Atlas America Public #15-2006 10-K 2011 FY Annual report

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, 2011

¨ 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 #15-2006 (B) L.P.

(Exact name of registrant as specified in its charter)

Delaware	20-3208390
(State or other jurisdiction of Incorporation or organization)	(I.R.S. Employer Identification No.)
Park Place Corporate Center One 1000 Commerce Drive, 4th Floor Pittsburgh, PA	15275
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number (412) 489-0006

Securities registered under Section 12(b) of the Exchange Act.

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

Securities registered under 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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations 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 the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerating filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	x

DOCUMENTS INCORPORATED BY REFERENCE:

None

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

(A DELAWARE LIMITED PARTNERSHIP)

INDEX TO ANNUAL REPORT

ON FORM 10-K

		PAGE
PART I
Item 1:	Business		4-10
Item 2:	Properties		10-11
Item 3:	Legal Proceedings		11
Item 4:	Mine Safety Disclosures (Not Applicable)		11
PART II
Item 5:	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		12
Item 7:	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12-17
Item 8:	Financial Statements and Supplementary Data		18-38
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		38
Item 9A:	Controls and Procedures		38-39
PART III
Item 10:	Directors, Executive Officers and Corporate Governance		39-40
Item 11:	Executive Compensation		41
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		41
Item 13:	Certain Relationships and Related Transactions		41
Item 14:	Principal Accountant Fees and Services		42
PART IV
Item 15:	Exhibits		42
SIGNATURES			43

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GLOSSARY OF TERMS

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Condensate. Liquid hydrocarbons present in casing head gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

Developed acres. Acres spaced or assigned to productive wells.

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

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

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 termsstructural featureandstratigraphic conditionare intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

GAAP. Generally Accepted Accounting Principles.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

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.

MGP. Managing General Partner

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within gas.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. 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.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas that 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.

Reserves.Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

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.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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PART I

ITEM 1: BUSINESS

Atlas America Public #15-2006 (B) L.P. (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 “MGP”). Atlas Resources is an indirect subsidiary of Atlas Energy, L.P., formerly Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS). On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, 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”).

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, for administrative services. (See Item 11 “Executive Compensation”).

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 agreements. 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 developmental wells to the Clinton/Median, Upper Devonian Sandstones, Southern Appalachia Shale and Marcellus Shale geological formations in Pennsylvania, Tennessee, and Ohio.

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 third-party gas gathering systems. The majority of our natural gas and oil is delivered into the Laurel Mountain Midstream, LLC (“Laurel Mountain”) gas gathering system, a joint venture between Chevron and the Williams Companies, Inc. (NYSE: WMB). Laurel Mountain owns and operates all of APL’s previously owned northern Appalachian assets. Upon formation of the joint venture in May 2009, subsidiaries of Atlas Energy Inc., including 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.

We do not plan to sell any of our wells and will continue to produce them 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).

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 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, 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 the costs for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2011, our MGP had not withheld any funds for this purpose.

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Subsequent Events

Formation of Atlas Resource Partners, L.P.In February 2012, the board of directors of Atlas Energy’s general partner approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. (“Atlas Resource Partners”), which will hold substantially all of the Atlas Energy’s current natural gas and oil development and production assets and its partnership management business. In March 2012, Atlas Energy distributed approximately 19.6% limited partner interest in Atlas Resource Partners to its unitholders, retaining a 78.4% limited partner interest in Atlas Resource Partners, including our MGP. Atlas Energy, will also own the general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in Atlas Resource Partners. The transaction closed in the first quarter of 2012.

Contractual Revenue Arrangements

The MGP markets the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, and the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices. For the year ended December 31, 2011, South Jersey Resources Group LLC, Chevron Natural Gas, US Energy Exploration Corporation and Atmos Energy Marketing, LLC accounted for approximately 24%, 16%, 10% and 10% of our total natural gas and oil production revenues, respectively, with no other single customer accounting for more than 10% for this period.

Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

We do not have delivery commitments for fixed and determinable quantities of natural gas or oil in any future periods under existing contracts or agreements.

Markets and Competition

The availability including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas 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, of a ready market for natural gas and oil and the price obtained depends upon numerous factors beyond our control. Product availability and price are the principal means of competition in selling oil and natural gas. During the years ended December 2011 and 2010, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during those periods.

While it is impossible to accurately determine our competitive position in the industry, we do not consider our operations to be a significant factor in the industry.

Seasonal Nature of Business.Seasonal weather conditions and lease stipulations can limit our producing activities in certain areas of the Appalachian region and Michigan/Indiana. 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.

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Environmental Matters and Regulation

Overview.Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

• require the acquisition of various permits before drilling commences;

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

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

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

• impose substantial liabilities for pollution resulting from our operations; and

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

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 and could have a significant impact on our operating costs. We believe that our operations substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the two-year period ended December 31, 2011, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2012, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry 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 impact 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 production activities on federal lands 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.

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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 EPA, 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 the EPA 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.

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 we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act.The Comprehensive Environmental Response, Compensation and Liability Act, or 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 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. 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, remediate contaminated property 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, and analogous state laws 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 EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly.

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 our operations are in substantial compliance with the requirements of the Clean Water Act.

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Air Emissions.The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through permits and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic and other air pollutants at specified sources. Specific federal regulations applicable to the natural gas industry have been proposed under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”s). Final NSPS and NESHAP rules are anticipated in the spring of 2012 and will likely impose additional emissions control requirements and practices on our operations. Some of our new existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of compliance of our customers to the point where demand for natural gas is affected. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act.

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, the EPA 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 Gas Regulation and Climate Change.Natural gas contains methane, which is considered to be a greenhouse gas. Additionally, the burning of natural gas produces carbon dioxide, which is also a greenhouse gas. Published studies have suggested that the emission of greenhouse gases may be contributing to global warming. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More directly, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007)(holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact our business.

First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (Prevention of Significant Deterioration) and the operating permit program (Title V) 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 Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported starting in 2011 with the initial reports due in 2012. This rule imposes additional reporting obligations on us.

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.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussion 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.

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Finally, as noted above, 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.

Other Regulation of the Natural Gas and Oil Industry.The natural gas and oil industry is extensively regulated by numerous 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. 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 costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production.Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we will operate also regulate one or more of the following:

• the location of wells;

• the manner in which water necessary to develop wells is managed;

• the method of drilling and casing wells;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

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 wells. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

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State Regulation.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, Michigan imposes a 5% severance tax on natural gas and a 6.6% severance tax on oil, Tennessee imposes a 3% severance tax on natural gas and oil production and Ohio imposes a severance tax of $0.025 per Mcf of natural gas and $0.10 per Bbl of oil, Indiana imposes a severance tax of $.03 per MCF on natural gas and $.24 per bbl of oil, Colorado imposes a severance tax up to 5% of the value of oil and gas severed from earth, in addition to other applicable taxes, and West Virginia imposes a 5% severance tax on oil and gas. While Pennsylvania has not imposed a severance tax, there is legislation that has been approved by the Pennsylvania legislature and signed by the Governor that will impose an impact fee on oil and gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. 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 of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill.

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 business.

Employees

We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. (See Item 13 “Certain Relationships and Related Party Transactions” for a discussion of compensation paid by us to our MGP).

Available Information

We file 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 with the SEC. 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 4^th Floor, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the Securities and Exchange Commission’s website atwww.sec.gov. Any of our filings is 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

Productive 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, 2011. 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:

	Number of productive wells
	Gross		Net
Gas wells		510		460.92
Oil wells		38		38.00
Total		548		498.92

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Developed Acreage

The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2011.

	Developed acreage
	Gross(1)		Net(2)
Pennsylvania		10,028.81		9,522.33
Tennessee		2,200.00		1,678.75
Ohio		100.00		75.00
Total		12,328.81		11,276.08

(1) A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(2) Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acre.

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 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 in 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 Note 9 ofNotes to the Financial Statements).

ITEM 4: MINE SAFETY DISCLOSURES (Not Applicable)

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PART II

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

Market Information.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 consent;

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

• the transfer 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 terms 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.

Holders.As of December 31, 2011, we had 4,138 unit holders.

Distributions.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.

The determination of our revenues and costs is made in accordance with generally accepted accounting principles, consistently applied, and cash distributions to our MGP may only be made in conjunction with distributions to our limited partners.

During the years ended December 31, 2011 and 2010, we distributed the following:

• $4,557,000 and $6,389,700 to our limited partners; and

• $1,340,500 and $1,414,400 to our managing general partner, respectively.

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

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with the financial statements and related notes appearing elsewhere in this report.

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BUSINESS OVERVIEW

We are a Delaware limited partnership, formed on May 9, 2006 with Atlas Resources, LLC serving as our Managing General Partner (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc., (“Atlas Energy”) (NYSE: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

CONTRACTUAL REVENUE ARRANGEMENTS

Natural Gas. We market the majority of our natural gas production to gas utility companies, gas marketers, local distribution companies, industrial or other end-users, and companies generating electricity. The sales price of natural gas produced in the Appalachian Basin has been primarily based upon the NYMEX spot market price, the natural gas produced in the New Albany Shale and Antrim Shale has been primarily based upon the Texas Gas Zone SL and Chicago spot market prices.

Crude Oil. Crude oil produced from our wells flows directly into storage tanks where it is picked up by an oil company, a common carrier or pipeline companies acting for an oil company, which is purchasing the crude oil. We sell any oil produced by our Appalachian wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil.

We do not have delivery commitments for fixed and determinable quantities of natural gas or oil in any future periods under existing contracts or agreements.

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.

Natural Gas Supply and Outlook.The areas in which we operate are experiencing a decline in the development of shallow wells, but a significant increase in drilling activity related to new and increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques, including horizontal and multiple fracturing techniques. 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 by third parties in the development of new natural gas reserves.

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 Item 1: Business “Environmental Matters and Regulations”). 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 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 environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

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Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/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.

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,
	2011			2010
Production revenues (in thousands):
Gas	$	7,544		$	9,774
Oil		215			280
Total	$	7,759		$	10,054
Production volumes:
Gas (mcf/day)		4,086			4,524
Oil (bbls/day)		7			12
Total (mcfe/day)		4,128			4,596
Average sales price:(1)
Gas (per mcf)(2)	$	5.44		$	6.62
Oil (per bbl)(3)	$	86.47		$	74.02
Average production costs:
As a percent of revenues		45	%		40	%
Per mcfe	$	2.32		$	2.42
Depletion per mcfe	$	2.67		$	2.90

(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 and dividing by the total volume for the period. Previously recognized derivative gains were $575,000 and $1,151,700 for the years ended December 31, 2011 and 2010, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

(3) Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $18,900 and $37,600 for the years ended December 31, 2011 and 2010, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

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Natural Gas Revenues. Our natural gas revenues were $7,544,400 and $9,773,700 for the years ended December 31, 2011 and 2010, respectively, a decrease of $2,229,300 (23%). The $2,229,300 decrease in our gas revenues for the year ended December 31, 2011 as compared to prior year period was attributable to a $1,283,000 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions, and a $946,300 decrease in production volumes. Our production volumes decreased to 4,086 mcf per day for the year ended December 31, 2011 from 4,524 mcf per day for the year ended December 31, 2010, a decrease of 438 (10%) 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.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $214,500 and $280,400 for the years ended December 31, 2011 and 2010, respectively, a decrease of $65,900 (24%). The $65,900 decrease in oil revenues for the year ended December 31, 2011 as compared to the prior year period was attributable to a $104,200 decrease in production volumes, partially offset by a $38,300 increase in oil prices after the effect of financial hedges. Our production volumes decreased to 7 bbls per day for the year ended December 31, 2011 from 12 bbls per day for the year ended December 31, 2010, a decrease of 5 bbls per day (42%).

Expenses.Production expenses were $3,498,400 and $4,057,500 for the years ended December 31, 2011 and 2010, respectively, a decrease of $559,100 (14%). This decrease was primarily due to lower transportation expenses, which were affected by a decrease in production volumes.

Depletion of our oil and gas properties as a percentage of oil and gas revenues was 52% and 48% for the years ended December 31, 2011 and 2010, respectively. These percentage changes were directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of oil and gas properties.

General and administrative expenses were $491,700 and $488,800 for the years ended December 31, 2011 and 2010, respectively, an increase of $2,900 (.6%). 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 timing and billing of the costs and services provided to us.

Impairment of oil and gas properties for the years ended December 31, 2011 and 2010 were $15,341,500 and $3,498,100, respectively. Annually, we compare the carrying value of our proved developed oil and gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2011 and 2010. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources. Cash provided by operating activities decreased $2,477,100 for the year ended December 31, 2011 to $5,138,700 as compared to $7,615,800 year ended December 31, 2010. This decrease was due to a decrease in net earnings before depletion, impairment, and accretion of $1,549,100, a non-cash gain on derivative value of $785,500, a decrease in the change in accounts receivable-affiliate of $250,900, partially offset by an increase in the change in accrued liabilities of $108,400.

Cash provided by investing activities was $10,600 during the year ended December 31, 2011. This was entirely due to proceeds from a sale of equipment. Cash used in investing activities was $6,000 during the year ended December 31, 2010. This consisted of proceeds from the sale and the purchase of tangible equipment.

Cash used in financing activities decreased $2,410,800 to $5,393,300 for the year ended December 31, 2011 from $7,804,100 for the year ended December 31, 2010. This decrease was due to a decrease in cash distributions to partners.

15

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2011, our MGP had not withheld any 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 may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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, depreciation and amortization, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements included in (Item 8 “Financial Statements”). The critical accounting policies and estimates we have identified are discussed below.

Depreciation and Impairment of Long-Lived Assets

The cost of oil and gas properties, less estimated salvage value, is depleted on the units-of-production method and is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable 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 of America and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions.

During the years ended December 31, 2011 and 2010, we recognized an impairment expense of $15,341,500 and $3,498,100, net of an offsetting gain in other comprehensive income of $697,200 and $507,100, respectively. These impairments related to the carrying amount of these oil and gas properties being in excess of our estimate of their fair value at December 31, 2011 and 2010. The estimate of the fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

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. 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.

16

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumption 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.

Our MGP uses a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. The 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.

Assets and liabilities that are required to be measured at fair value on a nonrecurring basis include our oil and gas properties and asset retirement obligations (“ARO’s”) 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 credit-adjusted risk-free rate and inflation rates.

Asset Retirement Obligations

On an annual basis, we estimate the cost of future dismantlement, restoration, reclamation, and abandonment of our operating assets. We also estimate the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and our credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties and other property, plant and equipment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation, and abandonment costs from those we have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

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 expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocate revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

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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, 2011 and 2010, and the related statements of operations, comprehensive loss, changes in partners’ capital, and cash flows for the years then ended. 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. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit 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, 2011 and 2010, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 30, 2012

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

BALANCE SHEETS

DECEMBER 31,

	2011		2010
ASSETS
Current assets:
Cash and cash equivalents	$	290,300	$	534,300
Accounts receivable-affiliate		1,864,500		1,872,500
Short-term hedge receivable due from affiliate		—		1,872,300
Total current assets		2,154,800		4,279,100
Oil and gas properties, net		19,256,200		38,922,900
Long-term hedge receivable due from affiliate		—		1,829,200
Long-term receivable-affiliate		489,900		—
	$	21,900,900	$	45,031,200
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	38,700	$	20,900
Short-term hedge liability due to affiliate		—		12,100
Total current liabilities		38,700		33,000
Asset retirement obligations		7,878,600		7,047,900
Long-term hedge liability due to affiliate		—		316,900
Partners’ capital:
Managing general partner		4,489,300		9,644,200
Limited partners (14,772.60 units)		9,471,700		26,234,700
Accumulated other comprehensive income		22,600		1,754,500
Total partners’ capital		13,983,600		37,633,400
	$	21,900,900	$	45,031,200

See accompanying notes to financial statements.

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

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2011 AND 2010

	2011			2010
REVENUES
Natural gas and oil	$	7,758,900		$	10,054,100
Interest income		400			600
Total revenues		7,759,300			10,054,700
COST AND EXPENSES
Production		3,498,400			4,057,500
Depletion		4,025,200			4,861,100
Impairment of oil and gas properties, net		15,341,500			3,498,100
Accretion of asset retirement obligation		422,900			309,000
General and administrative		491,700			488,800
Total expenses		23,779,700			13,214,500
Net loss	$	(16,020,400	)	$	(3,159,800	)
Allocation of net (loss) income:
Managing general partner	$	(3,237,300	)	$	194,500
Limited partners	$	(12,783,100	)	$	(3,354,300	)
Net loss per limited partnership unit	$	(865	)	$	(227	)

See accompanying notes to financial statements.

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

STATEMENTS OF COMPREHENSIVE LOSS

YEARS ENDED DECEMBER 31, 2011 AND 2010

	2011			2010
Net loss	$	(16,020,400	)	$	(3,159,800	)
Other comprehensive (loss) income:
Unrealized holding gains on hedging contracts		128,400			2,863,800
MGP portion of non-cash loss on hedge instruments		504,200			—
Difference in estimated monetized gains receivable		(879,200	)		—
Less: reclassification adjustment for gains realized in net loss		(1,485,300	)		(2,007,200	)
Total other comprehensive (loss) income		(1,731,900	)		856,600
Comprehensive loss	$	(17,752,300	)	$	(2,303,200	)

See accompanying notes to financial statements.

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

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2011 AND 2010

	Managing General Partner			Limited Partners			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2009	$	12,081,600		$	34,752,000		$	897,900		$	47,731,500
Participation in revenue and expenses:
Net production revenues		1,993,900			4,002,700			—			5,996,600
Interest income		200			400			—			600
Depletion		(892,300	)		(3,968,800	)		—			(4,861,100	)
Impairment		(642,100	)		(2,856,000	)					(3,498,100	)
Accretion of asset retirement obligations		(102,700	)		(206,300	)		—			(309,000	)
General and administrative		(162,500	)		(326,300	)		—			(488,800	)
Net income (loss)		194,500			(3,354,300	)		—			(3,159,800	)
Other comprehensive income		—			—			856,600			856,600
Subordination		(1,226,700	)		1,226,700			—			—
Asset contributions		9,200			—			—			9,200
Distributions to partners		(1,414,400	)		(6,389,700	)		—			(7,804,100	)
Balance at December 31, 2010	$	9,644,200		$	26,234,700		$	1,754,500		$	37,633,400
Participation in revenue and expenses:
Net production revenues		1,192,300			3,068,200			—			4,260,500
Interest income		100			300			—			400
Depletion		(752,200	)		(3,273,000	)		—			(4,025,200	)
Impairment		(3,373,400	)		(11,968,100	)		—			(15,341,500	)
Accretion of asset retirement obligations		(140,600	)		(282,300	)		—			(422,900	)
General and administrative		(163,500	)		(328,200	)		—			(491,700	)
Net loss		(3,237,300	)		(12,783,100	)		—			(16,020,400	)
Other comprehensive loss		—			—			(1,731,900	)		(1,731,900	)
Subordination		(577,100	)		577,100			—			—
Distributions to partners		(1,340,500	)		(4,557,000	)		—			(5,897,500	)
Balance at December 31, 2011	$	4,489,300		$	9,471,700		$	22,600		$	13,983,600

See accompanying notes to financial statements.

22

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

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2011 AND 2010

	2011			2010
Cash flows from operating activities:
Net loss	$	(16,020,400	)	$	(3,159,800	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion		4,025,200			4,861,100
Non-cash (gain) loss on derivative		(103,300	)		682,200
Impairment of oil and gas properties		16,038,700			4,005,200
Accretion of asset retirement obligation		422,900			309,000
Decrease in accounts receivable-affiliate		757,800			1,008,700
Increase (decrease) in accrued liabilities		17,800			(90,600	)
Net cash provided by operating activities		5,138,700			7,615,800
Cash flows from investing activities:
Proceeds from sale of tangible equipment		10,600			4,600
Purchase of tangible equipment		—			(10,600	)
Net cash provided by (used in) investing activities		10,600			(6,000	)
Cash flows from financing activities:
Distributions to partners		(5,393,300	)		(7,804,100	)
Net cash used in by financing activities		(5,393,300	)		(7,804,100	)
Net decrease in cash and cash equivalents		(244,000	)		(194,300	)
Cash and cash equivalents at beginning of period		534,300			728,600
Cash and cash equivalents at end of period	$	290,300		$	534,300
Supplemental Schedule of non-cash investing and financing activities:
Assets contributed by the managing general partner:
Intangible drilling costs	$	—		$	9,200
	$	—		$	9,200
Asset retirement obligation revision	$	407,800		$	1,589,200
Distribution to managing general partner	$	504,200		$	—

See accompanying notes to financial statements.

23

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

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND 2010

NOTE 1 – DESCRIPTION OF BUSINESS

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

On February 17, 2011, Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, 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”).

Formation of Atlas Resource Partners, L.P.In February 2012, the board of directors of Atlas Energy’s general partner approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. (“Atlas Resource Partners”), which will hold substantially all of the Atlas Energy’s current natural gas and oil development and production assets and its partnership management business. In March 2012 Atlas Energy distributed approximately 19.6% limited partner interest in the Atlas Resource Partners to its unitholders, retaining a 78.4% limited partner interest in Atlas Resource Partners, including our MGP. Atlas Energy, will also own the general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in Atlas Resource Partners. The transaction closed in the first quarter of 2012.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the years ended December 31, 2011 and 2010 represent actual results in all material respects (see“Revenue Recognition” accounting policy for further description).

24

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash Equivalents

The carrying amounts of the Partnership’s cash and receivables 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 on the balance sheets includes the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of its credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2011 and 2010, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.

The Partnership follows the successful efforts method of accounting for oil and gas 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 of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.

Impairment of Long-Lived Assets

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

25

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. 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 at December 31, 2011, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

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

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Drilling Partnership’s Agreement in order to recover these reserves.

During the years ended December 31, 2011 and 2010, the Partnership recognized an impairment expense of $15,341,500 and $3,498,100 asset impairment related to oil and gas properties, net of an offsetting gain in accumulated other comprehensive income of $697,200 and $507,100, respectively. These impairments related to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011 and 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Asset Retirement Obligations

Pursuant to prevailing accounting literature, the Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities (see Note 5). The Partnership recognizes a liability for 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 is required to consider estimated salvage value in the calculation of depreciation, depletion, and amortization.

26

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Income Taxes

The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.

The Partnership files income tax returns in the United States of America 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 2007. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2011.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The MGP 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 MGP maintains insurance which may cover in whole or in part certain environmental expenditures. At December 31, 2011 and 2010, the Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Concentration of Credit Risk

The Partnership natural gas is sold under contract to various purchasers in the normal course of business. For the year ended December 31, 2011, sales to South Jersey Resources Group LLC, Chevron Natural Gas, US Energy Exploration Corporation and Atmos Energy Marketing, LLC accounted for 24%, 16%, 10% and 10%, respectively, of total revenues excluding the impact of all financial derivative activity. For the year ended December 31, 2010, sales to Equitable Gas, South Jersey Resources Group LLC, Sequent Energy Management, Atmos Energy Marketing, LLC and U.S. Energy Exploration Corporation accounted for 15%, 14%, 14%, 10% and 10%, respectively, of total revenues, respectively, excluding the impact of all financial derivative activity. No other customers accounted for 10% or more of total revenues for the years ended December 31, 2011 and 2010.

27

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 reasonable 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 working interest and/or overriding royalty.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, which is generally fixed two business days prior to the commencement of the production month, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. The Partnership had unbilled revenues at December 31, 2011 and 2010 of $910,100 and $1,337,500, respectively, which were included in accounts receivable within the Partnership’s balance sheets.

Gains from the monetized hedge contracts resulting from the Transferred Business are recorded in accounts receivable-affiliate and long-term receivable-affiliate and are allocated to the Partnerships based on their participating pro-rata share of natural gas and oil production to the total of gas and oil production from all participating drilling partnerships. In November 2011, the MGP, in accordance with the Partnership agreement, created a new allocation process that reallocated the available hedge pool based on total production from all producing regions. In accordance with this retroactive reallocation, the Partnership recorded a decrease in previously recognized revenue net of transportation of $112,900.

Comprehensive Loss

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, are referred to as “other comprehensive income” and for the Partnership includes changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

28

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Accounting Standards

In December 2011, the FASB issued Accounting Standards Update 2011-12,Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05(Update 2011-12). The amendments in this update effectively defer implementation of changes made in Update 2011-05 related to the presentation of reclassification adjustments out of accumulated other comprehensive income. As a result, entities are required to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Update 2011-12 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 so that entities will not be required to comply with the presentation requirements in update 2011-05 that this Update is deferring. The Partnership will apply the requirements of Update 2011-12 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

In December 2011, the FASB issued Accounting Standards Update 2011-11,Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities(“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of this Update, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Update 2011-11 will be effective for annual reporting periods, and interim periods within those years, beginning on or after January 1, 2013. An entity should provide disclosures required by Update 2011-11 retrospectively for all comparative periods presented. The Partnership will apply the requirements of Update 2011-11 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

29

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Accounting Standards (Continued)

In May 2011, the FASB issued Accounting Standards Update 2011-04,Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. Update 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. Early adoption by public entities is not permitted. The Partnership will apply the requirements of Update 2011-04 upon its effective date of January 1, 2012, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

NOTE 3 – PARTICIPATION IN REVENUES AND COSTS

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

	Managing General Partner			Limited Partners
Organization and offering costs		100	%		0	%
Lease costs		100	%		0	%
Revenues(1)		33.25	%		66.75	%
Operating costs, administrative costs, direct and all other costs(2)		33.25	%		66.75	%
Intangible drilling costs		3.09	%		96.91	%
Tangible equipment costs		65.83	%		34.17	%

(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.

30

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at the dates indicated:

	December 31,
	2011			2010
Proved properties:
Leasehold interests	$	4,196,500		$	4,196,500
Wells and related equipment		185,416,000			185,018,800
		189,612,500			189,215,300
Accumulated depletion and impairment		(170,356,300	)		(150,292,400	)
	$	19,256,200		$	38,922,900

The Partnership recorded depletion expense on natural gas and oil properties of $4,025,200 and $4,861,100 for the years ended December 31, 2011 and 2010, 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 entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations.

During the years ended December 31, 2011 and 2010, the Partnership recognized a $16,038,700 and $4,005,200, respectively, asset impairment related to oil and gas properties on its balance sheets. These impairments related to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2011 and 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

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

The estimated liability is based on the Partnership’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 5 – ASSET RETIREMENT OBLIGATIONS (Continued)

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the years indicated is as follows:

	December 31,
	2011		2010
Asset retirement obligations, beginning of year	$	7,047,900	$	5,149,700
Accretion expense		422,900		309,000
Revisions in estimates		407,800		1,589,200
Asset retirement obligations, end of year	$	7,878,600	$	7,047,900

NOTE 6 – DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge forecasted natural gas, NGL, crude oil and condensate 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 natural gas, NGLs, crude oil and condensate are sold. Under commodity-based swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not the obligation, to receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including their risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassify the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occur.

32

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 6 – DERIVATIVE INSTRUMENTS (Continued)

Prior to the sale on February 17, 2011 of the Transferred Business, Atlas Energy, Inc. monetized its derivative instruments related to the Transferred Business. The monetized proceeds related to instruments that were originally put into place to hedge future natural gas and oil production of the Transferred Business, including production generated through its drilling partnerships. At December 31, 2011, the Partnership recorded a net receivable from the monetized derivative instruments of $749,800 in accounts receivable-affiliate and $489,900 in long-term receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive income on the Partnership’s balance sheets, which will be allocated to natural gas and oil production revenue generated over the period of the original instruments’ term. As a result of the monetization and the early settlement of natural gas and oil derivative instruments and the unrealized gains recognized in income in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheets in accumulated other comprehensive income of $22,600 as of December 31, 2011. Included in the balance of accumulated other comprehensive income are unrealized gains of $697,200, $151,800 and $368,200, net of the MGP interest, recognized into income as a result of oil and gas property impairments for the years ended December 31, 2011, December 31, 2010 and prior periods, respectively. In addition, the MGP’s portion of the unrealized gains, $504,200 was written-off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. As such, $504,200 was recorded as a distribution to partners on the statements of changes in partners’ capital. During the year ended December 31, 2011, $674,600 of monetized proceeds were recorded by the Partnership and allocated only to the limited partners. Of the remaining $22,600 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $72,900 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining $95,500 of net gains in later periods.

The following table summarizes the fair value of the Partnership’s own derivative instruments as of December 31, 2011 and 2010, as well as the gain or loss recognized in the statements of operations for effective derivative instruments for the years ended December 31, 2011 and 2010:

		December 31,
Contract Type	Balance Sheet Location	2011		2010
Asset Derivatives
Commodity contracts	Current portion of derivative asset	$	—	$	1,872,300
Commodity contracts	Long-term derivative asset		—		1,829,200
			—		3,701,500
Liability Derivatives
Commodity contracts	Current portion of derivative asset		—		(12,100	)
Commodity contracts	Long-term derivative asset		—		(316,900	)
			—		(329,000	)
Total derivatives		$	—	$	3,372,500
		December 31,
		2011		2010
Gain recognized in accumulated OCI		$	128,400	$	2,863,800
Gain reclassified from accumulated OCI into income		$	1,485,300	$	2,007,200

33

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 6 – DERIVATIVE INSTRUMENTS (Continued)

The MGP entered into natural gas and crude oil future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas prices and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

The Partnership recognized gains of $582,900 and $2,007,200 for the years ended December 31, 2011 and 2010, respectively, on settled contracts covering natural gas and oil production for historical periods prior to the acquisition of the Transferred Business. These gains are included within gas and oil production revenue in the Partnership’s consolidated combined statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2011 and 2010 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.

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. 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 assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). 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 fair value measurements.

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 7 – FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Information for assets and liabilities measured at fair value at December 31, 2011 and 2010 was as follows:

	Level 1		Level 2		Level 3		Total
December 31, 2011
Partnership commodity-based derivatives	$	—	$	—	$	—	$	—
December 31, 2010
Partnership commodity-based derivatives	$	—	$	3,372,500	$	—	$	3,372,500

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

The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 5). Information for assets that were measured at fair value on a nonrecurring basis for the years ended December 31, 2011 and 2010 were as follows:

	Years Ended December 31,
	2011				2010
	Level 3		Total		Level 3		Total
Asset retirement obligations	$	7,878,600	$	7,878,600	$	7,047,900	$	7,047,900

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under the 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. Administrative costs incurred for the years ended December 31, 2011 and 2010 were $407,000 and $415,300, respectively.

35

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 8 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

• 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 incurred for the years ended December 31, 2011 and 2010 were $1,607,200 and $1,641,000, respectively.

• Transportation fees which are included in production expenses in the Partnership’s statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the years ended December 31, 2011 and 2010 were $996,200 and $1,300,400, respectively.

• 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. Direct costs incurred for the years ended December 31, 2011 and 2010 were $979,700 and $1,189,600, respectively.

• Assets contributed from the MGP which are disclosed on the Partnership’s statements of cash flows as non-cash investing and financing activities for the year ended December 31, 2010 were $9,200.

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

Subordination by Managing General Partner

Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (March 2007) and expiring 60 months from that date. The MGP subordinated $577,100 and $1,226,700 of its net production revenue to the limited partners for the years ended December 31, 2011 and 2010, respectively.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

General Commitments

Subject to certain conditions, investor partners may present their interests beginning in 2011 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

36

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 9 – COMMITMENTS AND CONTINGENCIES (Continued)

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, 2011, the MGP has not withheld any such funds.

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 – NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

(1) Capitalized Costs Related to Oil and Gas Producing Activities

The following table presents the capitalized costs related to natural gas and oil producing activities at the periods indicated:

	December 31,
	2011			2010
Leasehold interests	$	4,196,500		$	4,196,500
Wells and related equipment		185,416,000			185,018,800
Accumulated depletion and impairment		(170,356,300	)		(150,292,400	)
Net capitalized cost	$	19,256,200		$	38,922,900

(2) Oil and Gas Reserve Information

The preparation of the Partnership’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2011, the Partnership retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2011. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.

The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed, net to the Partnership’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the previous two years. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.

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 the Partnership’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.

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

NOTES TO FINANCIAL STATEMENTS – (Continued)

DECEMBER 31, 2011 AND 2010

NOTE 10 – NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)

	Natural Gas (Mcf)			Oil (Bbls)
Proved developed reserves:
Balance at December 31, 2009		12,872,600			20,500
Production		(1,651,200	)		(4,300	)
Revisions to previous estimates(1)		711,900			1,600
Balance at December 31, 2010		11,933,300			17,800
Production		(1,491,300	)		(2,700	)
Revisions to previous estimates(1)		(176,000	)		500
Balance at December 31, 2011		10,266,000			15,600

(1) The change in estimate of natural gas reserves in 2011 was due to actual production not meeting expectations. The change in estimate of natural gas reserves in 2010 was due to actual production outperforming the previous year projection. The increase in the estimate of oil reserves for 2011 and 2010 was due to actual production outperforming expectations.

NOTE 11 – SUBSEQUENT EVENTS

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

Formation of Atlas Resource Partners, L.P.In February 2012, the board of directors of Atlas Energy’s general partner approved a plan to create a newly formed exploration and production master limited partnership named Atlas Resource Partners, L.P. (“Atlas Resource Partners”), which will hold substantially all of the Atlas Energy’s current natural gas and oil development and production assets and its partnership management business. In March 2012 Atlas Energy distributed approximately 19.6% limited partner interest in the Atlas Resource Partners to its unitholders, retaining a 78.4% limited partner interest in Atlas Resource Partners, including our MGP. Atlas Energy, will also own the general partner of Atlas Resource Partners, which will own a 2% general partner interest and all of the incentive distribution rights in Atlas Resource Partners. The transaction closed in the first quarter of 2012.

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.

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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, 2011, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management 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 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, 2011. This annual report does not include an attestation report by our registered public accounting firm regarding internal control financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Atlas Energy is headquartered at Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275, which is also our MGP’s primary office. The executive officers and directors of our MGP will serve until their successors are elected.

The following table sets forth information with respect to the executive officers and directors of our MGP:

Name	Age	Position with the MGP	Year in which service began
Sean P. McGrath	40	Chief Financial Officer	2011
Freddie M. Kotek	56	Senior Vice President of Investment Partnership Division and Director	2011
Jeffery C. Simmons	53	Executive Vice President – Operations and a Director	2001
Jack L. Hollander	55	Senior Vice President – Direct Participation Programs	2002

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Sean P. McGrath has been our Chief Financial Officer since February 2011. Before that he was the Chief Accounting Officer of AEI and the Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as the Chief Accounting Officer of our general partner from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. Mr. McGrath is a Certified Public Accountant.

Freddie M. Kotek has been a Senior Vice President of the Investment Partnership Division of our general partner since February 2011. Before that, he was the Executive Vice President of AEI from February 2004 until February 2011 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek served as AEI’s Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004.

Jeffrey C. Simmons.Executive Vice President-Operations and a Director since January 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Master’s degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas Energy and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jack L. Hollander.Senior Vice President – Direct Participation Programs since January 2002 and before that he served as Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President – Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Code of Business Conduct and Ethics and Partnership Governance Guidelines

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. Atlas Energy has also adopted Partnership Governance Guidelines. We will make a printed copy of the code of ethics, and the Partnership Governance Guidelines available to any limited partner who so requests. Requests for print copies may be directed to us as follows: Atlas Energy, L.P., Park Place Corporate Center One, 1000 Commerce Drive, 4^th. Floor, Pittsburgh, PA 15275, Attention: Secretary. Each of the code of business conduct and ethics and the Partnership Governance Guidelines are posted, and any waivers Atlas Energy grants to its code of business conduct and ethics will be posted, on its website at www.atlasenergy.com.

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ITEM 11: EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP receives any direct remuneration or other compensation from us. (See Item 13“Certain Relationships and Related Party Transaction” for a discussion of compensation paid by us to our MGP).

ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

As of December 31, 2011, 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 beginning in 2011 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 Energy Resources, LLC, whose ultimate parent is Atlas Energy.

ITEM 13: CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Oil and Gas Revenues. Our MGP is allocated 33.25% of our oil and gas 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 oil and gas leases for a total capital contribution of $52,509,500. During the years ended December 31, 2011 and 2010, our MGP received $1,192,300 and $1,993,900, respectively, for our net production revenues.

Administrative Costs.Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for the administrative costs they incur on our behalf of $75 per well per month, which is proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the years ended December 31, 2011 and 2010, our MGP received $407,000 and $415,300, respectively, for administrative costs.

Direct Costs.Our MGP and its affiliates are reimbursed by us for all direct costs expended by them on our behalf. During the years ended December 31, 2011 and 2010, our MGP was reimbursed $979,700 and $1,189,600, respectively, for direct costs.

Well Charges.Our MGP, as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amounts of $296 per well per month subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well. For the years ended December 31, 2011 and 2010, our MGP received $1,607,200 and $1,641,000, respectively, for well supervision fees.

Transportation Fees.We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. The transportation rate is generally 13% of the natural gas sales price. For the years ended December 31, 2011 and 2010, $996,200 and $1,300,400, respectively, was paid to our MGP for gathering fees. In turn, our MGP remitted 100% of these amounts to Atlas Energy, who in turn paid LMM for the use of LMM’s gathering system in transporting a majority of our natural gas production.

Other Compensation.For the years ended December 31, 2011 and 2010, our MGP did not advance any funds to us, or did it provide us with any equipment, supplies or other services.

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ITEM 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees.The aggregate fees billed by our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2011 and 2010, and for the review of the financial statements included in our Quarterly Reports on Form 10-Q during such years, were $34,500 and $33,200, respectively.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor.Pursuant to its charter, the Audit Committee of Atlas Energy is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. We do not have a separate audit committee.

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.	Previously filed in our Form S-1 on August 9, 2005
4(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #15-2006 (B) L.P.	Previously filed in our Form S-1 on August 9, 2005
4(c)	Drilling and Operating Agreement for Atlas America Public #15-2006 (B) L.P.(1)	Previously filed in our Form S-1 on August 9, 2005
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.
101	Interactive Data File

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

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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 America Public #15-2006 (B) L.P.
	ATLAS ENERGY L.P.
Date: March 30, 2012	By: /s/ FREDDIE M. KOTEK
	Freddie M. Kotek, Chairman of the Board of Directors, 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 30, 2012	By: /s/ SEAN P. MCGRATH
	Sean P. McGrath, Chief Financial Officer

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the

Exchange Act by Non-reporting Issuers

An annual report will be furnished to security holders subsequent to the filing of this report.

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