDEX

	Description	~~Location~~
4(a)	Certificate of Limited Partnership for Atlas America Public #15-2006 (B) L.P. (1)	~~Previously filed in our Form S-1 on April 17, 2006~~
4(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #15-2006 (B) L.P. (1)	~~Previously filed in our Form S-1 on April 17, 2006~~
4(c)	Drilling and Operating Agreement for Atlas America Public #15-2006 (B) L.P. (1)	~~Previously filed in our Form S-1 on April 17, 2006~~
23.1	Consent of Wright & Company, Inc.
31.1	Rule 13a-14(a)/15(d) – 14 (a) Certification
31.2	Rule 13a-14(a)/15(d) – 14 (a) Certification.
32.1	Section 1350 Certification.
32.2	Section 1350 Certification.
99.1	Summary Reserve Report
101	Interactive Data File

(1) Filed on April 17, 2006 in ~~the~~our Form S-1 Registration Statement dated April 17, 2006, as amended, File No. 0-52168

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	ATLAS RESOURCES PARTNERS L.P.
	ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
	BY: ATLAS RESOURCE PARTNERS GP, LLC, ITS GENERAL PARTNER
	BY: ATLAS RESOURCES, LLC, ITS GENERAL PARTNER
	ATLAS ENERGY L.P.
Date: April 14, 2016	By:	/s/ FREDDIE M. KOTEK
Date: March 31, 2015	By:	/s/ FREDDIE M. KOTEK
		Freddie M. Kotek, Chairman of the Board and Chief Executive Officer (principal executive officer)
		Freddie M. Kotek, Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person on behalf of the registrant and in the capacities and on the dates indicated.

Date: March 31, 2015	By:	/s/ SEAN P. MCGRATH
Date: April 14, 2016	By:	/s/ FREDDIE M. KOTEK
		Sean P. McGrath, Chief Financial Officer
		Freddie M. Kotek, Chairman of the Board and Chief Executive Officer (principal executive officer)

Date: April 14, 2016		By:	/s/ JEFFREY M. SLOTTERBACK
			Jeffrey M. Slotterback, Chief Financial Officer (principal financial officer and principle accounting officer)

Date: April 14, 2016		By:	/s/ MATTHEW J. FINKBEINER
			Matthew J. Finkbeiner, Chief Accounting Officer (principal accounting officer)

Date: April 14, 2016		By:	/s/ DANIEL C. HERZ
			Daniel C. Herz, Executive Vice President and Director

Filing Compare · Atlas America Public #15-2006 (B) L.P.