United
      StatesSecurities
      and Exchange CommissionWashington,
      D.C. 20549Form
      10-K(Mark
      One)R
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
      1934For
      the fiscal year ended December 31, 2008o
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF
      1934For
      the transition period from _____ to _____Commission
      file number 333-117035ATLAS
      AMERICA PUBLIC #14-2004 L.P.(Exact
      name of registrant as specified in its charter)Pennsylvania
            86-1111314(State
      or other jurisdiction of
              incorporation
      or organization)
            (I.R.S.
      Employer
              Identification
      No.)Westpointe
      Corporate Center One1550
      Coraopolis Heights Rd. 2nd FloorMoon
      Township, PA
            15108(Address
      of principal executive offices)
            (zip
      code)Registrant’s
      telephone number, including area code: (412)
      262-2830Securities
      registered under Section 12 (b) of the Exchange Act.Title
      of each class
            Name
      of each exchange on which registeredNone
            NoneSecurities
      registered under Section 12 (g) of the Exchange Act:  Investor
      General Partner Units and Limited Partner Units(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 þIndicate
      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 þIndicate
      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 þ 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 þIndicate
      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” 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 þIndicate
      by check mark whether the registrant is a shell company (as defined in
      Rule 12b-2 of the Act). Yes  ̈ No þDOCUMENTS
      INCORPORATED BY
REFERENCE:  None








ATLAS
AMERICA PUBLIC #14-2004 L.P.


(A
DELAWARE LIMITED PARTNERSHIP)


INDEX
TO ANNUAL REPORT


ON
FORM 10-K








PART
      I
              
              
              PAGEItem
      1:
              
              Description
      of Business
              3-5Item
      2:
              
              Description
      of Properties
              5-9Item
      3:
              
              Legal
      Proceedings
              9Item
      4:
              
              Submission
      of Matters to a Vote of Security Holders
              9PART
      IIItem
      5:
              
              Market
      for Registrant’s Common Equity and Related Security Holder
      Matters
              9-10Item
      7:
              
              Management’s
      Discussion and Analysis of Financial Condition or Plan of
      Operations
              10-17Item
      8:
              
              Financial
      Statements
              18-36Item
      9:
              
              Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
              37Item
      9A:
              
              Controls
      and Procedures
              37Item
      9B:
              
              Other
      Information
              38PART
      IIIItem
      10:
              
              Directors,
      Executive Officers and Corporate Governance
              38-40Item
      11:
              
              Executive
      Compensation
              40Item
      12:
              
              Security
      Ownership of Certain Beneficial Owners and Management
              40-41Item
      13:
              
              Certain
      Relationships and Related Transactions, and Director
      Independence
              41Item
      14:
              
              Principal
      Accountant Fees and Services
              41-42PART
      IVItem
      15:
              
              Exhibits
              42SIGNATURES
              43





2





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.  DESCRIPTION OF BUSINESS





General. We were formed as a
Delaware limited partnership on May 3, 2004, with Atlas Resources, Inc. as our
Managing General Partner, or MGP, to drill natural gas development wells. We
currently operate wells located in western Pennsylvania and Tennessee. We have
no employees and rely on our MGP for management, which, in turn, relies on its
parent company, Atlas Energy Resources, LLC (NYSE:ATN), or Atlas Energy, for
administrative services. See Item 10 “Directors, Executive Officers and
Corporate Governance.”





We
received total cash subscriptions from investors of $52,506,600, which were paid
to our MGP as operator and general drilling contractor under our drilling and
operating agreements. Our MGP contributed leases and paid all syndication and
offering costs and 71.70% of the tangible (“equipment”) costs for a total
capital contribution to us of $21,778,200. We have drilled 267 developmental
wells to the Clinton/Medina, Upper Devonian Sandstones and Southern Appalachia
Shale geological formations in Pennsylvania and Tennessee.





Atlas Resources
Inc. Merged into Atlas Resources, LLC.In March 2006,Atlas
Resources, Inc., our MGP was merged into a newly-formed limited liability
company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas
Energy, a newly-formed subsidiary of Atlas America, Inc., or Atlas America.
Atlas Resources, LLC serves as our MGP.





Public Offering
of Atlas Energy.  In December 2006,
Atlas America contributed substantially all of its natural gas and oil assets
and its investment partnership management business to Atlas Energy. Concurrent
with this transaction, Atlas Energy issued 7,273,750 common units, representing
a 19.4% ownership interest at that moment, in an initial public offering at a
price of $21.00 per unit. The net proceeds of approximately $139.9 million,
after underwriting discounts and commissions, were distributed to Atlas
America.





Atlas
Energy is a limited liability company focused on the development and production
of natural gas and, to a lesser extent, oil in northern Michigan's Antrim Shale
and the Appalachian Basin region of the United States of America. Atlas Energy
is also a leading sponsor of and manages tax-advantaged direct investment
partnerships, in which it coinvests to finance the exploitation and development
of its acreage. Atlas Energy is managed by Atlas Energy Management, Inc.,
through which Atlas America provides Atlas Energy with the personnel necessary
to manage its assets and raise capital.





Business
Strategy.  Our wells are currently producing natural gas and,
to a far lesser extent, oil which are our only products.  Most of our
gas is gathered and delivered to market through Atlas Pipeline Partners L.P.'s
gas gathering system, which is managed by an affiliate of our MGP.  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 “Description of Properties” for
information concerning our wells.


3





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 $318 per well, as outlined in
our drilling and operating agreement. This well supervision fee covers all
normal and regularly recurring operating expenses for the production, delivery
and sale of natural gas and to a lesser extent oil, such as:





·
            well
      tending, routine maintenance and
adjustment;


·
            reading
      meters, recording production, pumping, maintaining appropriate books and
      records; and


·
            preparing
      reports to us and to 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 will pay at cost 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. At
December 31, 2008, our MGP had not withheld any funds for this
purpose.





Markets and
Competition.  The availability of a ready market for natural
gas and oil produced by us, and the price obtained, depends on numerous factors
beyond our control, including the extent of domestic production, imports of
foreign natural gas and oil, political instability or terrorist acts in 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.  Our MGP is
responsible for selling our natural gas production. Our natural gas is sold as
discussed in Item 2 “Description of Properties.” During 2008 and 2007, we
experienced no problems in selling our natural gas and oil. Product availability
and price are the principal means of competition in selling natural gas and oil
production.





While it
is impossible to accurately determine our comparative position in the industry,
we do not consider our operations to be a significant factor in the
industry.  See Item 2 “Description of Properties” regarding the
marketing of our natural gas and oil.





Governmental
Regulation.  The energy industry in general is heavily
regulated by federal and state authorities, including regulation of production,
environmental quality and pollution control. The intent of federal and state
regulations generally is to prevent waste, protect rights to produce natural gas
and oil between owners in a common reservoir and control contamination of the
environment. Failure to comply with regulatory requirements can result in
substantial fines and other penalties.  The following discussion of
the regulation of the United States of America energy industry is not intended
to constitute a complete discussion of the various statutes, rules, regulations
and environmental orders to which our operations may be subject.





Regulation of oil
and gas producing activities.  State regulatory agencies where
a producing natural gas well is located provide a comprehensive statutory and
regulatory scheme for oil and gas operations such as ours including supervising
the production activities and the transportation of natural gas sold in
intrastate markets. Our oil and gas operations in Pennsylvania are regulated by
the Department of Environmental Resources, Division of Oil and Gas and our oil
and gas operations in Tennessee are regulated by the Tennessee Department of
Environment and Conservation and the Division of Geology.


4





Among
other things, the regulations involve:





·
            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.Under the
Comprehensive Environmental Response, Compensation and Liability Act, the Toxic
Substances Control Act, the Resource Conservation and Recovery Act, the Oil
Pollution Act of 1990, the Clean Air Act, and other federal and state laws
relating to the environment, owners and operators of wells producing natural gas
or oil can be liable for fines, penalties and clean-up costs for pollution
caused by the wells. Moreover, the owners or operators' liability can extend to
pollution costs from situations that occurred prior to their acquisition of the
assets.  State public utility regulators have either adopted federal
standards or promulgated their own safety requirements consistent with the
federal regulations.





We
believe we have complied in all material respects with applicable federal and
state regulations and do not expect that these regulations will have a material
adverse impact on our operations. Our producing activities also must comply with
various federal, state and local laws not mentioned, including those covering
the discharge of materials into the environment, or otherwise relating to the
protection of the environment.





Where can you
find more information.  We will file Form 10-K Annual Report
and Form 10-Q Quarterly Reports as well as other non-recurring special purpose
reports with the Securities and Exchange Commission. A complete list of our
filings is available on the Securities and Exchange Commission's website at
www.sec.gov. Any of our filings are also available at the SEC's Public Reference
Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room
may be contacted at 1-800- SEC-0330 for further information.





Additionally,
our MGP will provide copies of any of these reports to you without charge. Such
requests should be made to:





Atlas
America Public #14-2004 L.P.


Westpointe
Corporate Center One


1550
Coraopolis Heights Road, 2nd Floor


Moon
Township, PA  15108





ITEM
2.  DESCRIPTION OF PROPERTIES





Drilling
Activity.  For the years
ended December 31, 2008 and 2007, we did not drill any wells nor do we expect to
do so in future years.





Summary of
Producing Wells.  The table below
shows the number of our producing gross and net wells at December 31, 2008, in
which we have a working interest, all wells are located in the Appalachian
Basin.





Number
      of Producing WellsGross
                
                
                NetGas
                
                
                245
                
                
                
                220.875Oil
                
                
                11
                
                
                
                11.000Total
                
                
                256
                
                
                
                231.875





5





Production.  The
following table shows the quantities of natural gas and oil we produced (net to
our interest), our average sales price, and our average production (lifting)
cost per equivalent unit of production for the years indicated.





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)2008
                
                
                5,200
                
                
                
                739,000
                
                
                $
                97.20
                
                
                $
                8.70
                
                
                $
                2.712007
                
                
                7,900
                
                
                
                989,000
                
                
                $
                63.28
                
                
                $
                7.51
                
                
                $
                2.24


_____________





(1)
            “Mcf”
      means one thousand cubic feet of natural gas. “Mcfe” means 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.





Natural Gas and
Oil Reserve Information.The following table
summarizes information regarding our estimated proved natural gas and oil
reserves as of the date indicated. All of our reserves are located in the United
States of America. Our estimates relating to our proved natural gas and oil
reserves and our future net revenues from natural gas and oil reserves are based
on internally prepared reports, which are reviewed by our independent
third-party consultant as discussed below. In accordance with SEC guidelines, we
provide the PV-10 estimate of future net cash flows from proved reserves
discounted using an annual discount rate of 10%. The estimated future net cash
flows from proved reserves are calculated using natural gas and oil sales prices
in effect as of the dates of the estimates, which are held constant throughout
the life of the properties. We based our estimates of proved reserves on the
following year-end weighted average prices:





December
      31,2008
                
                
                2007Natural
      gas (per
      mcf)
                
                $
                6.43
                
                
                $
                7.56Oil
      (per
      bbl)
                
                
                37.64
                
                
                
                89.89





Reserve
estimates are imprecise and may change as additional information becomes
available. Furthermore, estimates of natural gas and oil reserves are
projections based on engineering data. There are uncertainties inherent in the
interpretation of this data as well as the projection of future rates of
production. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact way, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports of Wright &
Company, our independent consultants. The results of drilling, testing and
production of a well subsequent to the date of the reserve estimate for the well
may justify revising the estimate of the well’s reserves in the future. Also,
future prices we receive from the sale of natural gas and oil may be different
from those estimated by Wright & Company in preparing the reserve reports.
The amounts and timing of future operating costs also may differ from those we
estimated. In addition, you should not construe the estimated PV-10 values as
representative of the fair market value of our proved natural gas and oil
properties. PV-10 values are based on projected cash inflows, which do not
provide for changes in natural gas and oil prices or for escalation of expenses.
The meaningfulness of these estimates depends on the accuracy of the assumptions
on which they were based. The downward revision of oil and gas reserves
reflected production results that occurred during 2008 and used historical field
level and historical decline curves for the year ended December 31, 2008. This
decline reflects a decrease in the average price of natural gas of 15% and the
average price of oil of 58% for year ended December 31, 2008.


6





We
evaluate natural gas reserves at constant temperature and pressure. A change in
either of these factors can affect the measurement of natural gas reserves. We
deducted when applicable, operating costs, development costs and
production-related and ad valorem taxes in arriving at the estimated future cash
flows. We made no provision for income taxes and based the estimates on
operating methods and conditions prevailing as of the dates indicated. We cannot
assure you that these estimates are accurate predictions of future net cash
flows from our natural gas and oil reserves or their present value. For
additional information concerning our natural gas and oil reserves and estimates
of future net revenues, see Note 9 of the “Notes to Financial Statements” in
Item 8 “Financial Statements.”





At
      December 31,2008
                            
                            
                            2007Natural
      gas reserves – Proved Reserves (Mcf) (1)(4):Proved
      developed reserves
      (2)
                            
                            
                            5,936,900
                            
                            
                            
                            6,339,500Total
      proved reserves of natural gas
                            
                            
                            5,936,900
                            
                            
                            
                            6,339,500Oil
      reserves – Proved Reserves (Bbl) (1)(4):Proved
      developed reserves
      (2)
                            
                            
                            19,300
                            
                            
                            
                            21,900Total
      proved reserves of
      oil
                            
                            
                            19,300
                            
                            
                            
                            21,900Total
      proved reserves
      (Mcfe)
                            
                            
                            6,052,700
                            
                            
                            
                            6,470,900PV-10
      estimate of cash flows of proved reserves (3)(4):Proved
      developed
      reserves
                            
                            $
                            11,658,700
                            
                            
                            $
                            16,320,300Total
      PV-10
      estimate
                            
                            $
                            11,658,700
                            
                            
                            $
                            16,320,300PV-10
      estimate per limited partner unit (5)
                            
                            $
                            1,442
                            
                            
                            $
                            2,018Undiscounted
      estimate per limited partner unit (5)
                            
                            $
                            2,485
                            
                            
                            $
                            3,437





(1)
            “Proved
      reserves” generally means 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 means 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.





We have
not filed any estimates of our oil and gas reserves with, nor were such
estimates included in any reports to, any Federal or foreign governmental agency
other than the SEC within the 12 months before the date of this
filing.


7





Title to
Properties.  We believe that we hold good and indefeasible
title to our 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, our MGP conducts only a perfunctory title examination at the time it
acquires a property. Before our MGP commences drilling operations, it conducts
an extensive title examination and performs curative work on defects that it
deems significant. Our MGP has obtained title examinations for substantially all
of our 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 natural gas 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.





Acreage.  The
table below shows, by state, the estimated acres of developed oil and gas
acreage in which we had an interest at December 31, 2008. There was no
undeveloped acreage at December 31, 2008.





Developed
      AcreageLocation
                
                Gross
      (1)
                
                
                Net
      (2)Pennsylvania
                
                
                4,763.07
                
                
                
                4,393.39Tennessee
                
                
                760.00
                
                
                
                669.00Total
                
                
                5,523.07
                
                
                
                5,062.39


____________





(1)
            A
      “gross” acre is an acre in which we own a working
  interest.


(2)
            A
      “net” acre equals 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 0.5 net acre.





Delivery
Commitments. Atlas Energy markets our natural gas  which is
principally located in the Fayette County, PA area, primarily to UGI Energy
Services, Inc., Conoco Phillips company, Colonial Energy, Inc. Equitable Gas and
to third-party natural gas purchasers or marketers.





The
pricing arrangements with UGI Energy Services, Inc., Conoco Phillips Company,
and other third-party gas purchasers or marketers are tied to the New York
Mercantile Exchange Commissions or NYMEX monthly futures contract price. The
total price received for our gas is a combination of the monthly NYMEX futures
price plus a basis adjustment. For example, the NYMEX futures price is the base
price and there is an additional premium paid, because of the location of the
gas (the Appalachian Basin) in relation to the gas market, which is referred to
as the “basis.”





Pricing
for natural gas and oil has been volatile and uncertain for many years. The
agreements with UGI Energy Services, Inc., Conoco Phillips Company, and the
other third-party gas purchasers or marketers also permit Atlas Energy and its
affiliates to implement gas forward sales transactions through those companies.
UGI Energy Services, Inc., Conoco Phillips Company, and the other third-party
purchasers or marketers also use NYMEX based financial instruments to hedge
their pricing exposure and make price-hedging opportunities available to Atlas
Energy, which then makes those arrangements available to us and its other
partnerships. The price paid by UGI Energy Services, Inc., Conoco Phillips
Company, and any other third-party purchasers for certain volumes of natural gas
sold under these hedge agreements may be significantly different from the
underlying monthly spot market price. Also, Atlas Energy's hedges may include
purchases of regulated NYMEX futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. The futures
contracts employed by Atlas Energy are commitments to purchase or sell natural
gas at future dates and generally cover one-month periods for up to six years in
the future. The overall portion of our natural gas and oil portfolio that is
hedged changes from time to time.


8





To assure
that all financial instruments will be used solely for hedging price risks, and
not for speculative purposes, Atlas Energy has established a committee to assure
that all financial trading is done in compliance with Atlas Energy's hedging
policies and procedures. Atlas Energy does not intend to contract for positions
that it cannot offset with actual production.





We are
not required to provide any fixed and determinable quantities of gas under any
agreement other than with UGI Energy Services, Inc., Conoco Phillips Company and
the other third-party gas purchasers or marketers.





ITEM
3.  LEGAL PROCEEDINGS





The MGP
is not aware of any legal proceedings filed against us.





Affiliates
of the MGP and their subsidiaries are party to various routine legal proceedings
arising in the ordinary course of their collective business. The MGP management
believes that none of these actions, individually or in the aggregate, will have
a material adverse effect on the MGP's financial condition or results of
operations.





ITEM
4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS





None


PART
II





ITEM
5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER
MATTERS





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 require that:





·
            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 on 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 managing general
      partner 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, 2008, we had 1,519 unit holders.





Distributions.  Our
MGP reviews our accounts quarterly 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, to our
partners.  We will not advance or borrow funds for purposes of making
distributions.





9





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, 2008 and 2007, we distributed the
following:





·
            $3,834,500
      and $5,088,800 to our limited partners;
and


·
            $2,064,800
      and $2,749,400 to our managing general partner,
    respectively.





ITEM
7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR
PLAN OF
OPERATIONS





This Item
7 “Management's Discussion and Analysis of Financial Condition or Plan of
Operations” should be read in conjunction with Item 8 “Financial Statements” and
the “Notes to Financial Statements”.





General.  We
were formed as a Delaware limited partnership on May 3, 2004, with Atlas
Resources, Inc. as our Managing General Partner, or MGP, to drill natural gas
developmental wells. 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.





Atlas Resources
Inc. Merged into Atlas Resources, LLC.In March 2006,Atlas
Resources, Inc., our MGP was merged into a newly-formed limited liability
company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas
Energy a newly-formed subsidiary of Atlas America, Inc., or Atlas America. Atlas
Resources, LLC serves as our MGP.





Public Offering
of Atlas Energy.  In December 2006,
Atlas America contributed substantially all of its natural gas and oil assets
and its investment partnership management business to Atlas Energy. Concurrent
with this transaction, Atlas Energy issued 7,273,750 common units, representing
a 19.4% ownership interest at that moment, in an initial public offering at a
price of $21.00 per unit. The net proceeds of approximately $139.9 million,
after underwriting discounts and commissions, were distributed to Atlas
America.





Atlas
Energy is a limited liability company focused on the development and production
of natural gas and, to a lesser extent, oil in northern Michigan's Antrim Shale
and the Appalachian Basin region of the United States of America. Atlas Energy
is also a leading sponsor of and manages tax-advantaged direct investment
partnerships, in which it coinvests to finance the exploitation and development
of its acreage. Atlas Energy is managed by Atlas Energy Management, Inc.,
through which Atlas America provides Atlas Energy with personnel necessary to
manage its assets and raise capital.





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


10





Years
      Ended December 31,2008
                
                
                2007Production
      revenues (in thousands):Gas
                
                $
                6,430
                
                
                $
                7,426Oil
                
                $
                502
                
                
                $
                501Total
                
                $
                6,932
                
                
                $
                7,927Production
      volumes:Gas
      (mcf/day) (1)
                
                
                2,019
                
                
                
                2,710Oil
      (bbls/day) (1)
                
                
                14
                
                
                
                22Total
      (mcfe/day) (1)
                
                
                2,103
                
                
                
                2,842Average
      sales price:Gas
      (per mcf) (1) (2)
                
                $
                8.70
                
                
                $
                7.51Oil
      (per bbl) (1)
      (3)
                
                $
                97.20
                
                
                $
                63.28Average
      production costs:As
      a percent of
      revenues
                
                
                30
                %
                
                
                29
                %Per
      mcfe (1)
                
                $
                2.71
                
                
                $
                2.24Depletion
      per
      mcfe
                
                $
                3.00
                
                
                $
                3.31


_____________





(1)
            “Mcf”
      means thousand cubic feet, “mcfe” means thousand cubic feet equivalent and
      “bbls” means barrels. Bbls are converted to mcfe using the ratio of six
      mcfs to one bbl.


(2)
            The
      average sales price per mcf before the effects of hedging was $9.82 and
      $7.64 for the years ended December 31, 2008 and 2007,
      respectively.


(3)
            The
      average sales price per bbl before the effects of hedging was $100.34 for
      the year ended December 31, 2008. There was no hedging for oil in
      2007.





Natural Gas
Revenues. Our natural gas revenues were $6,429,800 and $7,426,200 for the
years ended December 31, 2008 and 2007, respectively, a decrease of $996,400
(13%). This decrease was due to a decrease in production volumes to 2,019 mcf
per day for the year ended December 31, 2008 from 2,710 mcf per day for the year
ended December 31, 2007, a decrease of 691 mcf per day (25%), partially offset
by an increase in the average sales price we received for our natural gas to
$8.70 per mcf for the year ended December 31, 2008 from $7.51 per mcf for the
year ended December 31, 2007, an increase of $1.19 per mcf (16%). The $996,400
decrease in our natural gas revenues for the year ended December 31, 2008, as
compared to the prior year similar period, was attributable to a $1,877,500
decrease due to lower production volumes, partially offset by an $881,100
increase due to higher natural gas prices, which are driven by market
conditions. The overall decrease in gas production volumes resulted primarily
from the normal production decline inherent in the life of a well.





The price
we receive for our natural gas is primarily a result of the index-driven
agreements with Hess Corporation, UGI Energy Services, Inc. and our other
natural gas purchasers. See Item 2 “Description of Properties.” 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 oil production. Our oil revenues were $502,200 and $500,800 for
the years ended December 31, 2008 and 2007, respectively, an increase of $1,400
(0.3%). This increase was due to an increase in the average sales price we
received for our oil to $97.20 for the year ended December 31, 2008 as compared
to $63.28 for the year ended December 31, 2007, an increase of $33.92 per bbls
(54%), partially offset by a decrease in the production volumes to 14 bbls per
day for the year ended December 31, 2008 from 22 bbls per day for the year ended
December 31, 2007, a decrease of 8 bbls per day (36%).The $1,400 increase in oil
revenue for the year ended December 31, 2008 as compared to the prior year
similar period was attributable to a $175,300 increase due to higher oil prices,
partially offset by a $173,900 decrease due to lower production
volumes.


11





Expenses.  Production
expenses were $2,089,900 and $2,323,100 for the years ended December 31, 2008
and 2007, respectively, a decrease of $233,200 (10%). This decrease was
primarily due to lower transportation fees and other variable expenses for the
years ended December 31, 2008 as compared to the prior year similar
period.





Depletion
of oil and gas properties as a percentage of oil and gas revenues was 33% for
the year ended December 31, 2008 as compared to 43% for the year ended December
31, 2007. This percentage change is directly attributable to revenues, oil and
gas reserve quantities, product prices, production volumes and changes in the
depletable cost basis of our oil and gas properties.





There was
no impairment of oil and gas properties for the years ended December 31, 2008
and 2007. 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 year ended December 31, 2006. This impairment charge is based
on reserve quantities, future market values and our carrying value. We can not
provide any assurance that impairment charges may or may not be taken in future
periods.





General
and Administrative expenses were $273,900 and $308,400 for the years ended
December 31, 2008 and 2007, respectively, a decrease of $34,500 (11%). These
expenses include outside costs for services, as well as the monthly
administrative fee charged by our MGP. This decrease was primarily due to lower
third-party costs as compared to prior year similar period.





Liquidity and
Capital Resources.  Cash provided by operating activities
decreased $1,581,300 to $5,551,200 for the year ended December 31, 2008, from
$7,132,500 for the year ended December 31, 2007. This decrease was primarily due
to a decrease in net earnings before depletion and accretion of $759,200. The
decrease in net earnings was partially offset by a decrease in accounts
receivable-affiliate of $60,300. In addition, the change in non-cash derivative
value decreased operating cash flow by $762,800.





Cash
provided by investing activities was zero and $13,200 for the years ended
December 31, 2008 and 2007, respectively. In 2007 the proceeds were from the
sale of tangible assets.





Cash used
in financing activities decreased $1,938,900 to $5,899,300 for the year ended
December 31, 2008 from $7,838,200 for the year ended December 31, 2007. This
decrease was due to lower distributions to partners as a result of a decrease in
net cash flow.





The MGP
may withhold funds for future plugging and abandonment costs.  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
believe that our future cash flows from operations and amounts available from
borrowing from our MGP or affiliates, if any, will be adequate to fund our
operations.





Critical
Accounting Policies.The discussion and analysis of our
financial condition and results of operations are based on our financial
statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. On an on-going basis, we
evaluate our estimates, including those related to our asset retirement
obligations, depletion, impairment of long-lived assets, and certain accrued
receivables and liabilities. We base our estimates on historical experience and
on various other assumptions that we believe are reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates under different
assumptions or conditions.


12





For a
detailed discussion on the application of policies critical to our business
operations and other accounting policies, see Note 2 of the “Notes to Financial
Statements” in Item 8 “Financial Statements.”





Use of
Estimates. Preparation of our financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the financial statements and the reported amounts
of revenues, costs and expenses during the reporting period.  Actual
results could differ from these estimates.





Reserve
Estimates.Our estimates of our
proved natural gas and oil reserves and the future net revenues we may receive
from them, are based on reserve analyses that rely on various assumptions,
including those required by the SEC, as to natural gas and oil prices, drilling
and operating expenses, capital expenditures, abandonment costs, taxes and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of our reserves. As a result, our
estimates of our proved natural gas and oil reserves will be inherently
imprecise. Actual future production, natural gas and oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and oil reserves may vary substantially from our
estimates, including the estimates contained in our reserve reports. In
addition, our proved reserves may be subject to downward or upward revision
based on production history, results of future exploration and development,
prevailing natural gas and oil prices, mechanical difficulties, governmental
regulations and other factors, many of which are beyond our
control.





Accounts
Receivable and Allowance for Possible Losses. The MGP engages in credit
extension, monitoring, and collection. In evaluating our allowance for possible
losses, the MGP performs ongoing credit evaluations of our customers and adjusts
credit limits based upon payment history and the customer’s current
creditworthiness, as determined by our review of our customer’s credit
information. The MGP extends credit on an unsecured basis to many of our energy
customers. At December 31, 2008 and 2007 our credit evaluation indicated that
the MGP has no need for an allowance for possible losses for our oil and gas
receivables.





Impairment of Oil
and Gas Properties.  We review our producing oil and gas
properties for impairment on an annual basis and whenever events and
circumstances indicate a decline in the recoverability of their carrying
values.  We estimate the expected future cash flows from our oil and
gas properties and compare such future cash flows to the carrying amount of the
oil and gas properties to determine if the carrying amount is
recoverable.  If the carrying amount exceeds the estimated
undiscounted future cash flows, we will adjust the carrying amount of the oil
and gas properties to their fair value in the current period.  The
factors used to determine fair value include, but are not limited to, estimates
of reserves, future production estimates, anticipated capital expenditures, and
a discount rate commensurate with the risk associated with realizing the
expected cash flows projected. Because of the complexities associated with oil
and gas reserve estimates and the history of price volatility in the oil and gas
markets, events may arise that will require us to record an impairment of our
oil and gas properties. There was no impairment charge for the years ended
December 31, 2008 and 2007.





Derivative
Instruments.  Atlas Energy, on our behalf from time to time
enters into natural gas future option and collar contracts to hedge exposure to
changes in natural gas prices. At any point in time, such contracts may include
regulated NYMEX futures, and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. NYMEX
contracts are generally settled with offsetting positions, but may be settled by
the delivery of natural gas. Oil contracts are based on a West Texas
Intermediate or WTI index. These contracts have qualified and been designated as
cash flow hedges and recorded at their fair values.





We apply
the provisions of SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, or SFAS 133. SFAS 133 requires each
derivative instrument to be recorded in the balance sheet as either an asset or
liability measured at fair value. Changes in a derivative instrument’s fair
value are recognized currently in earnings unless specific hedge accounting
criteria are met. See Note 7 on our financial statements.


13





At
December 31, 2008, Atlas Energy had allocated open natural gas futures contracts
to us related to natural gas sales covering 1,310,300 dekatherms (“Dth”) of gas,
maturing through December 31, 2013 at an average settlement price of $8.22 per
Dth. In addition, Atlas Energy had allocated oil futures contracts to us related
to oil sales covering 5,000 barrels (“Bbls”) of oil, maturing through April 30,
2013 at an average settlement price of $98.31 per Bbl. At December 31, 2008, we
reflected a net hedge asset on our Balance Sheets of $1,921,000. Due to the
impairment of our oil and gas properties at December 31, 2006, a net offsetting
unrealized gain of $2,303,600 was reclassified into earnings from accumulated
other comprehensive income. At December 31, 2008, $401,800 of the 2006
reclassification remains in accumulated other comprehensive income. Of the
$1,519,200 net gain in accumulated other comprehensive income at December 31,
2008, if the fair values of the instruments remain at current market values, we
will reclassify $805,100 of net gain to our Statements of Net Earnings over the
next twelve month period as these contracts expire, and $714,100 of net gain in
later periods. Actual amounts that will be reclassified will vary as a result of
future price changes. We realized losses of $842,900 and $127,100 for the years
ended December 31, 2008 and 2007, respectively; in our oil and gas revenues
within our Statements of Net Earnings related to the settlement of qualifying
hedge instruments. Ineffective hedge gains or losses are recorded within the
Statements of Net Earnings while the hedge contract is open and may increase or
decrease until settlement of the contract. We recognized no gains or losses
during the years ended December 31, 2008 and 2007 for hedge ineffectiveness or
as a result of the discontinuance of cash flow hedges.





As of
December 31, 2008, Atlas Energy had allocated to us the following natural gas
and oil volumes hedged:





Natural
Gas Fixed Price Swaps


Production
                  
                  
                  
                  
                  
                  AveragePeriod
      Ending
                  
                  
                  Volumes
                  
                  
                  Fixed
      Price
                  
                  
                  Fair
      ValueDecember
      31,
                  
                  
                  (MMbtu)
      (1)
                  
                  
                  (per
      MMbtu)
                  
                  
                  Asset
      (2)2009
                  
                  
                  
                  450,500
                  
                  
                  $
                  8.55
                  
                  
                  $
                  1,101,9002010
                  
                  
                  
                  311,500
                  
                  
                  
                  8.11
                  
                  
                  
                  301,8002011
                  
                  
                  
                  220,700
                  
                  
                  
                  7.84
                  
                  
                  
                  114,3002012
                  
                  
                  
                  163,100
                  
                  
                  
                  8.05
                  
                  
                  
                  128,2002013
                  
                  
                  
                  17,700
                  
                  
                  
                  8.73
                  
                  
                  
                  24,800$
                  1,671,000





Natural
Gas Costless Collars


Production
                    
                    
                    
                    
                    
                    
                    AveragePeriod
      Ending
                    
                    Option
                    
                    Volumes
                    
                    
                    Floor
      & Cap
                    
                    
                    Fair
      ValueDecember
      31,
                    
                    Type
                    
                    (MMbtu)
      (1)
                    
                    
                    (per
      MMbtu)
                    
                    
                    Asset
      (2)2009
                    
                    Puts
      purchased
                    
                    
                    2,800
                    
                    
                    $
                    11.00
                    
                    
                    $
                    14,0002009
                    
                    Calls
      sold
                    
                    
                    2,800
                    
                    
                    
                    15.35
                    
                    
                    
                    —2010
                    
                    Puts
      purchased
                    
                    
                    39,700
                    
                    
                    
                    7.84
                    
                    
                    
                    39,5002010
                    
                    Calls
      sold
                    
                    
                    39,700
                    
                    
                    
                    9.01
                    
                    
                    
                    —2011
                    
                    Puts
      purchased
                    
                    
                    88,600
                    
                    
                    
                    7.48
                    
                    
                    
                    43,8002011
                    
                    Calls
      sold
                    
                    
                    88,600
                    
                    
                    
                    8.44
                    
                    
                    
                    —2012
                    
                    Puts
      purchased
                    
                    
                    12,100
                    
                    
                    
                    7.00
                    
                    
                    
                    2,6002012
                    
                    Calls
      sold
                    
                    
                    12,100
                    
                    
                    
                    8.32
                    
                    
                    
                    —2013
                    
                    Puts
      purchased
                    
                    
                    3,600
                    
                    
                    
                    7.00
                    
                    
                    
                    8002013
                    
                    Calls
      sold
                    
                    
                    3,600
                    
                    
                    
                    8.25
                    
                    
                    
                    —$
                    100,700





14





Crude
Oil Fixed Price Swaps


Production
                  
                  
                  
                  
                  
                  AveragePeriod
      Ending
                  
                  
                  Volumes
                  
                  
                  Fixed
      Price
                  
                  
                  Fair
      ValueDecember
      31,
                  
                  
                  (Bbl)
                  
                  
                  (per
      Bbl)
                  
                  
                  Asset
      (3)2009
                  
                  
                  
                  900
                  
                  
                  $
                  100.14
                  
                  
                  $
                  43,7002010
                  
                  
                  
                  800
                  
                  
                  
                  97.40
                  
                  
                  
                  25,4002011
                  
                  
                  
                  700
                  
                  
                  
                  96.44
                  
                  
                  
                  17,9002012
                  
                  
                  
                  500
                  
                  
                  
                  96.00
                  
                  
                  
                  12,3002013
                  
                  
                  
                  200
                  
                  
                  
                  96.06
                  
                  
                  
                  3,500$
                  102,800





Crude
Oil Costless Collars


Production
                    
                    
                    
                    
                    
                    
                    AveragePeriod
      Ending
                    
                    Option
                    
                    Volumes
                    
                    
                    Floor
      & Cap
                    
                    
                    Fair
      ValueDecember
      31,
                    
                    Type
                    
                    (Bbl)
                    
                    
                    (per
      Bbl)
                    
                    
                    Asset
      (3)2009
                    
                    Puts
      purchased
                    
                    
                    600
                    
                    
                    $
                    85.00
                    
                    
                    $
                    18,8002009
                    
                    Calls
      sold
                    
                    
                    600
                    
                    
                    
                    118.63
                    
                    
                    
                    —2010
                    
                    Puts
      purchased
                    
                    
                    500
                    
                    
                    
                    85.00
                    
                    
                    
                    11,8002010
                    
                    Calls
      sold
                    
                    
                    500
                    
                    
                    
                    112.92
                    
                    
                    
                    —2011
                    
                    Puts
      purchased
                    
                    
                    400
                    
                    
                    
                    85.00
                    
                    
                    
                    8,4002011
                    
                    Calls
      sold
                    
                    
                    400
                    
                    
                    
                    110.81
                    
                    
                    
                    —2012
                    
                    Puts
      purchased
                    
                    
                    300
                    
                    
                    
                    85.00
                    
                    
                    
                    5,9002012
                    
                    Calls
      sold
                    
                    
                    300
                    
                    
                    
                    110.06
                    
                    
                    
                    —2013
                    
                    Puts
      purchased
                    
                    
                    100
                    
                    
                    
                    85.00
                    
                    
                    
                    1,6002013
                    
                    Calls
      sold
                    
                    
                    100
                    
                    
                    
                    110.09
                    
                    
                    
                    —$
                    46,500Total
      Net Asset
                    
                    
                    $
                    1,921,000


____________





(1)
            MMBTU
      represents million British Thermal
Units.


(2)
            Fair
      value based on forward NYMEX natural gas
prices.


(3)
            Fair
      value based on forward WTI crude oil
prices.





The fair
value of the derivatives is included on our Balance Sheets as
follows:





December
      31,2008
                
                
                2007Short-term
      hedge receivable due from affiliate
                
                $
                1,288,800
                
                
                $
                549,500Long-term
      hedge receivable due from affiliate
                
                
                842,000
                
                
                
                82,200Short-term
      hedge liability due to affiliate
                
                
                (110,400
                )
                
                
                (13,000
                )Long-term
      hedge liability due to affiliate
                
                
                (99,400
                )
                
                
                (825,600
                )$
                1,921,000
                
                
                $
                (206,900
                )





15





Fair
Value of Financial Instruments





We have
adopted the provisions of SFAS 157 at January 1, 2008. SFAS 157 establishes a
fair value hierarchy which requires an entity to maximize the use of observable
inputs and minimize the use of unobservable inputs when measuring fair value.
SFAS 157’s hierarchy defines three levels of inputs that may be used to measure
fair value:





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





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





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





We use
the fair value methodology outlined in SFAS 157 to value the assets and
liabilities for our outstanding derivative contracts. All of our derivatives
contracts are defined as Level 2. Our natural gas and crude oil derivative
contracts are valued based on prices quoted on the NYMEX or WTI and adjusted by
the respective counterparty using various assumptions including quoted forward
prices, time value, volatility factors, and contractual prices for the
underlying instruments. In accordance with SFAS 157, the following table
represents our fair value hierarchy for our financial instruments at December
31, 2008.





Fair
      Value Measurements at December 31, 2008 UsingQuoted
      prices
                  
                  
                  Significant
      other
                  
                  
                  Significantin
      active
                  
                  
                  observable
                  
                  
                  unobservablemarkets
                  
                  
                  inputs
                  
                  
                  inputs(Level
      1)
                  
                  
                  (Level
      2)
                  
                  
                  (Level
      3)Commodity-based
      derivatives
                  
                  $
                  —
                  
                  
                  $
                  1,921,000
                  
                  
                  $
                  —Total
                  
                  $
                  —
                  
                  
                  $
                  1,921,000
                  
                  
                  $
                  —





Revenue
Recognition.Revenues from sales of natural gas and oil are
recognized by us when the gas and oil have been delivered to the purchaser. Our
natural gas and oil is sold under various contracts entered into by our MGP.
Virtually all of our MGP's contract pricing provisions are tied to a market
index, with certain adjustments based on, among other factors, whether a well
delivers to a gathering or transmission line, quality of natural gas and
prevailing supply and demand conditions, so that the price we receive from the
sale of our natural gas fluctuates to remain competitive with generally
available natural gas supplies in the market.





Asset Retirement
Obligations.On an annual basis, we estimate the costs of
future dismantlement, restoration, reclamation and abandonment of our natural
gas and oil-producing properties. We also estimate the salvage value of our
equipment that we can recover upon abandonment. We comply with SFAS 143, Accounting for Asset Retirement
Obligationsas discussed in Note 8 of our Financial Statements. As of
December 31, 2008 and 2007, our estimate of salvage values was greater than, or
equal to, our estimate of the costs of future dismantlement, restoration,
reclamation, and abandonment. A decrease in salvage values or an increase in
dismantlement, restoration, reclamation and abandonment costs from those we have
estimated, or changes in our estimates or cost, would reduce our net
earnings.





Off-Balance Sheet
Arrangements.  We have no financial statement risk, or any
Off-Balance Sheet Arrangements or contractual obligations.


16





Recently
Issued Financial Accounting Standards.





In May
2008, the Financial Accounting Standards Board, or FASB, issued Statement of
Financial Accounting Standards, No. 162, The Hierarchy of Generally Accepted
Accounting Policies, or SFAS 162, which reorganizes the GAAP hierarchy.
The purpose of the new standard is to improve financial reporting by providing a
consistent framework for determining what accounting principles should be used
when preparing U.S. GAAP financial statements. The standard is effective 60 days
after the SEC's approval of the PCAOB's amendments to AU Section 411. The
adoption of SFAS 162 will not have an impact on our financial position or
results of operations.





In March
2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities, or SFAS 161, an amendment of FASB
Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, or SFAS 133. SFAS 161
requires entities to provide qualitative disclosures about the objectives and
strategies for using derivatives, quantitative data about the fair value of and
gains and losses on derivative contracts, and details of credit-risk-related
contingent features in their hedged positions. The standard is effective for
financial statements issued for fiscal years and interim periods beginning after
November 15, 2008, with early application encouraged, but not required. SFAS 161
also requires entities to disclose more information about the location and
amounts of derivative instruments in financial statements; how derivatives and
related hedges are accounted for under SFAS 133 and how the hedges affect the
entity’s financial position, financial performance, and cash flows. We will
apply the requirements of SFAS No. 161 on its adoption on January 1, 2009. We do
not expect it to have an impact on our financial position or results of
operations.





In
February 2007, the FASB issued Statement of Financial Accounting Standards
No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities,or SFAS No. 159.
SFAS No. 159 permits entities to choose to measure eligible financial
instruments and certain other items at fair value. The objective is to improve
financial reporting by providing entities with the opportunity to mitigate
volatility in reported earnings caused by measuring related assets and
liabilities differently without having to apply complex hedge accounting
provisions. By electing the fair value option in conjunction with a derivative,
an entity can achieve an accounting result similar to a fair value hedge without
having to comply with complex hedge accounting rules. The statement was
effective for us as of January 1, 2008. We adopted SFAS No. 159 at January 1,
2008, and have elected not to apply the fair value option to any of our
financial instruments not already carried at fair value in accordance with other
accounting standards, and therefore the adoption of SFAS No. 159 did not impact
our financial statements for the year ended December 31, 2008.





In
September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157, Fair Value
Measurement , or SFAS No. 157. SFAS No. 157 addresses the need for
increased consistency in fair value measurements, defining fair value as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the measurement date. It
also establishes a framework for measuring fair value and expands disclosure
requirements. In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No.
157, or FSP FAS 157-2. FSP FAS 157-2, which was effective upon issuance,
delays the effective date of SFAS No. 157 for nonfinancial assets and
nonfinancial liabilities, except for items that are recognized or disclosed at
fair value at least once a year, to fiscal years beginning after November 15,
2008. On January 1, 2009, we will adopt SFAS No. 157 for nonfinancial assets and
liabilities that are not measured at fair value on a recurring basis. Our
nonfinancial assets and liabilities will be limited to the initial recognition
of asset retirement obligations. FSP FAS 157-2 also covers interim periods
within the fiscal years for items within its scope. The delay is intended to
allow the FASB and its constituents the time to consider the various
implementation issues associated with SFAS No. 157. We adopted SFAS No. 157 as
of January 1, 2008 with respect to our derivative instruments which are measured
at fair value within our financial statements. See Note 7 for disclosures
pertaining to the provisions of SFAS No. 157 with regard to our fair value
measurements.





17


ITEM
8.  FINANCIAL STATEMENTS


REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
 To the
Partners of
 Atlas
America Public #14-2004 L.P.
 
 We have
audited the accompanying balance sheets of Atlas America Public #14-2004 L.P. (a
Delaware Limited Partnership) as of December 31, 2008 and 2007, and the related
statements of net earnings, comprehensive income, 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 #14-2004 L.P.
as of December 31, 2008 and 2007, 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,
2009


18





ATLAS
AMERICA PUBLIC #14-2004 L.P.


BALANCE
SHEETS


DECEMBER
31,





2008
                    
                    
                    2007ASSETSCurrent
      assets:Cash
      and cash equivalents
                    
                    $
                    1,242,100
                    
                    
                    $
                    1,590,200Accounts
      receivable-affiliate
                    
                    
                    1,228,700
                    
                    
                    
                    1,625,100Short-term
      hedge receivable due from affiliate
                    
                    
                    1,288,800
                    
                    
                    
                    549,500Total
      current assets
                    
                    
                    3,759,600
                    
                    
                    
                    3,764,800Oil
      and gas properties, net
                    
                    
                    23,553,800
                    
                    
                    
                    26,044,800Long-term
      hedge receivable due from affiliate
                    
                    
                    842,000
                    
                    
                    
                    82,200$
                    28,155,400
                    
                    
                    $
                    29,891,800LIABILITIES
      AND PARTNERS' CAPITALCurrent
      liabilities:Accrued
      liabilities
                    
                    $
                    22,200
                    
                    
                    $
                    19,600Short-term
      hedge liability due to affiliate
                    
                    
                    110,400
                    
                    
                    
                    13,000Total
      current liabilities
                    
                    
                    132,600
                    
                    
                    
                    32,600Asset
      retirement obligation
                    
                    
                    2,282,500
                    
                    
                    
                    2,321,400Long-term
      hedge liability due to affiliate
                    
                    
                    99,400
                    
                    
                    
                    825,600Partners'
      capital:Managing
      general partner
                    
                    
                    7,512,000
                    
                    
                    
                    8,468,100Limited
      partners (5,256.95 units)
                    
                    
                    16,609,700
                    
                    
                    
                    19,422,300Accumulated
      other comprehensive income (loss)
                    
                    
                    1,519,200
                    
                    
                    
                    (1,178,200
                    )Total
      partners' capital
                    
                    
                    25,640,900
                    
                    
                    
                    26,712,200$
                    28,155,400
                    
                    
                    $
                    29,891,800










The
accompanying notes are an integral part of these financial
statements


19




ATLAS
AMERICA PUBLIC #14-2004 L.P.


STATEMENTS
OF NET EARNINGS


YEARS
ENDED DECEMBER 31, 2008 AND 2007






2008
                    
                    
                    2007REVENUESNatural
      gas and oil
                    
                    $
                    6,931,900
                    
                    
                    $
                    7,927,000Interest
      income
                    
                    
                    14,600
                    
                    
                    
                    46,400Total
      revenues
                    
                    
                    6,946,500
                    
                    
                    
                    7,973,400COST
      AND EXPENSESProduction
                    
                    
                    2,089,900
                    
                    
                    
                    2,323,100Depletion
                    
                    
                    2,312,800
                    
                    
                    
                    3,431,600Accretion
      of asset retirement obligation
                    
                    
                    139,300
                    
                    
                    
                    136,600General
      and administrative
                    
                    
                    273,900
                    
                    
                    
                    308,400Total
      expenses
                    
                    
                    4,815,900
                    
                    
                    
                    6,199,700Net
      earnings
                    
                    $
                    2,130,600
                    
                    
                    $
                    1,773,700Allocation
      of net earnings:Managing
      general partner
                    
                    $
                    1,108,700
                    
                    
                    $
                    1,235,400Limited
      partners
                    
                    $
                    1,021,900
                    
                    
                    $
                    538,300Net
      earnings per limited partnership unit
                    
                    $
                    194
                    
                    
                    $
                    102










The
accompanying notes are an integral part of these financial
statements


20




ATLAS
AMERICA PUBLIC #14-2004 L.P.


STATEMENTS
OF COMPREHENSIVE INCOME


YEARS
ENDED DECEMBER 31, 2008 AND 2007





December
      31,2008
                    
                    
                    2007Net
      earnings
                    
                    $
                    2,130,600
                    
                    
                    $
                    1,773,700Other
      comprehensive income (loss):Unrealized
      holding gain (loss) on hedging contracts
                    
                    
                    1,854,500
                    
                    
                    
                    (1,636,500
                    )Less:
      reclassification adjustment for losses realized in net
      earnings
                    
                    
                    842,900
                    
                    
                    
                    127,100Total
      other comprehensive income (loss)
                    
                    
                    2,697,400
                    
                    
                    
                    (1,509,400
                    )Comprehensive
      income
                    
                    $
                    4,828,000
                    
                    
                    $
                    264,300













The
accompanying notes are an integral part of these financial
statements








21




ATLAS
AMERICA PUBLIC #14-2004 L.P.


STATEMENTS
OF CHANGES IN PARTNERS' CAPITAL


YEARS
ENDED DECEMBER 31, 2008 AND 2007





AccumulatedManaging
                                
                                
                                
                                
                                
                                OtherGeneral
                                
                                
                                Limited
                                
                                
                                ComprehensivePartner
                                
                                
                                Partners
                                
                                
                                Income
      (Loss)
                                
                                
                                TotalBalance
      at December 31, 2006
                                
                                $
                                9,931,000
                                
                                
                                $
                                23,972,800
                                
                                
                                $
                                331,200
                                
                                
                                $
                                34,235,000Participation
      in revenue and expensesNet
      production revenues
                                
                                
                                1,961,400
                                
                                
                                
                                3,642,500
                                
                                
                                
                                —
                                
                                
                                
                                5,603,900Interest
      income
                                
                                
                                16,200
                                
                                
                                
                                30,200
                                
                                
                                
                                —
                                
                                
                                
                                46,400Depletion
                                
                                
                                (586,400
                                )
                                
                                
                                (2,845,200
                                )
                                
                                
                                —
                                
                                
                                
                                (3,431,600
                                )Accretion
      of asset retirement obligation
                                
                                
                                (47,800
                                )
                                
                                
                                (88,800
                                )
                                
                                
                                —
                                
                                
                                
                                (136,600
                                )General
      and administrative
                                
                                
                                (108,000
                                )
                                
                                
                                (200,400
                                )
                                
                                
                                —
                                
                                
                                
                                (308,400
                                )Net
      earnings
                                
                                
                                1,235,400
                                
                                
                                
                                538,300
                                
                                
                                
                                —
                                
                                
                                
                                1,773,700MGP
      adjusted asset contribution
                                
                                
                                51,100
                                
                                
                                
                                —
                                
                                
                                
                                —
                                
                                
                                
                                51,100Other
      comprehensive loss
                                
                                
                                —
                                
                                
                                
                                —
                                
                                
                                
                                (1,509,400
                                )
                                
                                
                                (1,509,400
                                )Distributions
      to partners
                                
                                
                                (2,749,400
                                )
                                
                                
                                (5,088,800
                                )
                                
                                
                                —
                                
                                
                                
                                (7,838,200
                                )Balance
      at December 31, 2007
                                
                                $
                                8,468,100
                                
                                
                                $
                                19,422,300
                                
                                
                                $
                                (1,178,200
                                )
                                
                                $
                                26,712,200Participation
      in revenue and expensesNet
      production revenues
                                
                                
                                1,694,700
                                
                                
                                
                                3,147,300
                                
                                
                                
                                —
                                
                                
                                
                                4,842,000Interest
      income
                                
                                
                                5,100
                                
                                
                                
                                9,500
                                
                                
                                
                                —
                                
                                
                                
                                14,600Depletion
                                
                                
                                (446,400
                                )
                                
                                
                                (1,866,400
                                )
                                
                                
                                —
                                
                                
                                
                                (2,312,800
                                )Accretion
      of asset retirement obligation
                                
                                
                                (48,800
                                )
                                
                                
                                (90,500
                                )
                                
                                
                                —
                                
                                
                                
                                (139,300
                                )General
      and administrative
                                
                                
                                (95,900
                                )
                                
                                
                                (178,000
                                )
                                
                                
                                —
                                
                                
                                
                                (273,900
                                )Net
      earnings
                                
                                
                                1,108,700
                                
                                
                                
                                1,021,900
                                
                                
                                
                                —
                                
                                
                                
                                2,130,600Other
      comprehensive income
                                
                                
                                —
                                
                                
                                
                                —
                                
                                
                                
                                2,697,400
                                
                                
                                
                                2,697,400Distributions
      to partners
                                
                                
                                (2,064,800
                                )
                                
                                
                                (3,834,500
                                )
                                
                                
                                —
                                
                                
                                
                                (5,899,300
                                )Balance
      at December 31, 2008
                                
                                $
                                7,512,000
                                
                                
                                $
                                16,609,700
                                
                                
                                $
                                1,519,200
                                
                                
                                $
                                25,640,900











The
accompanying notes are an integral part of these financial
statements


22




ATLAS
AMERICA PUBLIC #14-2004 L.P.


STATEMENTS
OF CASH FLOWS


YEARS
ENDED DECEMBER 31, 2008 AND 2007





2008
                        
                        
                        2007Cash
      flows from operating activities:Net
      earnings
                        
                        $
                        2,130,600
                        
                        
                        $
                        1,773,700Adjustments
      to reconcile net earnings to net cash provided by operating
      activities:Depletion
                        
                        
                        2,312,800
                        
                        
                        
                        3,431,600Non-cash
      loss on derivative value
                        
                        
                        569,500
                        
                        
                        
                        1,332,300Accretion
      of asset retirement obligation
                        
                        
                        139,300
                        
                        
                        
                        136,600Decrease
      in accounts receivable-affiliate
                        
                        
                        396,400
                        
                        
                        
                        456,700Increase
      in accrued liabilities
                        
                        
                        2,600
                        
                        
                        
                        1,600Net
      cash provided by operating activities
                        
                        
                        5,551,200
                        
                        
                        
                        7,132,500Cash
      flows from investing activities:Proceeds
      from sale of tangible equipment
                        
                        
                        —
                        
                        
                        
                        13,200Net
      cash provided by investing activities
                        
                        
                        —
                        
                        
                        
                        13,200Cash
      flows from financing activities:Distributions
      to partners
                        
                        
                        (5,899,300
                        )
                        
                        
                        (7,838,200
                        )Net
      cash used in financing activities
                        
                        
                        (5,899,300
                        )
                        
                        
                        (7,838,200
                        )Net
      decrease in cash and cash equivalents
                        
                        
                        (348,100
                        )
                        
                        
                        (692,500
                        )Cash
      and cash equivalents at beginning of period
                        
                        
                        1,590,200
                        
                        
                        
                        2,282,700Cash
      and cash equivalents at end of period
                        
                        $
                        1,242,100
                        
                        
                        $
                        1,590,200Supplemental Schedule
      of non-cash investing and financing activities:Assets
      contributed by the managing general partner:Tangible
      equipment
                        
                        $
                        —
                        
                        
                        $
                        5,900Intangible
      drilling cost
                        
                        
                        —
                        
                        
                        
                        45,200$
                        —
                        
                        
                        $
                        51,100Asset
      retirement obligation revision
                        
                        $
                        (178,200
                        )
                        
                        $
                        (92,100
                        )








The
accompanying notes are an integral part of these financial
statements





23





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS


DECEMBER
31, 2008





NOTE
1 – DESCRIPTION OF BUSINESS





Atlas
America Public #14-2004 L.P. (the “Partnership”) is a Delaware Limited
Partnership, which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as
Managing General Partner (“MGP”) and Operator, and 1,518 as Limited Partners.
The Partnership was formed on May 3, 2004 to drill and operate gas wells located
primarily in western Pennsylvania and Tennessee. At December 31, 2008, the
Partnership had various working interest in 267 gross wells.





In March
2006, Atlas Resources, Inc., the Partnership's MGP was merged into a
newly-formed limited liability company, Atlas Resources, LLC, which became an
indirect subsidiary of Atlas America, Inc. Atlas Resources, LLC now serves as
the Partnership's MGP. In December 2007, Atlas America, Inc. contributed
substantially all of its natural gas and oil exploration and production assets
to Atlas Energy Resources, LLC.





NOTE
2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES





A summary
of significant accounting policies applied in the preparation of the
accompanying financial statements follows:





Basis
of Accounting





The
financial statements are prepared in accordance with accounting principles
generally accepted in the United States of America.





Use
of Estimates





Preparation
of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
the disclosure of contingent assets and liabilities as of the date of the
financial statements and the reported amounts of revenues, costs and expenses
during the reporting period. Actual results could differ from these
estimates.





Reclassification





Certain
reclassifications have been made to the 2007 presentation to conform to the 2008
presentation.





Accounts
Receivable and Allowance for Possible Losses





In
evaluating the need for an allowance for possible losses, the MGP performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customer's current creditworthiness, as determined by
the MGP's review of its customers' credit information. Credit is extended on an
unsecured basis to many of its energy customers. At December 31, 2008 and 2007,
the MGP's credit evaluation indicated that the Partnership had no need for an
allowance for possible losses.





24





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)





Revenue
Recognition





Revenues
from sales of natural gas and oil are recognized by the Partnership when the gas
and oil have been delivered to the purchaser. The Partnership's natural gas and
oil is sold under various contracts entered into by its MGP. Virtually all the
MGP's contract pricing provisions are tied to a market index, with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of natural gas and prevailing supply and
demand conditions, so that the price the Partnership receives from the sale of
its natural gas fluctuates to remain competitive with natural gas supplies
generally available in the market.





Because
there are timing differences between the delivery of the Partnership's natural
gas and oil and its receipt of a delivery statement, the Partnership has
unbilled revenues. These revenues are accrued based on volumetric data from its
records and its estimates of the related transportation and compression fees,
which are, in turn, based on applicable product prices. The Partnership had
unbilled trade receivables of $932,400 at December 31, 2008 and $1,217,400 at
December 31, 2007, respectively, which are included in Accounts
receivable-affiliate on the Partnership's Balance Sheets.





Fair
Value of Financial Instruments





For cash,
receivables and payables, the carrying amounts approximate fair values because
of the short maturities of these instruments.





For
derivatives, the carrying value approximates fair value because they have been
marked to market.





Supplemental
Cash Flow Information





The
Partnership considers temporary investments with a maturity at the date of
acquisition of 90 days or less to be cash equivalents. No cash was paid by the
Partnership for interest or income taxes for the years ended December 31, 2008
and 2007.





Concentration
of Credit Risk





Financial
instruments, which potentially subject the Partnership to concentrations of
credit risk, consist principally of periodic temporary investments of cash and
cash equivalents. The Partnership places its temporary cash investments in
deposits with high-quality financial institutions. At December 31, 2008, the
Partnership had $1,284,300 in deposits at one bank of which $1,034,300 was over
the insurance limit of the Federal Deposit Insurance Corporation and at December
31, 2007, the Partnership had $1,618,600 in deposits at one bank of which
$1,518,600 was over the insurance limit of the Federal Deposit Insurance
Corporation. No losses have been experienced on such investments.





25





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)





Comprehensive
Income





Comprehensive
income includes net income and all other changes in equity of a business during
a period from transactions and other events and circumstances from non-owner
sources. These changes, other than net income, are referred to as "other
comprehensive income (loss)" and, for the Partnership, include changes in the
fair value of hedging contracts related to commodity derivatives.





Oil
and Gas Properties





Oil and
gas properties are stated at cost. Depletion is based on cost less estimated
salvage value primarily using the unit-of-production method over the assets'
estimated useful lives. Maintenance and repairs are expensed as incurred. Major
renewals and improvements that extend the useful lives of property are
capitalized.





Oil
      and gas properties consist of the following at the dates
      indicated:
                
                December
      31,2008
                
                
                2007Natural
      gas and oil properties:Proved
      properties:Leasehold
      interest
                
                $
                1,417,900
                
                
                $
                1,440,700Wells
      and related
      equipment
                
                
                66,172,400
                
                
                
                66,456,50067,590,300
                
                
                
                67,897,200Accumulated
      depletion
                
                
                (44,036,500
                )
                
                
                (41,852,400
                )$
                23,553,800
                
                
                $
                26,044,800





The
Partnership uses the successful efforts method of accounting for oil and gas
producing activities. Costs to acquire mineral interests in oil and gas
properties and to drill and equip wells are capitalized.  Oil is
converted to gas equivalent basis (“mcfe”) at the rate of one barrel equals 6
mcf.





The
Partnership's long-lived assets are reviewed for impairment at least annually or
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. Long-lived assets are reviewed for potential
impairments at the lowest levels for which there are identifiable cash flows.
The review is done by determining if the historical cost of proved properties
less the applicable accumulated depreciation, depletion and amortization and
salvage value 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. The estimated future
level of production is based on assumptions surrounding future levels of prices
and costs, field decline rates, market demand and supply, and the economic and
regulatory climates. If the carrying value exceeds such undiscounted cash flows,
an impairment loss is recognized for the difference between the estimated fair
market value and the carrying value of the assets. The fair market value is
determined as the present value of future net revenues from the production of
proved reserves discounted using an annual discount of 12% in 2008 and 9% in
2007 and the 12 month NYMEX forward looking strip price for natural gas. There
was no impairment charge for the year ended December 31, 2008 and
2007.


26





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)





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. As a result of retirements the
Partnership reclassified $128,700 and $1,502,900 from oil and gas properties, to
accumulated depletion for the years ended December 31, 2008 and 2007,
respectively. 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 Net
Earnings.





Asset
Retirement Obligation





The fair
values of asset retirement obligations are recognized in the period they are
incurred if a reasonable estimate of fair value can be made. Asset retirement
obligations primarily relate to the abandonment of oil and gas producing
properties and include costs to dismantle and relocate or dispose of production
equipment, gathering systems, wells and related structures. Estimates are based
on 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 Partnership does not provide for a market risk
premium associated with asset retirement obligations because a reliable estimate
cannot be determined, see Note 8.





Environmental
Matters





The
Partnership is subject to various federal, state and local laws and regulations
relating to the protection of the environment. The Partnership has established
procedures for the ongoing evaluation of its operations, to identify potential
environmental exposures and to comply with regulatory policies and
procedures.





The
Partnership accounts for environmental contingencies in accordance with SFAS No.
5 Accounting for Contingencies. 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. Atlas Energy
maintains insurance that may cover in whole or in part certain environmental
expenditures. For the years ended December 31, 2008 and 2007, the Partnership
had no environmental matters requiring specific disclosure or the recording of a
liability.





Major
Customers





The
Partnership's natural gas is sold under contract to various
purchasers.  For the year ended December 31, 2008, sales to UGI Energy
Services, Inc., Conoco Phillips Company, Colonial Energy, Inc. and Equitable Gas
accounted for 16%, 16%, 13% and 10% respectively, of total revenues. For the
year ended December 31, 2007, sales to UGI Energy Services, Inc., Colonial
Energy, Inc., and Knox Energy accounted for 28%, 13% and 12%, respectively, of
total revenues. No other customers accounted for 10% or more of total revenues
for the years ended December 31, 2008 and 2007.





27





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)





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 his pro
rata share of all items of partnership income and deductions in computing his
federal income tax liability.





Recently
Issued Financial Accounting Standards





In May
2008, the Financial Accounting Standards Board, (“FASB”), issued Statement of
Financial Accounting Standards, No. 162, The Hierarchy of Generally Accepted
Accounting Policies, (“SFAS 162”), which reorganizes the GAAP hierarchy.
The purpose of the new standard is to improve financial reporting by providing a
consistent framework for determining what accounting principles should be used
when preparing U.S. GAAP financial statements. The standard is effective 60 days
after the SEC's approval of the PCAOB's amendments to AU Section 411. The
adoption of SFAS 162 will not have an impact on the Partnership’s financial
position or results of operations.





In March
2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative
Instruments and Hedging Activities, or SFAS 161, an amendment of FASB
Statement No. 133, Accounting
for Derivative Instruments and Hedging Activities, (“SFAS 133”). SFAS 161
requires entities to provide qualitative disclosures about the objectives and
strategies for using derivatives, quantitative data about the fair value of and
gains and losses on derivative contracts, and details of credit-risk-related
contingent features in their hedged positions. The standard is effective for
financial statements issued for fiscal years and interim periods beginning after
November 15, 2008, with early application encouraged, but not required. SFAS 161
also requires entities to disclose more information about the location and
amounts of derivative instruments in financial statements; how derivatives and
related hedges are accounted for under SFAS 133 and how the hedges affect the
entity’s financial position, financial performance, and cash flows. The
Partnership will apply the requirements of SFAS No. 161 on its adoption on
January 1, 2009 and does not expect it to have an impact on its financial
position or results of operations.





In
February 2007, the FASB issued Statement of Financial Accounting Standards
No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities, (“SFAS No. 159”).
SFAS No. 159 permits entities to choose to measure eligible financial
instruments and certain other items at fair value. The objective is to improve
financial reporting by providing entities with the opportunity to mitigate
volatility in reported earnings caused by measuring related assets and
liabilities differently without having to apply complex hedge accounting
provisions. By electing the fair value option in conjunction with a derivative,
an entity can achieve an accounting result similar to a fair value hedge without
having to comply with complex hedge accounting rules. The statement was
effective for the Partnership as of January 1, 2008. The Partnership adopted
SFAS No. 159 at January 1, 2008, and has elected not to apply the fair value
option to any of its financial instruments not already carried at fair value in
accordance with other accounting standards, and therefore the adoption of SFAS
No. 159 did not impact the Partnership’s financial statements for the year ended
December 31, 2008.


28





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)





In
September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157, Fair Value
Measurement,(”SFAS No. 157”). SFAS No. 157 addresses the need for
increased consistency in fair value measurements, defining fair value as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the measurement date. It
also establishes a framework for measuring fair value and expands disclosure
requirements. In February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No.
157, (“FSP FAS 157-2”). FSP FAS 157-2, which was effective upon issuance,
delays the effective date of SFAS No. 157 for nonfinancial assets and
nonfinancial liabilities, except for items that are recognized or disclosed at
fair value at least once a year, to fiscal years beginning after November 15,
2008. On January 1, 2009, the Partnership will adopt SFAS No. 157 for
nonfinancial assets and liabilities that are not measured at fair value on a
recurring basis. For the Partnership, the nonfinancial assets and liabilities
will be limited to the initial recognition of asset retirement obligations. FSP
FAS 157-2 also covers interim periods within the fiscal years for items within
its scope. The delay is intended to allow the FASB and its constituents the time
to consider the various implementation issues associated with SFAS No. 157. The
Partnership adopted SFAS No. 157 as of January 1, 2008 with respect to its
derivative instruments which are measured at fair value within its financial
statements. See Note 7 for disclosures pertaining to the provisions of SFAS No.
157 with regard to the Partnership’s fair value measurements.





NOTE
3 - PARTICIPATION IN REVENUES AND COSTS





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





ManagingGeneral
                
                
                LimitedPartner
                
                
                PartnersOrganization
      and offering
      costs
                
                
                100
                %
                
                
                0
                %Lease
      costs
                
                
                100
                %
                
                
                0
                %Revenues
      (1)
                
                
                35
                %
                
                
                65
                %Operating
      costs, administrative costs, direct and all other costs (2)
                
                
                35
                %
                
                
                65
                %Intangible
      drilling
      costs
                
                
                0
                %
                
                
                100
                %Tangible
      equipment
      costs
                
                
                71.70
                %
                
                
                28.30
                %


____________





(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, which may not
      exceed 35%.


(2)
            These
      costs will be charged to the partners in the same ratio as the related
      production revenues are
credited.


29





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
4 – CERTAIN RELATIONSHIPS AND RELATED 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 Net Earnings are at $75 per well per month.
      Administrative costs incurred in 2008 and 2007 were $198,600 and $199,600,
      respectively.





·
            Monthly
      well supervision fees which are included in production expenses in the
      Partnership's Statements of Net Earnings are payable at $318 and $306 per
      well per month in 2008 and 2007, respectively, for operating and
      maintaining the wells. Well supervision fees incurred in 2008 and 2007
      were $841,900 and $813,500,
respectively.





·
            Transportation
      fees which are included in production expenses in the Partnership's
      Statements of Net Earnings are generally payable at 13% of the natural gas
      sales price. Transportation fees incurred in 2008 and 2007 were $731,600
      and $985,100, respectively.





·
            Direct
      costs which are included in production and general administrative expenses
      in the Partnership's Statements of Net Earnings are payable to the MGP and
      its affiliates as reimbursement for all costs expended on the
      Partnership's behalf. Direct costs incurred in 2008 and 2007 were $591,700
      and $633,300, respectively.





·
            Assets
      contributed by the MGP which are disclosed on the Partnership's Statements
      of Cash Flows as a non-cash investing activity for the year ended 2007 was
      $51,100.





The MGP
and its affiliates perform all administrative and management functions for the
Partnership including billing revenues and paying expenses. The line-item
“Accounts receivable – affiliate” on the Partnership's Balance Sheets represents
the net production revenues due from the MGP.





NOTE
5 - COMMITMENTS





Subject
to certain conditions, investor partners may present their interests beginning
in 2009 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.





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, 2008, the MGP has not
withheld any such funds.


30





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
6 - 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 provide a
distribution to the limited partners equal to at least 10% of their agreed
subscriptions. Subordination is determined on a cumulative basis, in each of the
first five years of Partnership operations, commencing with the first
distribution of revenues to the investor partners (July 2005).  Since
inception of the Partnership, the MGP has not been required to subordinate any
of its net revenues to its limited partners.





NOTE
7 – DERIVATIVE INSTRUMENTS





Atlas
Energy, on behalf of the Partnership from time to time enters into natural gas
future option contracts and collar contracts to hedge exposure to changes in
natural gas prices. At any point in time, such contracts may include regulated
New York Mercantile Exchange ("NYMEX") futures, 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. 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 applies the provisions of SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, ("SFAS 133"). SFAS 133 requires each
derivative instrument to be recorded in the balance sheet as either an asset or
liability measured at fair value. Changes in a derivative instrument’s fair
value are recognized currently in earnings unless specific hedge accounting
criteria are met.





At
December 31, 2008, Atlas Energy had allocated open natural gas futures contracts
to the Partnership related to natural gas sales covering 1,310,300 dekatherms
(“Dth”) of gas, maturing through December 31, 2013 at an average settlement
price of $8.22 per Dth. In addition, Atlas Energy had allocated oil futures
contracts to the Partnership related to oil sales covering 5,000 barrels
(“Bbls”) of oil, maturing through April 30, 2013 at an average settlement price
of $98.31 per Bbl. At December 31, 2008, the Partnership reflected a net hedge
asset on its Balance Sheets of $1,921,000. Due to the impairment of the
Partnership's oil and gas properties at December 31, 2006, a net offsetting
unrealized gain of $2,303,600 was reclassified into earnings from accumulated
other comprehensive income. At December 31, 2008, $401,800 of the
reclassification remains in accumulated other comprehensive income. Of the
$1,519,200 net gain in accumulated other comprehensive income at December 31,
2008, if the fair values of the instruments remain at current market values, the
Partnership will reclassify $805,100 of net gains to its Statements of Net
Earnings over the next twelve month period as these contracts expire, and
$714,100 of net gains in later periods. Actual amounts that will be reclassified
will vary as a result of future price changes. The Partnership realized losses
of $842,900 and $127,100 for the years ended December 31 2008 and 2007,
respectively; in its oil and gas revenues within its Statements of Net Earnings
related to the settlement of qualifying hedge instruments. Ineffective hedge
gains or losses are recorded within the Statements of Net Earnings while the
hedge contract is open and may increase or decrease until settlement of the
contract. The Partnership recognized no gains or losses during the years ended
December 31, 2008 and 2007 for hedge ineffectiveness or as a result of the
discontinuance of cash flow hedges.


31





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
7 ─ DERIVATIVE INSTRUMENTS (Continued)





As of
December 31, 2008, Atlas Energy had allocated to the Partnership the following
natural gas and oil volumes hedged:





Natural
Gas Fixed Price Swaps


Production
                  
                  
                  
                  
                  
                  AveragePeriod
      Ending
                  
                  
                  Volumes
                  
                  
                  Fixed
      Price
                  
                  
                  Fair
      ValueDecember
      31,
                  
                  
                  (MMbtu)
      (1)
                  
                  
                  (per
      MMbtu)
                  
                  
                  Asset
      (2)2009
                  
                  
                  
                  450,500
                  
                  
                  $
                  8.55
                  
                  
                  $
                  1,101,9002010
                  
                  
                  
                  311,500
                  
                  
                  
                  8.11
                  
                  
                  
                  301,8002011
                  
                  
                  
                  220,700
                  
                  
                  
                  7.84
                  
                  
                  
                  114,3002012
                  
                  
                  
                  163,100
                  
                  
                  
                  8.05
                  
                  
                  
                  128,2002013
                  
                  
                  
                  17,700
                  
                  
                  
                  8.73
                  
                  
                  
                  24,800$
                  1,671,000





Natural
Gas Costless Collars


Production
                    
                    
                    
                    
                    
                    
                    AveragePeriod
      Ending
                    
                    Option
                    
                    Volumes
                    
                    
                    Floor
      & Cap
                    
                    
                    Fair
      ValueDecember
      31,
                    
                    Type
                    
                    (MMbtu)
      (1)
                    
                    
                    (per
      MMbtu)
                    
                    
                    Asset
      (2)2009
                    
                    Puts
      purchased
                    
                    
                    2,800
                    
                    
                    $
                    11.00
                    
                    
                    $
                    14,0002009
                    
                    Calls
      sold
                    
                    
                    2,800
                    
                    
                    
                    15.35
                    
                    
                    
                    —2010
                    
                    Puts
      purchased
                    
                    
                    39,700
                    
                    
                    
                    7.84
                    
                    
                    
                    39,5002010
                    
                    Calls
      sold
                    
                    
                    39,700
                    
                    
                    
                    9.01
                    
                    
                    
                    —2011
                    
                    Puts
      purchased
                    
                    
                    88,600
                    
                    
                    
                    7.48
                    
                    
                    
                    43,8002011
                    
                    Calls
      sold
                    
                    
                    88,600
                    
                    
                    
                    8.44
                    
                    
                    
                    —2012
                    
                    Puts
      purchased
                    
                    
                    12,100
                    
                    
                    
                    7.00
                    
                    
                    
                    2,6002012
                    
                    Calls
      sold
                    
                    
                    12,100
                    
                    
                    
                    8.32
                    
                    
                    
                    —2013
                    
                    Puts
      purchased
                    
                    
                    3,600
                    
                    
                    
                    7.00
                    
                    
                    
                    8002013
                    
                    Calls
      sold
                    
                    
                    3,600
                    
                    
                    
                    8.25
                    
                    
                    
                    —$
                    100,700





32





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
7 ─ DERIVATIVE INSTRUMENTS (Continued)





Crude
Oil Fixed Price Swaps


Production
                  
                  
                  
                  
                  
                  AveragePeriod
      Ending
                  
                  
                  Volumes
                  
                  
                  Fixed
      Price
                  
                  
                  Fair
      ValueDecember
      31,
                  
                  
                  (Bbl)
                  
                  
                  (per
      Bbl)
                  
                  
                  Asset
      (3)2009
                  
                  
                  
                  900
                  
                  
                  $
                  100.14
                  
                  
                  $
                  43,7002010
                  
                  
                  
                  800
                  
                  
                  
                  97.40
                  
                  
                  
                  25,4002011
                  
                  
                  
                  700
                  
                  
                  
                  96.44
                  
                  
                  
                  17,9002012
                  
                  
                  
                  500
                  
                  
                  
                  96.00
                  
                  
                  
                  12,3002013
                  
                  
                  
                  200
                  
                  
                  
                  96.06
                  
                  
                  
                  3,500$
                  102,800





Crude
Oil Costless Collars


Production
                      
                      
                      
                      
                      
                      
                      AveragePeriod
      Ending
                      
                      Option
                      
                      Volumes
                      
                      
                      Floor
      & Cap
                      
                      
                      Fair
      ValueDecember
      31,
                      
                      Type
                      
                      (Bbl)
                      
                      
                      (per
      Bbl)
                      
                      
                      Asset
      (3)2009
                      
                      Puts
      purchased
                      
                      
                      600
                      
                      
                      $
                      85.00
                      
                      
                      $
                      18,8002009
                      
                      Calls
      sold
                      
                      
                      600
                      
                      
                      
                      118.63
                      
                      
                      
                      —2010
                      
                      Puts
      purchased
                      
                      
                      500
                      
                      
                      
                      85.00
                      
                      
                      
                      11,8002010
                      
                      Calls
      sold
                      
                      
                      500
                      
                      
                      
                      112.92
                      
                      
                      
                      —2011
                      
                      Puts
      purchased
                      
                      
                      400
                      
                      
                      
                      85.00
                      
                      
                      
                      8,4002011
                      
                      Calls
      sold
                      
                      
                      400
                      
                      
                      
                      110.81
                      
                      
                      
                      —2012
                      
                      Puts
      purchased
                      
                      
                      300
                      
                      
                      
                      85.00
                      
                      
                      
                      5,9002012
                      
                      Calls
      sold
                      
                      
                      300
                      
                      
                      
                      110.06
                      
                      
                      
                      —2013
                      
                      Puts
      purchased
                      
                      
                      100
                      
                      
                      
                      85.00
                      
                      
                      
                      1,6002013
                      
                      Calls
      sold
                      
                      
                      100
                      
                      
                      
                      110.09
                      
                      
                      
                      —$
                      46,500Total
      Net Asset
                      
                      
                      $
                      1,921,000


_____________





(1)
            MMBTU
      represents million British Thermal
Units.


(2)
            Fair
      value based on forward NYMEX natural gas
prices.


(3)
            Fair
      value based on forward WTI crude oil
prices.


33





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
7 ─ DERIVATIVE INSTRUMENTS (Continued)





The fair
value of the derivatives is included on the Partnership's Balance Sheets as
follows:





December
      31,2008
                
                
                2007Short-term
      hedge receivable due from affiliate
                
                $
                1,288,800
                
                
                $
                549,500Long-term
      hedge receivable due from affiliate
                
                
                842,000
                
                
                
                82,200Short-term
      hedge liability due to affiliate
                
                
                (110,400
                )
                
                
                (13,000
                )Long-term
      hedge liability due to
      affiliate
                
                
                (99,400
                )
                
                
                (825,600
                )$
                1,921,000
                
                
                $
                (206,900
                )





Fair
Value of Financial Instruments





The
Partnership adopted the provisions of SFAS 157 at January 1, 2008. SFAS 157
establishes a fair value hierarchy which requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. SFAS 157’s hierarchy defines three levels of inputs that may be used
to measure fair value:





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





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





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





The
Partnership uses the fair value methodology outlined in SFAS 157 to value the
assets and liabilities for its outstanding derivative contracts. All of the
Partnership’s derivatives contracts are defined as Level 2. The Partnership's
natural gas and crude oil derivative contracts are valued based on prices quoted
on the NYMEX or WTI and adjusted by the respective counterparty using various
assumptions including quoted forward prices, time value, volatility factors, and
contractual prices for the underlying instruments. In accordance with SFAS 157,
the following table represents the Partnership's fair value hierarchy for its
financial instruments at December 31, 2008.





Fair
      Value Measurements at December 31, 2008 UsingQuoted
      prices
                  
                  
                  Significant
      other
                  
                  
                  Significantin
      active
                  
                  
                  observable
                  
                  
                  unobservablemarkets
                  
                  
                  inputs
                  
                  
                  inputs(Level
      1)
                  
                  
                  (Level
      2)
                  
                  
                  (Level
      3)Commodity-based
      derivatives
                  
                  $
                  —
                  
                  
                  $
                  1,921,000
                  
                  
                  $
                  —Total
                  
                  $
                  —
                  
                  
                  $
                  1,921,000
                  
                  
                  $
                  —





34





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008








NOTE
8 – ASSET RETIREMENT OBLIGATION





The
Partnership accounts for its estimated plugging and abandonment costs of its oil
and gas properties in accordance with SFAS 143, Accounting for Asset Retirement
Obligations and FASB Interpretation No. 47, Accounting for Conditional Asset Retirement
Obligations.





A
reconciliation of the Partnership's liability for plugging and abandonment costs
for the years indicated are:





Years
      Ended December 31,2008
                
                
                2007Asset
      retirement obligation at beginning of
      year
                
                $
                2,321,400
                
                
                $
                2,276,900Revisions
      in
      estimates
                
                
                (178,200
                )
                
                
                (92,100
                )Accretion
      expense
                
                
                139,300
                
                
                
                136,600Asset
      retirement obligation at end of
      year
                
                $
                2,282,500
                
                
                $
                2,321,400





NOTE
9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)





The
supplementary information summarized below presents the results of natural gas
and oil activities in accordance with Statements of Financial Accounting
Standards No. 69, Disclosures
About Oil and Gas Producing Activities (“SFAS No. 69”). Annually, reserve
value information is provided to the investor partners pursuant to the
partnership agreement. The partnership agreement provides a presentment feature
whereby the MGP will buy partnership units, subject to annual limitations, based
upon a valuation formula price in the partnership agreement. Therefore, certain
information required under SFAS No. 69 is not presented.





No
consideration has been given in the following information to the income tax
effect of the activities, as the Partnership is not treated as a taxable entity
for income tax purposes.





(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:





At
      December 31,2008
                
                
                2007Mineral
      interest in proved
      properties:
                
                $
                1,417,900
                
                
                $
                1,440,700Wells
      and related
      equipment
                
                
                66,172,400
                
                
                
                66,456,500Accumulated
      depletion
                
                
                (44,036,500
                )
                
                
                (41,852,400
                )Net
      capitalized
      cost
                
                $
                23,553,800
                
                
                $
                26,044,800





35





ATLAS
AMERICA PUBLIC #14-2004 L.P.


NOTES
TO FINANCIAL STATEMENTS - (Continued)


DECEMBER
31, 2008





NOTE
9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
(Continued)





(2)
            Oil
      and Gas Reserve Information





The
information presented below represents estimates of proved developed natural gas
and oil reserves. All reserves are proved developed reserves and are located in
the Appalachian Basin area. The estimates of the Partnership's proved developed
gas and oil reserves are based upon evaluations made by management and verified
by Wright & Company, Inc., an independent petroleum-engineering firm, as of
December 31, 2008 and 2007. All reserves are located within the United States of
America.  Reserves are estimated in accordance with guidelines
established by the Securities and Exchange Commission and the Financial
Accounting Standards Board which require that reserve estimates be prepared
under existing economic and operating conditions with no provision for price and
cost escalation except by contractual arrangements. Proved developed reserves
are generally estimated quantities of crude oil and natural gas, which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs.





Proved
developed reserves are generally those which are expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as “proved developed reserves”
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.





There are
numerous uncertainties inherent in estimating quantities of proved developed
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 measure 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 which effects have not been provided.





Natural
      Gas
                    
                    
                    Oil(Mcf)
                    
                    
                    (Bbls)Proved
      developed reserves:Balance
      at December 31, 2006
                    
                    
                    6,500,400
                    
                    
                    
                    30,200Production
                    
                    
                    (989,000
                    )
                    
                    
                    (7,900
                    )Revisions
      to previous
      estimates
                    
                    
                    828,100
                    
                    
                    
                    (400
                    )Balance
      at December 31,
      2007
                    
                    
                    6,339,500
                    
                    
                    
                    21,900Production
                    
                    
                    (739,000
                    )
                    
                    
                    (5,200
                    )Revisions
      to previous
      estimates
                    
                    
                    336,400
                    
                    
                    
                    2,600Balance
      at December 31, 2008
                    
                    
                    5,936,900
                    
                    
                    
                    19,300





36





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 Chairman of the Board of
Directors, Chief Executive Officer and President, as appropriate, to allow
timely decisions regarding required disclosure. In designing and evaluating the
disclosure controls and procedures, our management recognized that any controls
and procedures, no matter how well designed and operated, can provide only
reasonable assurance of achieving the desired control objectives, and our
management necessarily was required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.





Under the
supervision of our Chairman of the Board of Directors, Chief Executive Officer
and President, 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 Chairman of the Board of Directors,
Chief Executive Officer and President, concluded that, as of December 31, 2008,
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 Rules
13a-15(f). Under the supervision and with the participation of management,
including our Chairman of the Board of Directors, Chief Executive Officer and
President, 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 as of December 31, 2008 was
effective.





This
annual report does not include an attestation report by Grant Thornton regarding
internal control over financial reporting. Management's report was not subject
to attestation by Grant Thornton pursuant to temporary rules of the Securities
and Exchange Commission that permit the Company to provide only management's
report in this annual report.


37





ITEM
9B.  OTHER INFORMATION





None.





PART
III





ITEM
10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE





Atlas
Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis
Heights Road, 2nd Floor
Moon Township, Pennsylvania 15108, which is also our MGP's primary
office.





Executive Officers and
Directors.The executive officers and directors of our MGP
will serve until their successors are elected.  The executive officers
and directors of our MGP are as follows:





NAME
              AGE
              POSITION OR
      OFFICEFreddie
      M. Kotek
              53
              Chairman
      of the Board of Directors, Chief Executive Officer and
      PresidentFrank
      P. Carolas
              49
              Executive
      Vice President – Land and Geology and a DirectorJeffrey
      C. Simmons
              50
              Executive
      Vice President – Operations and a DirectorJack
      L. Hollander
              52
              Senior
      Vice President – Direct Participation ProgramsSean
      P. McGrath
              37
              Chief
      Accounting OfficerMichael
      L. Staines
              59
              Senior
      Vice President, Secretary and a DirectorMatthew
      A. Jones
              47
              Chief
      Financial Officer





With
respect to the biographical information set forth below:





·
            the
      approximate amount of an individual's professional time devoted to the
      business and affairs of our MGP and Atlas America 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, 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 America as compared with the other affiliates of our MGP,
      such as Viking Resources or Resource
Energy.





Freddie M.
Kotek.President and Chief Executive Officer since January
2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has
been Executive Vice President of Atlas America since February 2004, and served
as a director from September 2001 until February 2004 and served as Chief
Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior
Vice President of Resource America, and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he
resigned from Resource America and all of its subsidiaries which are not
subsidiaries of Atlas America.  Mr. Kotek was President of Resource
Properties from September 2000 to October 2001 and its Executive Vice President
from 1993 to August 1999. Mr. Kotek received a Bachelor of Arts degree from
Rutgers College in 1977 with high honors in Economics. He also received a Master
in Business Administration degree from the Harvard Graduate School of Business
Administration in 1981. Mr. Kotek will devote approximately 95% of his
professional time to the business and affairs of the MGP and Atlas America,
Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder
of his professional time to the business and affairs of the MGP's other
affiliates.


38





Frank P.
Carolas.Executive Vice President-Land and Geology and a
Director since January 2001. Mr. Carolas has been an Executive Vice President of
Atlas America since January 2001 and served as a Director of Atlas America from
January 2002 until February 2004. Mr. Carolas has been a Senior Vice President
of Atlas Energy Management, Inc. since 2006.  Mr. Carolas was a Vice
President of Resource America from April 2001 until May 2004 when he resigned
from Resource America. Mr. Carolas served as Vice President of Land and Geology
for the MGP from July 1999 until December 2000 and for Atlas America from 1998
until December 2000. Before that Mr. Carolas served as Vice President of Atlas
Energy Group, Inc. from 1997 until 1998, which was the former parent company of
the MGP. Mr. Carolas is a certified petroleum geologist and has been with the
MGP and its affiliates since 1981. He received a Bachelor of Science degree in
Geology from Pennsylvania State University in 1981 and is an active member of
the American Association of Petroleum Geologists. Mr. Carolas devotes
approximately 100% of his professional time to the business and affairs of the
MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management,
Inc.





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 Masters 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 America, 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 America, Atlas Energy
Resources, LLC and Atlas Energy Management, Inc.





Sean P. McGrath.Chief
Accounting Officer since December 31, 2008. Mr. McGrath also has been the Chief
Accounting Officer of Atlas America, Inc. and ATN since December 31, 2008. Mr.
McGrath has been the Chief Accounting Officer of Atlas Pipeline Partners GP
since May 2005 and Chief Accounting Officer of Atlas Pipeline Holdings GP since
January 2006. 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 and received his Bachelor of Science degree in accounting from
LaSalle University in 1993. Mr. McGrath will devote approximately 70% of his
professional time to the business and affairs of the managing general partner
and Atlas America, and the remainder of his professional time to the business
and affairs of the managing general partner’s other affiliates, including Atlas
Pipeline Partners GP.





39





Michael L.
Staines.Senior Vice President, Secretary, and a Director
since 1998. Mr. Staines has been an Executive Vice President and Secretary of
Atlas America since 1998. Mr. Staines was a Senior Vice President of Resource
America from 1989 until May, 2005 when he resigned from Resource
America.  Mr. Staines was a director of Resource America from 1989 to
February 2000 and Secretary from 1989 to October 1998. Mr. Staines has been
President of Atlas Pipeline Partners GP since January 2001 and its Chief
Operating Officer and a member of its Managing Board since its formation in
November 1999.  Mr. Staines is a member of the Ohio Oil and Gas
Association and the Independent Oil and Gas Association of New York. Mr. Staines
received a Bachelor of Science degree from Cornell University in 1971 and a
Master of Business degree from Drexel University in 1977. Mr. Staines devotes
approximately 5% of his professional time to the business and affairs of the MGP
and Atlas America, and the remainder of his professional time to the business
and affairs of the MGP's other affiliates, including Atlas Pipeline Partners
GP.





Matthew A.
Jones.Chief Financial Officer since March 2006 for Atlas
Resources, LLC.  Mr. Jones has been the Chief Financial Officer since
January 2006 and a director of Atlas Pipeline Holdings since February 2006 and
has been Chief Financial Officer of Atlas Pipeline Partners GP and Atlas America
since March 2005.  He has been the Chief Financial Officer and a
director of Atlas Energy Resources and Atlas Energy Management, Inc. since their
formation.  From 1996 to 2005, Mr. Jones worked in the Investment
Banking Group at Friedman Billings Ramsey, concluding as Managing
Director.  Mr. Jones worked in Friedman Billings Ramsey's Energy
Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey's
Specialty Finance and Real Estate Group from 1996 to 1999.  Mr. Jones
is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his
professional time to the business and affairs of the MGP, Atlas America, Atlas
Energy Resources, LLC and Atlas Energy Management, Inc. and the remainder of his
professional time to the business and affairs of the MGP’s other
affiliates.





Audit Committee Financial
Expert.  The Board of Directors of our MGP acts as the audit
committee. The Board of Directors has determined that Freddie M. Kotek meets the
requirement of an “audit committee financial expert,” he is not
independent.





Remuneration of Officers and
Directors.No officer or director of the MGP will receive any
direct remuneration or other compensation from the
Partnerships.  These persons will receive compensation solely from
affiliated companies of the MGP.





Code of Business Conduct and
Ethics.Because the partnerships do not directly employ and
persons, the MGP has determined that the Partnerships will rely on a Code of
business Conduct and Ethics adopted by Atlas America, Inc. and/or Atlas Energy
Resources, LLC that applies to the principal executive officer, principal
financial officer and principal accounting officer of the MGP, as well as to
persons performing services for the MGP generally. You may obtain a copy of this
Code of Business Conduct and Ethics by a request to the MGP at Atlas Resources,
LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor,
Moon Township, Pennsylvania 15108.





ITEM
11.  EXECUTIVE COMPENSATION





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 Transactions,and Director Independence” for a discussion of
compensation paid by us to our MGP.





ITEM
12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT





As of
December 31, 2008, we had 5,256.95 investor 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 2009 for purchase,
the MGP is not obligated by the Partnership agreement from purchasing more than
5% of our total outstanding units in any calendar year.


40





Organizational and Security Ownership
of Beneficial Owners.Atlas America owns approximately 49.4%
of the limited liability company interest of Atlas Energy Resources, LLC which
owns 100% of the limited liability company interests of Atlas Energy Operating
Company, LLC, which owns 100% of the limited liability company interests of AIC,
LLC, which owns 100% of the  limited liability company interest of the
managing general partner. The officers and directors of Atlas America and Atlas
Energy Resources LLC are set forth below.  The directors of AIC, LLC
are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey Simmons.  The
biographies of Messrs, Staines and Simmons are set forth above.





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





Oil and Gas
Revenues.  Our MGP is allocated 35% of our oil and gas revenues
in return for its payment and/or contribution of services towards our
syndication and offering costs equal to 12.8% of our subscriptions, its payment
of 71.70% of the tangible costs of drilling and completing our wells and its
contribution to us of all of our oil and gas leases.  These capital
contributions from our MGP totaled $21,778,200. During the years ended December
31, 2008 and 2007, our MGP received $1,694,700 and $1,961,400, respectively,
from 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, 2008 and 2007, our MGP received $198,600 and $199,600,
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, 2008 and 2007, we
reimbursed our MGP $591,700 and $633,300, respectively, for direct
costs.





Well Charges.  Our
MGP, as operator, 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 amount of $318 and $306 per well
per month in 2008 and 2007, respectively, subject to an annual adjustment for
inflation.  The well supervision fees were proportionately reduced to
the extent we acquired less than 100% of the working interest in a well. For the
years ended December 31, 2008 and 2007, our MGP received $841,900 and $813,500,
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.  Transportation rate is
generally 13% of the natural gas sales price.  For the years ended
December 31, 2008 and 2007, $731,600 and $985,100, respectively, was paid to our
MGP for gathering fees. In turn, our MGP paid 100% of these amounts to Atlas
America, for the use of its gathering system in transporting a majority of our
natural gas production.





Other
Compensation.  For the years ended December 31, 2008 and 2007,
our MGP did not advance any funds to us, or did they provide us with any
equipment, supplies or other services.





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, 2008 and 2007, and for the reviews of the financial
statements included in our Quarterly Reports on Form 10-Q during such years were
$30,800 and $32,500, respectively.


41





Procedures for Audit Committee
Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor.Pursuant to its charter, the Audit Committee of our MGP 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


EXHIBIT
INDEX





Description
              Location4
      (a)
              Certificate
      of Limited Partnership for Atlas America
              Previously
      filed in our Form S-1 onPublic
      #14-2004 L.P.
              June
      30, 20044
      (b)
              Amended
      and Restated Certificate and Agreement of Limited
              Previously
      filed in our Form S-1 onPartnership
      for Atlas America Public #14-2004 L.P. (1)
              June
      30, 20044(c)
              Drilling
      and Operating Agreement for Atlas America
              Previously
      filed in our Form S-1 onPublic
      #14-2004 L.P. (1)
              June
      30, 200431.1
              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.


_______________





(1)
            
            Filed
      on June 30, 2004 in the Form S-1 Registration Statement dated June 30,
      2004, File No. 333-117035





42





SIGNATURES





In
      accordance with Section 13 or 15 (d) of the Exchange Act, the registrant
      caused this report to be signed onits
      behalf by the undersigned, thereunto duly authorized.Atlas
      America Public #14-2004 L.P.Atlas
      Resources, LLC, Managing General PartnerDate:  March
      30, 2009
              
              By: /s/ Freddie M.
      KotekFreddie
      M. Kotek, Chairman of the Board of Directors, Chief
    ExecutiveOfficer
      and PresidentIn
      accordance with the Exchange Act, this report has been signed by the
      following persons on behalf of theregistrant
      and in the capacities and on the dates indicated.Date:  March
      30, 2009
              
              By: /s/ Freddie M.
      KotekFreddie
      M. Kotek, Chairman of the Board of Directors, Chief
    ExecutiveOfficer
      and PresidentDate:  March
      30, 2009
              
              By: /s/ Frank P.
      CarolasFrank
      P. Carolas, Executive Vice President – Land and GeologyDate:  March
      30, 2009
              
              By: /s/ Jeffrey C.
      SimmonsJeffrey
      C. Simmons, Executive Vice President – OperationsDate:  March
      30, 2009
              
              By: /s/ Sean P.
      McGrathSean
      P. McGrath, Chief Accounting OfficerDate:  March
      30, 2009
              
              By: /s/ Matthew A.
      JonesMatthew
      A. Jones, 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.


43