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United States
Securities and Exchange Commission
 Washington, D.C. 20549
 Form 10-K
  þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2010
 o
    
    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 0-52168
 ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
  Delaware
    
    20-3208390(State or other jurisdiction of
    
    (I.R.S. EmployerIncorporation or organization)
    
    Identification No.)Westpointe Corporate Center One1550 Coraopolis Heights Road, 2nd FloorMoon Township, PA
    
    15108(Address of principal executive offices)
    
    (Zip Code)
 (412) 262-2830
  Title of each class 
None
    
    Name of each exchange on which registered
None
 
 o þ
 o þ
 þ o
 þ
  Large accelerated filer o
    
    Accelerated filer o
    
    Non-accelerated filer o
    
    Smaller reporting company þ
 o þ




---



##### 



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO ANNUAL REPORT
ON FORM 10-K
 PAGEPART IItem 1: Business
    
    
    3-5Item 2: Properties
    
    
    5-9Item 3: Legal Proceedings
    
    
    10Item 4: (Removed and Reserved)
    
    
    10PART IIItem 5: Market for Registrants Common Equity and Related Security Holder Matters
    
    
    10Item 7: Managements Discussion and Analysis of Financial Condition or Plan of Operations
    
    
    11-14Item 8: Financial Statements
    
    
    15-34Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
    
    
    34Item 9A: Controls and Procedures
    
    
    34-35Item 9B: Other Information
    
    
    35PART IIIItem 10: Directors and Executive Officers of the Registrant
    
    
    35-37Item 11: Executive Compensation
    
    
    37Item 12: Security Ownership of Certain Beneficial Owners and Management
    
    
    37Item 13: Certain Relationships and Related Party Transactions
    
    
    37Item 14: Principal Accountant Fees and Services
    
    
    38PART IVItem 15: Exhibits
    
    
    38SIGNATURES
    
    
    39EX-23.1EX-31.1EX-31.2EX-32.1EX-32.2EX-99.1
   2




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The matters discussed within this report include forward-looking statements. These statements
may be identified by the use of forward-looking terminology such as anticipate, believe,
continue, could, estimate, expect, intend, may, might, plan, potential,
predict, should, or will, or the negative thereof or other variations thereon or comparable
terminology. In particular, statements about our expectations, beliefs, plans, objectives,
assumptions or future events or performance contained in this report are forward-looking
statements. We have based these forward-looking statements on our current expectations,
assumptions, estimates and projections. While we believe these expectations, assumptions, estimates
and projections are reasonable, such forward-looking statements are only predictions and involve
known and unknown risks and uncertainties, many of which are beyond our control. These and other
important factors may cause our actual results, performance or achievements to differ materially
from any future results, performance or achievements expressed or implied by these forward-looking
statements.
 
 PART I
 
 ITEM 1.
    
    BUSINESS
 General.
      3




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
    
    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.
   Markets and Competition.
  Governmental Regulation.
 Regulation of oil and gas producing activities.
  4




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
    
    new well permit and well registration requirements, procedures and fees;
 
    
    minimum well spacing requirements;
 
    
    restriction on well locations and underground gas storage;
 
    
    certain well site restoration, groundwater protection and safety measures;
 
    
    landowner notification requirements;
 
    
    certain bonding or other security measures;
 
    
    various reporting requirements;
 
    
    well plugging standards and procedures; and
 
    
    broad enforcement powers.
 Environmental and Safety Regulation.
  Where can you find more information.
  
 
 ITEM 2.
    
    PROPERTIES
 Drilling Activity .
 Summary of Producing Wells .
 Number of Producing WellsGross
    
    
    NetGas
    
    
    510
    
    
    
    460.92Oil
    
    
    38
    
    
    
    38.00Total
    
    
    548
    
    
    
    498.92
  5




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Production.
 AverageYear
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production CostEnded
    
    Production
    
    
    Average Sales Price
    
    
    (Lifting Cost)December 31,
    
    Oil (bbls) (1)
    
    
    Gas (mcf) (1)
    
    
    per bbl (1)
    
    
    per mcf (1)
    
    
    per mcfe (1) (2)2010
    
    
    4,300
    
    
    
    1,651,200
    
    
    $
    74.02
    
    
    $
    6.62
    
    
    $
    2.422009
    
    
    5,700
    
    
    
    1,840,400
    
    
    $
    61.66
    
    
    $
    7.98
    
    
    $
    2.52
 
 (1)
    
    Mcf represents one thousand cubic feet of natural gas. Mcfe represents a thousand
cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per
barrel (bbl).(2)
    
    Lifting costs include labor to operate the wells and related equipment, repairs
and maintenance, materials and supplies, property taxes, insurance and gathering
charges.(3)
    
    Average sales prices represent accrual basis pricing after reversing the effect
of previously recognized gains resulting from prior period impairment charges.(4)
    
    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 $1,151,700 and $3,766,000 for the years
ended December 31, 2010 and 2009, respectively. The derivative gains are included in
other comprehensive income and resulted from prior period impairment charges.(5)
    
    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 $37,600 and $65,800 for the years ended
December 31, 2010 and 2009, respectively. The derivative gains are included in other
comprehensive income and resulted from prior period impairment charges. Natural Gas and Oil Reserve Information.
 
    
    Introduce a new definition of oil and gas producing activities. This new definition
allows companies to include in their reserve base volumes from unconventional resources.
Such unconventional resources include bitumen extracted from oil sands and oil and gas
extracted from coal beds and shale formations.
 
    
    Report oil and gas reserves using an unweighted average price using the prior 12-month
period, based on the closing prices on the first day of each month, rather than year-end
pricing. This should maximize the comparability of reserve estimates among companies and
mitigate the distortion of the estimates that arises when using a single pricing date.
 
    
    Permit companies to disclose their probable and possible reserves on a voluntary basis.
Current rules limit disclosure to only proved reserves.
 
    
    Update and revise reserve definitions to reflect changes in the oil and gas industry and
new technologies. New updated definitions include by geographic area and reasonable
certainty.
 
    
    Permit the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
 
    
    Require additional disclosures regarding the qualifications of the chief technical
person who oversees the companys overall reserve estimation process. Additionally,
disclosures are required related to internal controls over reserve estimation, as well as a
report addressing the independence and qualifications of a companys reserves preparer or
auditor based on Society of Petroleum Engineers criteria.
  6




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December 31,2010
    
    
    2009Natural gas (per mcf)
    
    $
    4.38
    
    
    $
    3.87Oil ( per bbl)
    
    
    79.43
    
    
    
    61.18
   7




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At December 31,2010
    
    
    2009Natural gas reserves  proved developed reserves (Mcf) (1) (2) (4)
    
    
    11,933,300
    
    
    
    12,872,600Oil reserves  Proved Reserves (Bbl) (1) (2) (4)
    
    
    17,800
    
    
    
    20,500Total proved reserves (Mcfe)
    
    
    12,040,100
    
    
    
    12,995,600PV-10 estimate of cash flows of proved reserves (3) (4)
    
    $
    14,961,700
    
    
    $
    15,284,700PV-10 estimate per limited partner unit (5)
    
    $
    676
    
    
    $
    691Undiscounted estimate per limited partner unit (5)
    
    $
    1,124
    
    
    $
    1,127
 
 (1)
    
    Proved reserves generally refers to the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in existing prices provided
only by contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic production is supported by either actual
production or conclusive formation test. The area of a reservoir considered proved
includes: that portion delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of available geological and
engineering data.(2)
    
    Proved developed oil and gas reserves generally refers to reserves that can be
expected to be recovered through existing wells with existing equipment and operating
methods.(3)
    
    The present value of estimated future net cash flows is calculated by discounting
estimated future net cash flows by 10% annually.(4)
    
    Please see Regulation S-X rule 4-10 for complete definitions of each reserve
category.(5)
    
    This value per $10,000 unit is determined by following the methodology used for
determining our proved reserves using the data discussed above. However, this value does
not necessarily reflect the fair market value of a unit, and each unit is illiquid.
Also, the value of a unit for purposes of presentment of the unit to our MGP for
purchase is different, because it is calculated under a formula set forth in the
Partnership Agreement.  Title to Properties .
   8




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Acreage.
 Developed AcreageLocation
    
    Gross (1)
    
    
    Net (2)Pennsylvania
    
    
    10,028.81
    
    
    
    9,522.33Tennessee
    
    
    2,200.00
    
    
    
    1,678.75Ohio
    
    
    100.00
    
    
    
    75.00Total
    
    
    12,328.81
    
    
    
    11,276.08
 
 (1)
    
    A gross acre is an acre in which we own a working interest.(2)
    
    A net acre represents the actual working interest we own in one gross acre
divided by one hundred. For example, a 50% working interest in an acre is one gross
acre, but a .50 net acre. Delivery Commitments .
     9




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ITEM 3.
    
    LEGAL PROCEEDINGS
   
 ITEM 4.
    
    (REMOVED AND RESERVED)
  
 PART II
 
 ITEM 5.
    
    MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
 Market Information.
 
    
    our managing general partner 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 managing general partner 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.
  Holders.
 Distributions.
   
    
    $6,389,700 and $9,348,200 to our limited partners; and
 
    
    $1,414,400 and $3,987,500 to our managing general partner, respectively.
  10




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ITEM 7.
    
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS
    Results of Operations.
 Years Ended December 31,2010
    
    
    2009Production revenues (in thousands):Gas
    
    $
    9,774
    
    
    $
    10,921Oil
    
    
    280
    
    
    
    287Total
    
    $
    10,054
    
    
    $
    11,208Production volumes:Gas (mcf/day) (1)
    
    
    4,524
    
    
    
    5,042Oil (bbls/day) (1)
    
    
    12
    
    
    
    16Total (mcfe/day) (1)
    
    
    4,596
    
    
    
    5,138Average sales price: (2)Gas (per mcf) (1) (3)
    
    $
    6.62
    
    
    $
    7.98Oil (per bbl) (1) (4)
    
    $
    74.02
    
    
    $
    61.66Average production costs:As a percent of revenues
    
    
    40
    %
    
    
    42
    %Per mcfe (1)
    
    $
    2.42
    
    
    $
    2.52Depletion per mcfe
    
    $
    2.90
    
    
    $
    2.49
 
 (1)
    
    Mcf represents thousand cubic feet, mcfe represents thousand cubic feet
equivalent and bbls represents barrels. Bbls are converted to mcfe using the ratio of
six mcfs to one bbl.(2)
    
    Average sales prices represent accrual basis pricing after reversing the effect
of previously recognized gains resulting from prior period impairment charges.  11




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(3)
    
    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 $1,151,700 and $3,766,000 for the years
ended December 31, 2010 and 2009, respectively. The derivative gains are included in
other comprehensive income and resulted from prior period impairment charges.(4)
    
    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 $37,600 and $65,800 for the years ended
December 31, 2010 and 2009, respectively. The derivative gains are included in other
comprehensive income and resulted from prior period impairment charges. Natural Gas Revenues.
  Oil Revenue.
 Expenses.
     12




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Liquidity and Capital Resources.
     Critical Accounting Policies
 Use of estimates .
 Impairment of Long-Lived Assets.
  13




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Fair Value of Financial Instruments
  Level 1 
 Level 2 
 Level 3
   Reserve Estimates .
 Asset Retirement Obligations .
 Working Interest.
  14




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ITEM 8.
    
    FINANCIAL STATEMENTS
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
     
  15




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
BALANCE SHEETS
DECEMBER 31,
 2010
    
    
    2009ASSETSCurrent assets:Cash and cash equivalents
    
    $
    534,300
    
    
    $
    728,600Accounts receivable-affiliate
    
    
    1,872,500
    
    
    
    2,881,200Short-term hedge receivable due from affiliate
    
    
    1,872,300
    
    
    
    1,896,500Total current assets
    
    
    4,279,100
    
    
    
    5,506,300Oil and gas properties, net
    
    
    38,922,900
    
    
    
    46,184,800Long-term hedge receivable due from affiliate
    
    
    1,829,200
    
    
    
    1,560,900$
    45,031,200
    
    
    $
    53,252,000LIABILITIES AND PARTNERS CAPITALCurrent liabilities:Accrued liabilities
    
    $
    20,900
    
    
    $
    111,500Short-term hedge liability due to affiliate
    
    
    12,100
    
    
    
    22,900Total current liabilities
    
    
    33,000
    
    
    
    134,400Asset retirement obligations
    
    
    7,047,900
    
    
    
    5,149,700Long-term hedge liability due to affiliate
    
    
    316,900
    
    
    
    236,400Partners capital:Managing general partner
    
    
    9,644,200
    
    
    
    12,081,600Limited partners (14,772.60 units)
    
    
    26,234,700
    
    
    
    34,752,000Accumulated other comprehensive income
    
    
    1,754,500
    
    
    
    897,900Total partners capital
    
    
    37,633,400
    
    
    
    47,731,500$
    45,031,200
    
    
    $
    53,252,000
   16




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2010 AND 2009
 2010
    
    
    2009REVENUESNatural gas and oil
    
    $
    10,054,100
    
    
    $
    11,208,500Interest income
    
    
    600
    
    
    
    1,300Total revenues
    
    
    10,054,700
    
    
    
    11,209,800COST AND EXPENSESProduction
    
    
    4,057,500
    
    
    
    4,732,600Depletion
    
    
    4,861,100
    
    
    
    4,663,300Impairment of oil and gas properties
    
    
    3,498,100
    
    
    
    Accretion of asset retirement obligation
    
    
    309,000
    
    
    
    267,500General and administrative
    
    
    488,800
    
    
    
    494,400Total expenses
    
    
    13,214,500
    
    
    
    10,157,800Net (loss) earnings
    
    $
    (3,159,800
    )
    
    $
    1,052,000Allocation of net (loss) earnings:Managing general partner
    
    $
    194,500
    
    
    $
    1,060,000Limited partners
    
    $
    (3,354,300
    )
    
    $
    (8,000
    )Net loss per limited partnership unit
    
    $
    (227
    )
    
    $
    (1
    )
   17




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
YEARS ENDED DECEMBER 31, 2010 AND 2009
 2010
    
    
    2009Net (loss) earnings
    
    $
    (3,159,800
    )
    
    $
    1,052,000Other comprehensive income (loss):Unrealized holding gain on hedging contracts
    
    
    2,863,800
    
    
    
    1,515,900Less: reclassification adjustment for gains realized in net earnings
    
    
    (2,007,200
    )
    
    
    (1,622,500
    )Total other comprehensive income (loss)
    
    
    856,600
    
    
    
    (106,600
    )Comprehensive (loss) income
    
    $
    (2,303,200
    )
    
    $
    945,400
   18




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
STATEMENTS OF CHANGES IN PARTNERS CAPITAL
YEARS ENDED DECEMBER 31, 2010 AND 2009
 AccumulatedManaging
    
    
    
    
    
    
    OtherGeneral
    
    
    Limited
    
    
    ComprehensivePartner
    
    
    Partners
    
    
    Income (Loss)
    
    
    TotalBalance at December 31, 2008
    
    $
    15,496,500
    
    
    $
    43,512,500
    
    
    $
    1,004,500
    
    
    $
    60,013,500Participation in revenue and expenses:Net production revenues
    
    
    2,153,200
    
    
    
    4,322,700
    
    
    
    
    
    
    
    6,475,900Interest income
    
    
    400
    
    
    
    900
    
    
    
    
    
    
    
    1,300Depletion
    
    
    (840,300
    )
    
    
    (3,823,000
    )
    
    
    
    
    
    
    (4,663,300
    )Accretion of asset retirement obligations
    
    
    (88,900
    )
    
    
    (178,600
    )
    
    
    
    
    
    
    (267,500
    )General and administrative
    
    
    (164,400
    )
    
    
    (330,000
    )
    
    
    
    
    
    
    (494,400
    )Net earnings (loss)
    
    
    1,060,000
    
    
    
    (8,000
    )
    
    
    
    
    
    
    1,052,000Subordination
    
    
    (122,500
    )
    
    
    122,500
    
    
    
    
    
    
    
    Working interest adjustment
    
    
    (473,200
    )
    
    
    473,200
    
    
    
    
    
    
    
    Asset contributions
    
    
    108,300
    
    
    
    
    
    
    
    
    
    
    
    108,300Other comprehensive loss
    
    
    
    
    
    
    
    
    
    
    (106,600
    )
    
    
    (106,600
    )Distributions to partners
    
    
    (3,987,500
    )
    
    
    (9,348,200
    )
    
    
    
    
    
    
    (13,335,700
    )Balance at December 31, 2009
    
    $
    12,081,600
    
    
    $
    34,752,000
    
    
    $
    897,900
    
    
    $
    47,731,500Participation in revenue and expenses:Net production revenues
    
    
    1,993,900
    
    
    
    4,002,700
    
    
    
    
    
    
    
    5,996,600Interest income
    
    
    200
    
    
    
    400
    
    
    
    
    
    
    
    600Depletion
    
    
    (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 earnings (loss)
    
    
    194,500
    
    
    
    (3,354,300
    )
    
    
    
    
    
    
    (3,159,800
    )Other comprehensive income
    
    
    
    
    
    
    
    
    
    
    856,600
    
    
    
    856,600Subordination
    
    
    (1,226,700
    )
    
    
    1,226,700
    
    
    
    
    
    
    
    Asset contributions
    
    
    9,200
    
    
    
    
    
    
    
    
    
    
    
    9,200Distributions 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
   19




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2010 AND 2009
 2010
    
    
    2009Cash flows from operating activities:Net (loss) earnings
    
    $
    (3,159,800
    )
    
    $
    1,052,000Adjustments to reconcile net (loss) earnings to net cash provided by
operating activities:Depletion
    
    
    4,861,100
    
    
    
    4,663,300Non-cash losses on derivative
    
    
    682,200
    
    
    
    3,831,800Impairment of oil and gas properties
    
    
    4,005,200
    
    
    
    Accretion of asset retirement obligation
    
    
    309,000
    
    
    
    267,500(Decrease) increase in accrued liabilities
    
    
    (90,600
    )
    
    
    89,300Decrease in accounts receivable affiliate
    
    
    1,008,700
    
    
    
    2,618,400Net cash provided by operating activities
    
    
    7,615,800
    
    
    
    12,522,300Cash flows from investing activities:Proceeds from sale of tangible equipment
    
    
    4,600
    
    
    
    136,800Purchase of tangible equipment
    
    
    (10,600
    )
    
    
    Net cash (used in) provided by operating activities
    
    
    (6,000
    )
    
    
    136,800Cash flows from financing activities:Distributions to partners
    
    
    (7,804,100
    )
    
    
    (13,335,700
    )Net cash used in by financing activities
    
    
    (7,804,100
    )
    
    
    (13,335,700
    )Net decrease in cash and cash equivalents
    
    
    (194,300
    )
    
    
    (676,600
    )Cash and cash equivalents at beginning of period
    
    
    728,600
    
    
    
    1,405,200Cash and cash equivalents at end of period
    
    $
    534,300
    
    
    $
    728,600Supplemental Schedule of non-cash investing and financing activities:Assets contributed by the managing general partner:Tangible equipment
    
    $
    
    
    
    $
    83,200Intangible drilling costs
    
    
    9,200
    
    
    
    25,100$
    9,200
    
    
    $
    108,300Asset retirement obligation revision
    
    $
    1,589,200
    
    
    $
    423,400
   20




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
 NOTE 1  DESCRIPTION OF BUSINESS
   NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
  Use of Estimates
   Accounts Receivable and Allowance for Possible Losses
   21




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
 NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 Fair Value of Financial Instruments
  Supplemental Cash Flow Information
  Concentration of Credit Risk
  Oil and Gas Properties
   Impairment of Long-Lived Assets
   22




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
 NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 Impairment of Long-Lived Assets (Continued)
    Working Interest
  Revenue Recognition
   23




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
 NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 Revenue Recognition (Continued)
  Asset Retirement Obligation
  Environmental Matters
   Comprehensive (Loss) Income
   24




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
 NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 Recently Adopted Accounting Standards
    Major Customers
   25




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 2  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 Income Taxes
  NOTE 3  PARTICIPATION IN REVENUES AND COSTS
  ManagingGeneral
    
    
    LimitedPartner
    
    
    PartnersOrganization 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, and the MGP revenue percentage may not exceed 40%.(2)
    
    These costs will be charged to the partners in the same ratio as the related
production revenues are credited. NOTE 4  OIL AND GAS PROPERTIES
  December 31,2010
    
    
    2009Natural gas and oil properties:Proved properties:Leasehold interests
    
    $
    4,196,500
    
    
    $
    4,196,500Wells and related equipment
    
    
    185,018,800
    
    
    
    183,414,400189,215,300
    
    
    
    187,610,900Accumulated depletion
    
    
    (150,292,400
    )
    
    
    (141,426,100
    )$
    38,922,900
    
    
    $
    46,184,800
 NOTE 5  ASSET RETIREMENT OBLIGATIONS
   26




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 5  ASSET RETIREMENT OBLIGATIONS (Continued)
   Years Ended December 31,2010
    
    
    2009Asset retirement obligation at beginning of year
    
    $
    5,149,700
    
    
    $
    4,458,800Revision in estimates
    
    
    1,589,200
    
    
    
    423,400Accretion expense
    
    
    309,000
    
    
    
    267,500Asset retirement obligation at end of year
    
    $
    7,047,900
    
    
    $
    5,149,700
 NOTE 6  DERIVATIVE INSTRUMENTS
    27




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 6  DERIVATIVE INSTRUMENTS (Continued)
   Fair Value of Derivative Instruments:
 Asset Derivatives
    
    
    
    
    Liability DerivativesDerivatives in
    
    
    
    Fair Value
    
    
    
    
    Fair ValueCash Flow
    
    Balance Sheet
    
    December 31,
    
    
    December 31,
    
    
    Balance sheet
    
    December 31,
    
    
    December 31,Hedging Relationships
    
    Location
    
    2010
    
    
    2009
    
    
    Location
    
    2010
    
    
    2009Commodity Contracts
    
    Current Assets
    
    $
    1,872,300
    
    
    $
    1,896,500
    
    
    Current liabilities
    
    $
    (12,100
    )
    
    $
    (22,900
    )Long-Term Assets
    
    
    1,829,200
    
    
    
    1,560,900
    
    
    Long-term liabilities
    
    
    (316,900
    )
    
    
    (236,400
    )Total Derivatives
    
    
    
    $
    3,701,500
    
    
    $
    3,457,400
    
    
    
    
    $
    (329,000
    )
    
    $
    (259,300
    )
 Effects of Derivative Instruments on Statement of Operations:
 Gain
    
    
    
    
    GainRecognized in OCI on Derivative
    
    
    
    
    Reclassified from OCI into Net (Loss) Income(Effective Portion)
    
    
    Location of Gain
    
    (Effective Portion)Derivatives in
    
    Twelve Months Ended
    
    
    Reclassified from Accumulated
    
    Twelve Months EndedCash Flow
    
    December 31,
    
    
    December 31,
    
    
    OCI into (Loss) Income
    
    December 31,
    
    
    December 31,Hedging Relationships
    
    2010
    
    
    2009
    
    
    (Effective Portion)
    
    2010
    
    
    2009Commodity Contracts
    
    $
    2,863,800
    
    
    $
    1,515,900
    
    
    Natural Gas and Oil Revenue
    
    $
    2,007,200
    
    
    $
    1,622,500
    28




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 6  DERIVATIVE INSTRUMENTS (Continued)
  Natural Gas Fixed Price Swaps
 Production
    
    
    
    
    
    AveragePeriod Ending
    
    Volumes
    
    
    Fixed Price
    
    
    Fair ValueDecember 31,
    
    (MMbtu) (1)
    
    
    (per MMbtu) (1)
    
    
    Asset (2)2011
    
    
    539,100
    
    
    $
    6.964
    
    
    $
    1,320,4002012
    
    
    303,200
    
    
    
    7.485
    
    
    
    724,4002013
    
    
    196,800
    
    
    
    6.803
    
    
    
    272,9002014
    
    
    92,100
    
    
    
    5.942
    
    
    
    36,600$
    2,354,300
 Natural Gas Costless Collars
 Production
    
    
    
    
    
    
    
    AveragePeriod Ending
    
    Option
    
    Volumes
    
    
    Floor & Cap
    
    
    Fair ValueDecember 31,
    
    Type
    
    (MMbtu) (1)
    
    
    (per MMbtu) (1)
    
    
    Asset/(Liability) (2)2011
    
    Puts purchased
    
    
    263,600
    
    
    $
    6.535
    
    
    $
    550,4002011
    
    Calls sold
    
    
    263,600
    
    
    
    7.653
    
    
    
    (6,700
    )2012
    
    Puts purchased
    
    
    162,700
    
    
    
    6.102
    
    
    
    244,6002012
    
    Calls sold
    
    
    162,700
    
    
    
    7.328
    
    
    
    (41,200
    )2013
    
    Puts purchased
    
    
    275,800
    
    
    
    5.862
    
    
    
    398,2002013
    
    Calls sold
    
    
    275,800
    
    
    
    7.043
    
    
    
    (175,700
    )2014
    
    Puts purchased
    
    
    95,500
    
    
    
    5.705
    
    
    
    135,8002014
    
    Calls sold
    
    
    95,500
    
    
    
    6.811
    
    
    
    (89,600
    )$
    1,015,800
 Crude Oil Fixed Price Swaps
 Production
    
    
    
    
    
    AveragePeriod Ending
    
    Volumes
    
    
    Fixed Price
    
    
    Fair ValueDecember 31,
    
    (Bbl) (1)
    
    
    (per Bbl) (1)
    
    
    Liability (3)2011
    
    
    500
    
    
    $
    87.703
    
    
    $
    (2,600
    )2012
    
    
    300
    
    
    
    87.299
    
    
    
    (2,200
    )2013
    
    
    100
    
    
    
    87.632
    
    
    
    (500
    )2014
    
    
    
    
    
    
    
    
    
    
    $
    (5,300
    )
  29




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 6  DERIVATIVE INSTRUMENTS (Continued)
 Crude Oil Costless Collars
 Production
    
    
    
    
    
    
    
    AveragePeriod Ending
    
    Option
    
    Volumes
    
    
    Floor & Cap
    
    
    Fair ValueDecember 31,
    
    Type
    
    (Bbl) (1)
    
    
    (per Bbl) (1)
    
    
    Asset/(Liability) (3)2011
    
    Puts purchased
    
    
    300
    
    
    $
    76.818
    
    
    $
    6002011
    
    Calls sold
    
    
    300
    
    
    
    100.965
    
    
    
    (1,800
    )2012
    
    Puts purchased
    
    
    200
    
    
    
    76.143
    
    
    
    1,3002012
    
    Calls sold
    
    
    200
    
    
    
    101.596
    
    
    
    (2,300
    )2013
    
    Puts purchased
    
    
    100
    
    
    
    76.148
    
    
    
    5002013
    
    Calls sold
    
    
    100
    
    
    
    102.587
    
    
    
    (700
    )2014
    
    Puts purchased
    
    
    
    
    
    
    
    
    
    
    2014
    
    Calls sold
    
    
    
    
    
    
    
    
    
    
    $
    (2,400
    )Total Net Asset
    
    
    $
    3,362,400
 
 (1)
    
    MMBTU represents million British Thermal Units. Bbl represents barrels.(2)
    
    Fair value based on forward NYMEX natural gas prices, as applicable.(3)
    
    Fair value based on forward WTI crude oil prices, as applicable. NOTE 7  FAIR VALUE OF FINANCIAL INSTRUMENTS
  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
   30




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 7  FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
  NOTE 8  CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
  
    
    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, 2010 and 2009 were $415,300
and $416,200, respectively.
 
    
    Monthly well supervision fees which are included in production expenses in the
Partnerships statements of operations are generally payable at $296 per well per month for
operating and maintaining the wells. Well supervision fees incurred for the years ended
December 31, 2010 and 2009 were $1,641,000 and $1,644,600, respectively.
 
    
    Transportation fees which are included in production expenses in the Partnerships
statements of operations are payable at 13% of the natural gas sales price. Transportation
fees incurred for the years ended December 31, 2010 and 2009 were $1,300,400 and
$1,731,500, 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, 2010 and 2009 were $1,189,600 and $1,434,700, respectively.
 
    
    Assets contributed by the MGP, which are disclosed on the Partnerships statement of
cash flows as a non-cash investing activity for the years ended December 31, 2010 and 2009
were $9,200 and $108,300, respectively.
  Subordination by Managing General Partner
   31




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ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010 AND 2009
 NOTE 9  COMMITMENTS AND CONTINGENCIES
   Legal Proceedings
   NOTE 10  NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
 (1) Capitalized Costs Related to Oil and Gas Producing Activities
  December 31,2010
    
    
    2009Leasehold interest:
    
    $
    4,196,500
    
    
    $
    4,196,500Wells and related equipment
    
    
    185,018,800
    
    
    
    183,414,400Accumulated depletion
    
    
    (150,292,400
    )
    
    
    (141,426,100
    )Net capitalized cost
    
    $
    38,922,900
    
    
    $
    46,184,800
 (2) Oil and Gas Reserve Information
   32




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010
 NOTE 10  NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
   Natural Gas
    
    
    Oil(Mcf)
    
    
    (Bbls)Balance at December 31, 2008
    
    
    17,726,300
    
    
    
    29,700Production
    
    
    (1,840,400
    )
    
    
    (5,700
    )Revisions to previous estimates
    
    
    (3,013,300
    )
    
    
    (3,500
    )Balance at December 31, 2009
    
    
    12,872,600
    
    
    
    20,500Production
    
    
    (1,651,200
    )
    
    
    (4,300
    )Revisions to previous estimates
    
    
    711,900
    
    
    
    1,600Balance at December 31, 2010
    
    
    11,933,300
    
    
    
    17,800
 NOTE 11  SUBSEQUENT EVENTS
 Atlas Energy, Inc. Asset Acquisition
  Laurel Mountain Sale
   33




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##### Table of Contents



ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
NOTES TO FINANCIAL STATEMENTS  (Continued)
DECEMBER 31, 2010
 NOTE 11  SUBSEQUENT EVENTS (Continued)
 Hedge Monetization
  
 ITEM 9.
    
    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:
  
 ITEM 9A.
    
    CONTROLS AND PROCEDURES
 Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
   Managements Report on Internal Control over Financial Reporting
 Internal Control  Integrated
Framework
  34




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##### Table of Contents



ITEM 9B.
    
    OTHER INFORMATION
  
 PART III
 
 ITEM 10.
    
    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 nd
 Executive Officers and Directors.
 NAME
    
    AGE
    
    POSITION OR OFFICEFreddie M. Kotek
    
    
    55
    
    
    Chairman of the Board of Directors, Chief Executive
Officer and PresidentJeffrey C. Simmons
    
    
    52
    
    
    Executive Vice President  Operations and a DirectorJack L. Hollander
    
    
    54
    
    
    Senior Vice President  Direct Participation ProgramsSean McGrath
    
    
    39
    
    
    Chief Financial Officer
  
    
    the approximate amount of an individuals professional time devoted to the business and
affairs of our MGP and Atlas Energy have been aggregated because there is no reasonable
method for them to distinguish their activities between the two companies; and
 
    
    for those individuals who also hold senior positions with other affiliates of our MGP,
if it is stated that they devote approximately 100% of their professional time to our MGP
and Atlas Energy, it is because either the other affiliates are not currently active in
drilling new wells, such as Viking Resources or Resource Energy, and the individuals are
not required to devote a material amount of their professional time to the affiliates, or
there is no reasonable method to distinguish their activities between our MGP and Atlas
Energy as compared with the other affiliates of our MGP, such as Viking Resources or
Resource Energy.
  35




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##### Table of Contents



Freddie M. Kotek
 Jeffrey C. Simmons.
 Jack L. Hollander.
 Sean P. McGrath
 Audit Committee Financial Expert.
 Remuneration of Officers and Directors.
  36




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##### Table of Contents



Code of Business Conduct and Ethics. nd
 
 ITEM 11.
    
    EXECUTIVE COMPENSATION
  
 ITEM 12.
    
    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
  
 ITEM 13.
    
    CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
 Oil and Gas Revenues.
 Administrative Costs.
 Direct Costs.
 Well Charges.
 Transportation Fees.
 Other Compensation.
  37




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##### Table of Contents



ITEM 14.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
 Audit Fees.
 Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of
Independent Auditor.
 
 PART IV
 
 ITEM 15.
    
    EXHIBITS
 
 EXHIBIT INDEX
 Description
    
    Location4
    (a)
    
    Certificate of Limited Partnership for Atlas
America Public #15-2006 (B) L.P.
    
    Previously filed in
our Form S-1 on
August 9, 20054
    (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, 20054
    (c)
    
    Drilling and Operating Agreement for Atlas
America Public #15-2006 (B) L.P.
    
    Previously filed in
our Form S-1 on
August 9, 200523.1
    
    
    Consent of Wright and Company, Inc.31.1
    
    
    Rule 13a-14(a)/15(d)  14 (a) Certification31.2
    
    
    Rule 13a-14(a)/15(d)  14 (a) Certification.32.1
    
    
    Section 1350 Certification.32.2
    
    
    Section 1350 Certification.99.1
    
    
    Summary Reserve Report
 
 (1)
    
    Filed on April 17, 2006 in the Form S-1 Registration Statement dated April 17, 2006, File No. 0-52168  38




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##### Table of Contents



SIGNATURES
   Atlas Resources, LLC, Managing General PartnerDate:  March 30, 2011
    By:
    /s/ Freddie M. KotekFreddie M. Kotek,Chairman of the Board of Directors,
Chief Executive Officer and President  Date: March 30, 2011
    By:
    /s/ Freddie M. KotekFreddie M. Kotek,Chairman of the Board of Directors,
Chief Executive Officer and PresidentDate: March 30, 2011
    By:
    /s/ Jeffrey C. SimmonsJeffrey C. Simmons,Executive Vice President  OperationsDate: March 30, 2011
    By:
    /s/ Sean P. McGrathSean 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
   39