**United
                  States Securities and Exchange Commission****Washington,
                  D.C. 20549****Form
                  10-KSB**(Mark
                  One)**R**
              **ANNUAL
                  REPORT UNDER SECTION 13 OR 15 (d) OF THE****SECURITIES
                  EXCHANGE ACT OF 1934**For
                  the fiscal year ended December 31, 2005o
              **TRANSITION
                  REPORT UNDER SECTION 13 OR 15 (d) OF THE****SECURITIES
                  EXCHANGE ACT OF 1934**For
                  the transition period from _____ to _____Commission
                  file number 333-117035-01**ATLAS
                  AMERICA PUBLIC #14-2005 (A) L.P.**(Name
                  of small business issuer in its
                  charter)
 
 **Delaware**
              
              **20-1849549**(State
                  or other jurisdiction of
              
              (I.R.S.
                  EmployerIncorporation
                  or organization)
              
              Identification
                  No)311
                  Rouser Rd.
              
              Zip
                  CodeMoon
                  Township, PA
              
              15108(address
                  of principal executive offices)Issuer’s
                  telephone number**(412)
                  262-2830**Securities
                  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)
 
 Check
        whether the issuer (1) filed all reports required to be filed by Section
        13 or
        15(d) of the Exchange Act during the past 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 R
 
 Check
        if
        there is no disclosure of delinquent filers in response to Item 405 of
        Regulation S-B contained in this form, and no disclosure will 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-KSB or any
        amendment to this Form 10-KSB. R
 
 State
        issuer’s revenues for its most recent fiscal year. $4,702,200
 
 State
        the
        aggregate market value of the voting stock held by non-affiliates of the
        Registrant. Not Applicable.
 
 Indicate
        by check mark whether the registrant is a shell company (as defined in Rule
        12b-2 of the Exchange Act).
 Yes o No R
 
 Transitional
        Small Business Disclosure Format (check one): Yes o No R
  
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **INDEX
        TO ANNUAL REPORT**
 **ON
        FORM 10-KSB**
 
 **PART
                  I**
              
              
              **PAGE**Item
                  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
              9**PART
                  II**Item
                  5:
              
              Market
                  for Registrant’s Common Equity and Related Security Holder
                  Matters
              9-10Item
                  6:
              
              Management’s
                  Discussion and Analysis of Financial Condition or Plan of
                  Operations
              10-14Item
                  7:
              
              Financial
                  Statements
              15-31Item
                  8:
              
              Changes
                  in and Disagreements with Accountants on Accounting and Financial
                  Disclosure
              31Item
                  8A:
              
              Controls
                  and Procedures
              31Item
                  8B:
              
              Other
                  Information
              31**PART
                  III**Item
                  9:
              
              Directors,
                  Executive Officers and Significant Employees, Compliance with Section
                  (16a)of
                  the Exchange Act
              32-34Item
                  10:
              
              Executive
                  Compensation
              34Item
                  11:
              
              Security
                  Ownership of Certain Beneficial Owners and Management
              34Item
                  12:
              
              Certain
                  Relationships and Related Party Transactions
              35Item
                  13:
              
              Exhibits
              36Item
                  14:
              
              Principal
                  Accountant Fees and Services
              36**SIGNATURES**
              37
 
 
  2
  
 **PART
        I**
 
 **ITEM
        1. DESCRIPTION OF BUSINESS**
 
 ***Forward-Looking
        Statements.*** WHEN
        USED
        IN THIS FORM 10-KSB, THE WORDS “BELIEVES” “ANTICIPATES” “EXPECTS” AND SIMILAR
        EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS. SUCH STATEMENTS
        ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES.  THESE RISKS AND
        UNCERTAINTIES, INCLUDING RISKS ASSOCIATED WITH FLUCTUATIONS IN THE MARKET
        PRICE
        FOR NATURAL GAS AND OIL, COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY.
        READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE FORWARD-LOOKING
        STATEMENTS, WHICH SPEAK ONLY AS OF THE DATE HEREOF. WE UNDERTAKE NO OBLIGATION
        TO PUBLICLY RELEASE THE RESULTS OF ANY REVISIONS TO FORWARD-LOOKING STATEMENTS
        WHICH WE MAY MAKE TO REFLECT EVENTS OR CIRCUMSTANCES AFTER THE DATE OF THIS
        FORM
        10-KSB OR TO REFLECT THE OCCURRENCE OF UNANTICIPATED EVENTS.
 
 ***General.*** **** We were
        formed as a Delaware limited partnership on March 3, 2005, with Atlas Resources,
        Inc. as our managing general partner. We drilled and currently operate wells
        located in western Pennsylvania and Tennessee. We have no employees and rely
        on
        our managing general partner for management which, in turn, relies on its
        parent
        company, Atlas America, Inc. (“Atlas”) for administrative services. See Item 9
“Directors, Executive Officers and Significant Employees, Compliance with
        Section 16(a) of the Exchange Act”.
 
 We
        received total cash subscriptions from investors of $69,674,900, of which
        $63,072,000 has been paid to our managing partner as operator and general
        drilling contractor under our drilling and operating agreement and the remaining
        $6,602,900 is shown as an account receivable from our managing general partner
        on our balance sheet. Our managing general partner contributed cash and leases
        and paid all organization and offering costs and 70.41% of the tangible
        (“equipment”) costs for a total capital contribution to us of $24,625,800. We
        have drilled 336 developmental wells to the Clinton/Medina and Upper Devonian
        Sandstones and Southern Shale geological formations in Pennsylvania and
        Tennessee.
 
 ***Spin-off
        of Atlas America, Inc. from Resource America, Inc.*** On
        June
        30, 2005, Resource America, Inc. (“RAI”) our former indirect parent distributed
        its remaining 10.7 million shares of Atlas America, Inc. to its stockholders
        in
        the form of a tax-free dividend. Although the distribution itself was tax-free
        to RAI’s stockholders, as a result of the deconsolidation there may be some tax
        liability arising from prior unrelated corporate transactions among Atlas
        America, Inc. and some of its subsidiaries. These transactions did not have
        a
        direct material impact on our financial position or results of operations
        and
        Atlas America, Inc. (and our managing general partner) no longer consolidate
        with RAI as of June 30, 2005.
 
 ***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 managing general partner. 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 beyond those initially drilled after
        our
        partnership formation. See Item 2 “Description of Properties” for information
        concerning our wells.
 
 Our
        ongoing operating and maintenance costs have been and are expected to be
        fulfilled through revenues from the sale of our gas and oil production. We
        pay
        our managing general partner a monthly well supervision fee of $285 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 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.  3
  
 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 and materials
        and a
        reasonable charge for services performed directly by our managing general
        partner or its affiliates. Also, beginning one year after each of our wells
        has
        been placed into production our managing general partner, as operator, may
        retain $200 of our revenues per month to cover the estimated future plugging
        and
        abandonment costs of the well. As of December 31, 2005, our managing general
        partner 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 managing general partner is responsible for selling our natural
        gas production, and its policy is to treat all wells in a given geographic
        area
        equally. Our natural gas is being sold as discussed in Item 2 “Description of
        Properties - Delivery Commitments”. During 2005, we experienced no problems in
        selling our natural gas and oil, although prices we received varied, sometimes
        significantly. 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 - Delivery Commitments” 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
        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.
 
 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;  4
  
 ***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 must also 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-KSB Annual Report and Form 10-QSB 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 managing general partner will provide copies of any of these reports
        to you
        without charge. Such requests should be made to:
 
 ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.
 311
        Rouser Road
 Moon
        Township, PA 15108
 
 **ITEM
        2. DESCRIPTION OF PROPERTIES**
 
 ***Drilling
        Activity*** **.** As of
        December 31, 2005, we have drilled 336 gross wells. All the wells drilled
        were
        development wells, which mean a well drilled within the proved area of an
        oil or
        gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
 **Development
                  Wells****Period
                  Ended December 31,**
              
              **Productive****(1)**
              
              **Dry****(2)****Gross****(3)**
              
              **Net****(4)**
              
              **Gross****(3)**
              
              **Net****(4)**2005
              
              
              139.00
              
              
              128.62
              
              
              4
              
              
              4
 
  
 (1)
            A
                “productive well” generally means a well that is not a dry
                hole. (2)
            A
                “dry hole” generally means a well found to be incapable of producing
                either oil or gas in sufficient quantities to justify completion
                as an oil
                or gas well. The term “completion” refers either to the installation of
                permanent equipment for the production of oil or gas or, in the case
                of a
                dry hole, to the reporting of the abandonment of the well to the
                appropriate regulatory agency. (3)
            A
                “gross” well is a well in which we have a working
                interest. (4)
            A
                “net” well equals the actual working interest we own in one gross well
                divided by one hundred. For example, a 50% working interest in a
                well is
                one gross well, but a .50 net well.  5
  
 ***Summary
        of Productive Wells*** **.** The
        table below shows the number of productive gross and net wells at December
        31,
        2005, in which we have a working interest. All wells are located in the
        Appalachian Basin.
 
 **Number
                  of Productive Wells****Gross**
              
              **Net**Gas
              
              
              123.00
              
              
              113.37Oil
              
              
              16.00
              
              
              15.25Total
              
              
              139.00
              
              
              128.62
 
 ***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 period indicated.
 
 **Average****Production
                  Cost****Year**
              
              **Production**
              
              **Average
                  Sales Price**
              
              **(Lifting
                  Cost)****Ended**
              
              **Oil
                  (bbls)**
              
              **Gas
                  (mcf)**
              
              **per
                  bbl**
              
              **per
                  mcf**
              
              **per
                  mcfe****(1)
                  (2)**2005
              
              
              4,900
              
              
              460,100
              
              $
              56.46
              
              $
              9.62
              
              $
              .67
 
  
 (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. 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
        make the standardized SEC PV-10 estimates of future net cash flows from proved
        reserves using natural gas and oil sales prices in effect as of the dates
        of the
        estimates, which are held constant throughout the life of the properties.
        We
        based our estimates of proved reserves on the following year-end weighted
        average prices:
 
 **December
                  31,****2005**Natural
                  gas (per mcf)
              
              $
              10.46Oil
                  (per bbl)
              
              $
              57.50
 
 Reserve
        estimates are imprecise and may change as additional information becomes
        available. Furthermore, estimates of natural gas and oil reserves, of necessity,
        are projections based on engineering data. There are uncertainties inherent
        in
        the interpretation of this data as well as the projection of future rates
        of
        production and the timing of development expenditures. Reservoir engineering
        is
        a subjective process of estimating underground accumulations of natural gas
        and
        oil that cannot be measured in an exact way, and the accuracy of any reserve
        estimate is a function of the quality of available data and of engineering
        and
        geological interpretation and judgment. Reserve reports of other engineers
        might
        differ from the reports we prepared which were reviewed by Wright & Company,
        our consultant. 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 may be different from those we estimated
        in
        preparing the reserve reports received by Wright & Company. The amounts and
        timing of future operating, development and abandonment costs also may differ
        from those we estimated. Accordingly,
 the
        reserves of our wells as set forth in the following table ultimately may
        not be
        produced and our proved undeveloped reserves may not be developed within
        the
        periods anticipated. 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.
  6
  
 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 and capital costs.
        The
        meaningfulness of these estimates depends on the accuracy of the assumptions
        on
        which they were based.
 
 We
        evaluate natural gas reserves at constant temperature and pressure. A change
        in
        either of these factors can affect the measurement of natural gas reserves.
        We
        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 11 of the “Notes to “Financial Statements” in
        Item 7 “Financial Statements”.
 
 **December
                  31,****2005**Natural
                  gas reserves - Proved Reserves (Mcf)(1)(4):Proved
                  developed reserves (2)
              
              
              22,139,100Total
                  proved reserves of natural gas
              
              
              22,139,100Oil
                  reserves - Proved Reserves (Bbl)(1)(4):Proved
                  developed reserves (2)
              
              
              65,900Total
                  proved reserves of oil
              
              
              65,900Total
                  proved reserves (Mcfe)
              
              
              22,534,500PV-10
                  estimate of cash flows of proved reserves (3)(4):Proved
                  developed reserves
              
              $
              96,819,800Total
                  PV-10 estimate
              
              $
              96,819,800PV-10
                  estimate per limited partner unit (5)
              
              $
              9,014Undiscounted
                  estimate per limited partner unit (5)
              
              $
              16,419
  
 (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 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 managing general partner for purchase
                is
                different, because it is calculated under a formula set forth in
                the
                partnership agreement.  7
  
 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. For
        additional information concerning our natural gas and oil reserves and
        activities, see Note 11 of the “Notes to “Financial Statements” in Item 7
“Financial Statements”.
 
 ***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, we conduct only a perfunctory title examination at
        the
        time we acquire a property. Before we commence drilling operations, we conduct
        an extensive title examination and we perform curative work on defects that
        we
        deem significant. We have obtained title examinations for substantially all
        of
        our managed producing properties. No single property represents a material
        portion of our holdings.
 
 Our
        properties are subject to royalty, overriding royalty and other outstanding
        interests customary in the 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 and undeveloped
        oil and gas acreage in which we had an interest at December 31,
        2005.
 
 **Developed
                  Acreage**
              
              **Undeveloped
                  Acreage (****3)****Gross****(1)**
              
              **Net****(2)**
              
              **Gross****(1)**
              
              **Net****(2)****Location**Pennsylvania
              
              
              5,612.32
              
              
              5,404.79
              
              
              ―
              
              
              ―Tennessee
              
              
              1,280.00
              
              
              1,087.50
              
              
              ―
              
              
              ―Total
              
              
              6,892.32
              
              
              6,492.29
              
              
              ―
              
              
              ―
 
  
 (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 .50 net acre. (3)
            “Undeveloped
                acreage” means those lease acres on which wells have not been drilled or
                completed to a point that would permit the production of commercial
                quantities of oil and gas regardless of whether or not the acreage
                contains proved reserves. 
 ***Delivery
        Commitments.*** Our
        managing general partner and Resource Energy, Inc. and Atlas Energy Group,
        Inc.,
        its affiliates, have a natural gas supply agreement with Amerada Hess
        Corporation for a 10-year term which began on April 1, 1999. The agreement
        was
        formerly with First Energy Solutions Corporation and was acquired by Amerada
        Hess Corporation in 2005. For the next 12 months, our managing general partner
        anticipates that approximately 40% of our gas will be sold through this
        agreement with Amerada Hess Corporation, approximately 27% will be sold through
        a natural gas supply agreement with UGI Energy Services, Inc. and approximately
        33% will be sold through other third-party natural gas purchasers or marketers.
        The natural gas delivery commitments with Amerada Hess Corporation, UGI Energy
        Services, Inc. and our other third-party natural gas purchasers or marketers
        are
        generally for a one-year term.
 
 The
        pricing arrangements with Amerada Hess Corporation, UGI Energy Services,
        Inc.
        and other third-party gas purchasers or marketers are tied to the New York
        Mercantile Exchange Commission (“NYMEX”) monthly futures contract price, which
        is reported daily in the Wall Street Journal. The total price received for
        our
        gas is a combination of the monthly NYMEX futures price plus a fixed basis.
        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.”
  8
  
 Pricing
        for natural gas and oil has been volatile and uncertain for many years. The
        agreements with Amerada Hess Corporation, UGI Energy Services, Inc. and the
        other third-party gas purchasers or marketers also permit our managing general
        partner and its affiliates to implement gas forward sales transactions through
        those companies. Amerada Hess Corporation, UGI Energy Services, Inc. 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 our managing general partner, which then makes those arrangements
        available to us and its other partnerships. The majority of our managing
        general
        partner’s hedges are implemented through its natural gas purchasers. These
        transactions are similar to NYMEX based futures contracts, swaps and options,
        but also require firm delivery of the hedged quantity and are not deemed
        hedges
        for accounting purposes because they required firm delivery of natural gas.
        Thus, our managing general partner limits these arrangements to much smaller
        quantities than those projected to be available at any delivery point. The
        price
        paid by Amerada Hess Corporation, UGI Energy Services, Inc. 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 value.  To limit
        our managing general partner’s and its partnerships’ exposure to changes in
        natural gas prices our managing general partner uses hedges through contracts
        including regulated NYMEX futures and options contracts and non-regulated
        over-the-counter futures contracts with qualified counterparties. The futures
        contracts employed by our managing general partner are commitments to purchase
        or sell natural gas at future dates and generally cover one-month periods
        for up
        to 24 months in the future. The overall portion of our natural gas portfolio
        that is hedged changes from time to time.
 
 To
        assure
        that all financial instruments will be used solely for hedging price risks,
        and
        not for speculative purposes, our managing general partner has established
        a
        committee to assure that all gas prices hedges, whether made through a
        third-party marketer or purchaser, are made in compliance with our managing
        general partner’s hedging policies and procedures. Our managing general partner
        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 Amerada Hess Corporation, UGI Energy Services,
        Inc.
        and the other third-party gas purchasers or marketers.
 
 **ITEM
        3. LEGAL PROCEEDINGS**
 
 None
 
 **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:
  9
  
 ·
            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, 2005, we had 2,190 unit holders.
 
 **Distributions.** Our
        managing general partner 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 managing general partner determines are
        not
        necessary for us to retain, to our partners. We will not advance or borrow
        funds
        for purposes of making distributions if the amount of the distributions would
        exceed our accrued and received revenues for the previous four quarters,
        less
        paid and accrued operating costs with respect to the revenues. The determination
        of our revenues and costs is made in accordance with generally accepted
        accounting principles, consistently applied, and cash distributions to our
        managing general partner may only be made in conjunction with distributions
        to
        our investor partners. During the period ended December 31, 2005, the
        partnership had no distributions.
 
 **ITEM
                  6.**
              **MANAGEMENT’S
                  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR
                  PLAN****OF
                  OPERATION**
 
 This
        Item
        6 “Management’s Discussion and Analysis of Financial Conditions or Plan of
        Operation” should be read in conjunction with Item 7 “Financial Statements” and
        the “Notes to Financial Statements”.
 
 ***General*** .
        We were
        formed as a Delaware limited partnership on March 3, 2005, with Atlas Resources,
        Inc. as our managing general partner, to drill natural gas development wells.
        The period ended December 31, 2005 is the first calendar year that almost
        all of
        our wells were on line and producing natural gas and, to a lesser extent,
        oil.
        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 additional funds will be required for
        drilling.
 
 ***Spin-off
        of Atlas America, Inc. from Resource America, Inc.*** On
        June
        30, 2005, RAI, our former indirect parent, distributed its remaining 10.7
        million shares of Atlas America, Inc. to its stockholders in the form of
        a
        tax-free dividend. Although the distribution itself was tax-free to RAI’s
        stockholders, as a result of the deconsolidation there may be some tax liability
        arising from prior unrelated corporate transactions among Atlas America,
        Inc.
        and some of its subsidiaries. These transactions did not have a direct material
        impact on our financial position or results of operations and Atlas America,
        Inc. (and our managing general partner) no longer consolidate with RAI as
        of
        June 30, 2005.
 
 ***Results
        of Operations.*** ** The
        following table sets forth information for the period March 3, 2005 through
        December 31, 2005 relating to revenues we recognized and costs, expenses
        we
        incurred, and our daily production volumes, our average sales prices and
        our
        production cost per equivalent unit during the period
        indicated:
  10
  
 **December
                  31,****2005**Revenues
                  (in thousands):Gas
                  (1)
              
              $
              4,428Oil
              
              $
              274Total
              
              $
              4,702Production
                  volumes:Gas
                  (thousands of cubic feet (mcf/day)
              
              
              1,519Oil
                  (barrels (bbls/day)
              
              
              16Total
                  (mcfe/day)
              
              
              1,615Average
                  sales price:Gas
                  (per mcf)(2)
              
              $
              9.62Oil
                  (per bbl)
              
              $
              56.46Production
                  costs:As
                  a percent of sales
              
              
              7
              %Per
                  equivalent mcf
              
              $
              .67Depletion
                  per mcfe
              
              $
              3.15
 
  
 (1)
            Excludes
                sales of residual gas and sales to
                landowners. (2)
            The
                average sales price per mcf before the effects of hedging was $9.51
                for
                the year ended December 31, 2005. 
 ***Natural
        Gas Revenues.*** Our
        natural gas revenues were $4,427,700 for the period ended December 31, 2005.
        We
        expect that our natural gas revenues will increase over the next year, as
        more
        of our wells are put on-line and are producing larger volumes of natural
        gas
        and, to a lesser extent, oil.
 
 ***Oil
        Revenues*** *.* We
        drilled our wells primarily to produce natural gas, rather than oil, but
        we do
        have some oil production. Our oil revenues were $274,100 for the period ended
        December 31, 2005.
 
 The
        price
        we receive for our natural gas is primarily a result of the index driven
        agreements with Amerada Hess Corporation, UGI Energy Services, Inc. and our
        other natural gas purchasers See Item 2 “Description of Properties - Delivery
        Commitments.” Thus, the price we receive for our natural gas may vary
        significantly each month as the underlying index changes in response to market
        conditions.
 
 ***Expenses.*** Production expenses were $325,800 for the period ended December 31,
        2005.
 
 Depletion
        of our oil and gas properties as a percentage of oil and gas revenues was
        33%
        for the period ended December 31, 2005.
 
 General
        and Administrative expenses were $58,600 for the period ended December 31,
        2005.
        These expenses include outside costs for services as well as the monthly
        administrative fee charged by our managing general partner.
 
 ***Liquidity
        and Capital Resources.*** Cash
        used in operating activities was $5,701,300 for the period ended December
        31,
        2005, which was primarily related to net income before depletion and increases
        in accounts receivable, accrued liabilities and accretion expense.
 
 Cash
        used
        in investing activities was $63,072,000 for the period ended December 31,
        2005,
        which was used in drilling contracts paid to our managing general
        partner.
  11
  
 Cash
        provided by financing activities was $69,674,900 for the period ended December
        31, 2005, which represents investor capital contributions.
 
 We
        had no
        material commitments to make capital expenditures during the period and we
        do
        not expect any in the foreseeable future, except that our managing general
        partner may withhold funds for estimated future plugging and abandonment
        costs.
        If we need any additional funds for future capital expenditures, we will
        reserve
        them from our production revenues or borrow the additional funds from our
        managing general partner or its affiliates, although they are not contractually
        committed to make a loan to us. The amount that we may borrow may not at
        anytime
        exceed 5% of our total subscriptions, and we will not borrow from
        third-parties.
 
 We
        believe that our future cash flow from operations and amounts available from
        borrowings from our managing general partner or its affiliates, if any, will
        be
        adequate to fund our operations for the foreseeable future.
 
 ***Critical
        Accounting Estimates.*** 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.
        The
        preparation of these financial statements requires us to make estimates and
        judgments that affect the reported amounts of our assets, liabilities, revenues,
        costs and expenses, and related disclosure of contingent assets and liabilities.
        On an on-going basis, we evaluate our estimates, including those related
        to our
        asset retirement obligations, depletion and certain accrued 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.
 
 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 7 “Financial Statements”.
 
 ***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.
 
 ***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.
 
 ***Impairment
        of Oil and Gas Properties.*** We
        will
        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 will 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.
        Given
        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 and there
        can
        be no assurance that such impairments will not materially affect our financial
        position or results of operations.
  12
  
 ***Derivative
        Instruments*** .
        Atlas
        formally documents all relationships between hedging instruments and the
        items
        being hedged, including Atlas’s risk management objective and strategy for
        undertaking the hedging transactions. This includes matching the natural
        gas
        futures and options contracts to the forecasted transactions. Atlas assesses,
        both at the inception of the hedge and on an ongoing basis, whether the
        derivatives are highly effective in offsetting changes in the fair value
        of
        hedged items. Historically these contracts have qualified and been designated
        as
        cash flow hedges and recorded at their fair values. Gains or losses on future
        contracts are determined as the difference between the contract price and
        a
        reference price, generally prices on NYMEX. Changes in fair value are recognized
        in Partners’ Capital as Accumulated Other Comprehensive Income (Loss) and
        recognized within the statement of operations in the month the hedged gas
        is
        sold. If it is determined that a derivative is not highly effective as a
        hedge
        or it has ceased to be a highly effective hedge, due to the loss of correlation
        between changes in gas reference prices under a hedging instrument and actual
        gas prices, Atlas will discontinue hedge accounting for the derivative and
        subsequent changes in fair value for the derivative will be recognized
        immediately into earnings.
 
 At
        December 31, 2005, Atlas had 60 open natural gas futures contracts on behalf
        of
        the Partnership related to natural gas sales covering 804,800 dekatherms
        (“Dth”)
        (net to the Partnership) of natural gas, maturing through December 31, 2009
        at a
        combined average settlement price of $9.24 per Dth. There were no such open
        contracts at December 31, 2004. At December 31, 2005, the Partnership reflected
        net hedging liabilities on its balance sheet of $504,500. Of the $504,500
        net
        loss in accumulated other comprehensive income (loss) at December 31, 2005,
        if
        the fair values of the instruments remain at current market values, the
        Partnership will reclassify $131,100 of net gains to its statement of operations
        over the next twelve month period as these contracts expire, and $635,600
        of
        losses will be reclassified in later periods. Actual amounts that will be
        reclassified will vary as a result of future price changes. Ineffective hedge
        gains or losses are recorded within the statement of operations while the
        hedge
        contract is open and may increase or decrease until settlement of the contract.
        The Partnership realized gains of $53,300 for the year ended December 31,
        2005
        within its statement of operations related to the settlement of qualifying
        hedge
        instruments.
 
 As
        of
        December 31, 2005, Atlas on behalf of the Partnership, had allocated to it
        the
        following natural gas volumes hedged:
 
 **Natural
                  Gas Fixed - Price Swaps****Production**
              
              
              
              **Average**
              
              **Fair
                  Value****Period**
              
              **Volumes**
              
              **Fixed
                  Price**
              
              **Liability****(2)****Ended
                  December 31,**
              
              **(MMBTU)****(1)**
              
              **(per
                  MMBTU)**
              
              **(in
                  thousands)**2006
              
              
              184,500
              
              $
              11.48
              
              $
              1312007
              
              
              292,400
              
              
              8.77
              
              
              (351
              )2008
              
              
              327,900
              
              
              8.40
              
              
              (285
              )Total
                  liability
              
              
              
              
              
              
              
              $
              (505
              )
  
  (1)
            MMBTU
                represents million British Thermal Units. (2)
            Fair
                value based on forward NYMEX natural gas prices, as
                applicable.  13
  
  The
        following table sets forth the book and estimated fair values of derivative
        instruments at the dates indicated (in thousands):
  **December
                  31, 2005****Book
                  Value**
              
              **Fair
                  Value**AssetsDerivative
                  instruments
              
              $
              145
              
              $
              145$
              145
              
              $
              145LiabilitiesDerivative
                  instruments
              
              $
              (650
              )
              $
              (650
              )$
              (505
              )
              $
              (505
              )
 
 ***Revenue
        Recognition.*** Revenues
        from sales of natural gas are recognized by us when the gas has been delivered
        to the purchaser. Our natural gas is sold under various contracts entered
        into
        by our managing general partner. Virtually all of our managing general partner’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.
 
 ***Dismantlement,
        Restoration, Reclamation and Abandonment Costs.*** ** 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 on
        abandonment. The partnership complies with SFAS 143, as discussed in Note
        2 to
        our financial statements. As of December 31, 2005, 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,
        could
        reduce our gross profit from energy operations
 
 ***Recently
        Issued Financial Accounting Standards.*** In
        May
        2005, the Financial Accounting Standards Board, (“FASB”) issued Statement No.
        154, *Accounting
        Changes and Error Corrections* (“SFAS
        154”). SFAS 154 requires retrospective application to prior periods’ financial
        statements of changes in an accounting principle. It also requires that the
        new
        accounting principle be applied to the balances of assets and liabilities
        as of
        the beginning of the earliest period for which retrospective application
        is
        practicable and that a corresponding adjustment be made to the opening balance
        of retained earnings for that period rather than being reported in an income
        statement. The statement will be effective for accounting changes and
        corrections of errors made in fiscal years beginning after December 15, 2005.
        The impact of SFAS 154 will depend on the nature and extent of any voluntary
        accounting changes and corrections of errors after the effective date, but
        management does not currently expect SFAS 154 to have a material impact on
        our
        financial position or results of operations.
  14
  
 
 
 **ITEM
        7.**  **FINANCIAL
        STATEMENTS**
 
 
 **REPORT
        OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 
 To
        the
        Partners of
 **Atlas
        America Public #14-2005 (A) L.P.**
 **A
        Delaware Limited Partnership**
 
 We
        have
        audited the accompanying balance sheet of Atlas America Public #14-2005 (A)
        L.P.
        (a Delaware Limited Partnership) as of December 31, 2005, and the related
        statement of operations, changes in partners’ capital, and cash flows for the
        period March 3, 2005 (date of formation) through December 31, 2005. 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 audit 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 audits included consideration of internal control
        over
        financial reporting as a basis for designing audit procedures that are
        appropriate in the circumstances, but not for the purpose of expressing an
        opinion on the effectiveness of the Partnership’s internal control over
        financial reporting. Accordingly, we express no such opinion. An audit also
        includes examining, on a test basis, evidence supporting the amounts and
        disclosures in the financial statements, assessing the accounting principles
        used and significant estimates made by management, as well as evaluating
        the
        overall financial statement presentation. We believe that our audit provides
        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 #14-2005
        (A)
        L.P. as of December 31, 2005, 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
        20,
        2006
 
 
 
  15
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **BALANCE
        SHEET**
 **DECEMBER
        31, 2005**
 
 
 **2005****ASSETS**Current
                  assets:Cash
                  and cash equivalents
              
              $
              901,600Accounts
                  receivable - affiliate
              
              
              10,039,300Hedge
                  receivable
              
              
              145,300Total
                  current assets
              
              
              11,086,200Oil
                  and gas properties, well drilling contracts and leases (successful
                  efforts)
              
              
              82,189,200Less
                  accumulated depletion
              
              
              (1,540,500
              )80,648,700$
              91,734,900**LIABILITIES
                  AND PARTNERS’ CAPITAL**Current
                  liabilities:Accrued
                  liabilities
              
              $
              20,200Hedge
                  liability short-term
              
              
              14,200Total
                  current liabilities
              
              
              34,400Asset
                  retirement obligation
              
              
              1,915,600Hedge
                  liability long-term
              
              
              635,600Partners’
                  capital:Managing
                  general partner
              
              
              18,591,300Investor
                  partners (6,982.05 units)
              
              
              71,062,500Accumulated
                  comprehensive loss
              
              
              (504,500
              )89,149,300$
              91,734,900
 
 
 
 
 
 
 
 
 
 The
        accompanying notes are an integral part of these financial
        statements
 
  16
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **STATEMENT
        OF OPERATIONS**
 **FOR
        THE PERIOD MARCH 3, 2005 (date of formation) THROUGH DECEMBER 31,
        2005**
 
 
 
 **2005****REVENUES**Natural
                  gas and oil sales
              
              $
              4,701,800Interest
                  income
              
              
              400Total
                  revenues
              
              
              4,702,200**COST
                  AND EXPENSES**Production
                  expenses
              
              
              325,800Depletion
                  of oil and gas properties
              
              
              1,540,500Accretion
                  of asset retirement obligation
              
              
              108,400General
                  and administrative expenses
              
              
              58,600Total
                  expenses
              
              
              2,033,300**Net
                  earnings**
              
              $
              2,668,900**Allocation
                  of net earnings:**Managing
                  general partner
              
              $
              1,281,300Investor
                  partners
              
              $
              1,387,600Net
                  earnings per investor partnership unit
              
              $
              199
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 The
        accompanying notes are an integral part of these financial
        statements
 
  17
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **STATEMENT
        OF COMPREHENSIVE INCOME (LOSS)**
 **FOR
        THE PERIOD MARCH 3, 2005 (date of formation) THROUGH DECEMBER 31,
        2005**
 
 
 **2005**Net
                  earnings
              
              $
              2,668,900Other
                  comprehensive loss:Unrealized
                  holding losses on hedging contracts
              
              
              (504,500
              )Comprehensive
                  income
              
              $
              2,164,400
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 The
        accompanying notes are an integral part of these financial
        statements
 
  18
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **STATEMENT
        OF CHANGES IN PARTNERS’ CAPITAL ACCOUNTS**
 **FOR
        THE PERIOD MARCH 3, 2005 (date of formation) THROUGH DECEMBER 31,
        2005**
 
 
 **Managing**
              
              
              
              **Accumulated****General**
              
              **Investor**
              
              **Comprehensive****Partner**
              
              **Partners**
              
              **Loss**
              
              **Total****Balance
                  at March 3, 2005**
              
              $
              ―
              
              $
              ―
              
              $
              ―
              
              $
              ―Partners’
                  capital contributionsCash
              
              
              100
              
              
              69,674,900
              
              
              ―
              
              
              69,675,000Syndication
                  and offering costs
              
              
              7,315,900
              
              
              ―
              
              
              ―
              
              
              7,315,900Tangible
                  equipment/leasehold costs
              
              
              17,309,900
              
              
              ―
              
              
              ―
              
              
              17,309,900Total
                  contributions
              
              
              24,625,900
              
              
              63,072,000
              
              
              ―
              
              
              94,300,800Syndication
                  and offering costs, immediatelycharged
                  to capital
              
              
              (7,315,900
              )
              
              ―
              
              
              ―
              
              
              (7,315,900
              )17,310,000
              
              
              69,674,900
              
              
              ―
              
              
              86,984,900Participation
                  in revenue and costs and expensesNet
                  production revenues
              
              
              1,531,600
              
              
              2,844,400
              
              
              ―
              
              
              4,376,000Interest
                  income
              
              
              100
              
              
              300
              
              
              ―
              
              
              400Depletion
              
              
              (192,000
              )
              
              (1,348,500
              )
              
              ―
              
              
              (1,540,500
              )Accretion
                  expense
              
              
              (37,900
              )
              
              (70,500
              )
              
              ―
              
              
              (108,400
              )General
                  and administrative
              
              
              (20,500
              )
              
              (38,100
              )
              
              ―
              
              
              (58,600
              )Net
                  income
              
              
              1,281,300
              
              
              1,387,600
              
              
              ―
              
              
              2,668,900Accumulated
                  comprehensive loss
              
              
              ―
              
              
              ―
              
              
              (504,500
              )
              
              (504,500
              )**Balance
                  at December 31, 2005**
              
              $
              18,591,300
              
              $
              71,062,500
              
              $
              (504,500
              )
              $
              89,149,300
 
 
 
 
 
 
 
 
 The
        accompanying notes are an integral part of these financial
        statements
 
  19
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **STATEMENT
        OF CASH FLOWS**
 **FOR
        THE PERIOD MARCH 3, 2005 (date of formation) THROUGH DECEMBER 31,
        2005**
 
 
 **2005****Cash
                  flows from operating activities:**Net
                  earnings
              
              $
              2,668,900Adjustments
                  to reconcile net earnings to net cash provided by operating
                  activities:Depletion
              
              
              1,540,500Increase
                  in accrued liabilities
              
              
              20,200Increase
                  in accounts receivable-affiliate
              
              
              (10,039,300
              )Accretion
                  of asset retirement obligation
              
              
              108,400Net
                  cash used in operating activities
              
              
              (5,701,300
              )**Cash
                  flows from investing activities:**Oil
                  and gas well drilling contracts paid to Managing General
                  Partner
              
              
              (63,072,000
              )Net
                  cash used in investing activities
              
              
              (63,072,000
              )**Cash
                  flows from financing activities:**Return
                  of partners initial capital contribution
              
              
              (100
              )Partners’
                  capital contributions
              
              
              69,675,000Net
                  cash provided by financing activities
              
              
              69,674,900Net
                  increase in cash and cash equivalents
              
              
              901,600Cash
                  and cash equivalents at beginning of period
              
              
              ―Cash
                  and cash equivalents at end of period
              
              $
              901,600**Supplemental
                  Schedule of Noncash Investing and Financing
                  Activities:**Assets
                  contributed by Managing General PartnerTangible
                  equipment/lease costs, included in oil and gas properties
              
              $
              17,309,900Syndication
                  and offering costs
              
              
              7,315,900$
              24,625,800Asset
                  retirement obligation
              
              $
              1,807,200
 
 
 The
        accompanying notes are an integral part of these financial
        statements
 
  20
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS**
 **DECEMBER
        31, 2005**
 
 **NOTE
        1 - NATURE OF OPERATIONS**
 
 Atlas
        America Public #14-2005 (A) L.P. (the “Partnership”) is a Delaware Limited
        Partnership, which includes Atlas Resources, Inc. (“Atlas”) of Pittsburgh,
        Pennsylvania, as Managing General Partner and Operator, and 2,190 subscribers
        to
        units as either Limited Partners or Investor General Partners depending upon
        their election. The Partnership was formed on March 3, 2005 to drill and
        operate
        gas wells located primarily in Western Pennsylvania and Tennessee. At December
        31, 2005, the majority of the Partnership’s properties were scheduled for
        drilling. Recoverability of the cost of properties is dependent on the results
        of such development activities.
 
 ***Spin-off
        of Atlas America, Inc. from Resource America, Inc.*** On
        June
        30, 2005, RAI distributed its remaining 10.7 million shares of Atlas America,
        Inc. to its stockholders in the form of a tax-free dividend. Although the
        distribution itself was tax-free to RAI’s stockholders, as a result of the
        deconsolidation there may be some tax liability arising from prior unrelated
        corporate transactions among Atlas America, Inc. and some of its subsidiaries.
        These transactions did not have a direct material impact on our financial
        position or results of operations and Atlas America, Inc. (and the managing
        general partner) no longer consolidate with RAI as of June 30,
        2005.
 
 **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 the 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.
 
 *Receivables*
 
 In
        evaluating the need for an allowance for possible losses, Atlas performs
        ongoing
        credit evaluations of its customers and adjusts credit limits based upon
        payment
        history and the customer’s current creditworthiness, as determined by Atlas’s
        review of its customers’ credit information. Atlas extends credit on an
        unsecured basis to many of its energy customers. At December 31, 2005, Atlas’
credit evaluation indicated that it and the Partnership have no need for
        an
        allowance for possible losses.
  21
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)**
 
 *Revenue
        Recognition*
 
 Revenues
        from sales of natural gas are recognized by us when the gas has been delivered
        to the purchaser. Our natural gas is sold under various contracts entered
        into
        by our managing general partner. Virtually all of our managing general partner’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.
 
 Because
        there are timing differences between the delivery of our natural gas and
        oil and
        our receipt of a delivery statement, we have unbilled revenues. These revenues
        are accrued based on volumetric data from our records and our estimates of
        the
        related transportation and compression fees which are, in turn, based on
        applicable product prices. We had unbilled trade receivables of $2,423,200
        at
        December 31, 2005, which are included in the amounts set forth in the “Accounts
        receivable - affiliate” line item on our balance sheets. See Item 7 “Financial
        Statements”.
 
 *Recently
        Issued Financial Accounting Standards*
 
 In
        May
        2005, the Financial Accounting Standards Board, (“FASB”) issued Statement No.
        154, *Accounting
        Changes and Error Corrections* (“SFAS
        154”). SFAS 154 requires retrospective application to prior periods’ financial
        statements of changes in an accounting principle. It also requires that the
        new
        accounting principle be applied to the balances of assets and liabilities
        as of
        the beginning of the earliest period for which retrospective application
        is
        practicable and that a corresponding adjustment be made to the opening balance
        of retained earnings for that period rather than being reported in an income
        statement. The statement will be effective for accounting changes and
        corrections of errors made in fiscal years beginning after December 15, 2005.
        The impact of SFAS 154 will depend on the nature and extent of any voluntary
        accounting changes and corrections of errors after the effective date, but
        management does not currently expect SFAS 154 to have a material impact on
        our
        financial position or results of operations.
 
 *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 period ended December 31,
        2005.
  22
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)**
 
 *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, 2005,
        the
        Partnership had $903,900 in deposits at one bank of which $803,900 was over
        the
        insurance limit of the Federal Deposit Insurance Corporation. No losses have
        been experienced on such investments.
 
 *Comprehensive
        Income*
 
 The
        Partnership is subject to the provisions of SFAS No. 130, “Reporting
        Comprehensive Income,” which requires disclosure of comprehensive income and its
        components. Comprehensive income includes net income and all other changes
        in
        equity of a business during a period from non-owner sources. These changes,
        other than net income, are referred to as “other comprehensive income” which
        includes changes in unrealized hedging gains and losses.
 
 *Property
        and Equipment*
 
 Property
        and equipment 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
                  December 31,****2005**Mineral
                  interest in properties:Proved
                  properties
              
              $
              1,801,700Wells
                  and related equipment
              
              
              80,387,50082,189,200Accumulated
                  depletion:Oil
                  and gas properties
              
              
              (1,540,500
              )$
              80,648,700
 
 *Oil
        and Gas Properties*
 
 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. Depletion is
        provided on the units of production method.
 
 The
        Partnership’s long-lived assets are reviewed for impairment annually for events
        or changes in circumstances that 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 that are
        largely independent of other groups of assets. The review is done by determining
        if the historical cost of proved properties less the applicable accumulated
        depreciation, depletion and amortization and abandonment is less than the
        estimated expected undiscounted future cash flows. The expected future cash
        flows are estimated based on the Partnership’s plans to continue to produce and
        develop
  23
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)**
 
 *Oil
        and Gas Properties (Continued)*
 
 proved
        reserves. Expected future cash flow from the sale of production of reserves
        is
        calculated based on estimated future prices. The Partnership estimates prices
        based upon market related information including published futures prices.
        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
        cash
        flows, an impairment loss is recognized for the difference between the estimated
        fair market value (as determined by discounted future cash flows), and the
        carrying value of the assets.
 
 Upon
        the
        sale or retirement of a complete or partial unit of a proved property, the
        cost
        is eliminated from the property accounts, and the resultant gain or loss
        is
        reclassified to accumulated depletion. Upon the sale of an entire interest
        in an
        unproved property where the property had been assessed for impairment
        individually, a gain or loss is recognized in the statements of operations.
        If a
        partial interest in an unproved property is sold, any funds received are
        accounted for as a reduction of the cost in the interest retained.
 
 *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
        facilities 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 obligation because a reliable estimate
        cannot be determined.
 
 *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. The Partnership maintains insurance that may cover
        in
        whole or in part certain environmental expenditures. For the period ended
        December 31, 2005, 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
        period ended December 31, 2005, sales to UGI Energy Services, Inc., Amerada
        Hess
        Corporation and Colonial Energy, Inc. accounted for 64%, 12% and 12%,
        respectively, of total revenues. No other customer accounted for 10% or more
        of
        total revenues for the period ended December 31, 2005.
  24
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)**
 
 *Derivative
        Instruments*
 
 The
        Partnership applies the provisions of SFAS No. 133, “Accounting for Derivative
        Instruments and Hedging Activity” (“SFAS No. 133”). SFAS No. 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.
 
 **NOTE
        3 - ASSET RETIREMENT OBLIGATION**
 
 The
        Partnership accounts for its estimated plugging and abandonment of its oil
        and
        gas properties in accordance with SFAS 143, “Accounting for Asset Retirement
        Obligations”.
 
 A
        reconciliation of the Partnership’s liability for well plugging and abandonment
        costs for the period ended December 31, 2005 is as follows:
 
 **2005**Asset
                  retirement obligation, at beginning of period
              
              $
              ―Liabilities
                  incurred from drilling wells
              
              
              1,807,200Accretion
                  expense
              
              
              108,400Asset
                  retirement obligation, at end of period
              
              $
              1,915,600
 
 **NOTE
        4 - FEDERAL 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.
 
 **NOTE
        5 - PARTICIPATION IN REVENUES AND COSTS**
 
 The
        Managing General Partner and the other partners will generally participate
        in
        revenues and costs in the following manner:
 
 **Managing**
              
              **Other****General
                  Partner**
              
              **Partners****(3****)**Organization
                  and offering costs
              
              
              100
              %
              
              0
              %Lease
                  costs
              
              
              100
              %
              
              0
              %Revenues
              
              
              (1
              )
              
              (1
              )Operating
                  costs, administrative costs, direct costs and all other
                  costs
              
              
              (2
              )
              
              (2
              )Intangible
                  drilling costs
              
              
              0
              %
              
              100
              %Tangible
                  equipment costs
              
              
              70.41
              %
              
              29.59
              %
 
  25
  
 
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        5 - PARTICIPATION IN REVENUES AND COSTS (CONTINUED)**
 
  
 (1)
            Subject
                to the Managing General Partner’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 Managing General Partner 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. (3)
            Other
                Partners include both investor limited partners and investor general
                partners. General Partner units will automatically convert to limited
                partner units when all wells have been drilled and completed. Thereafter,
                each investor general partner will have limited liability as a limited
                partner under the Delaware Revised Uniform Limited Partnership Act
                with
                respect to his or her interest in the
                partnership. 
 **NOTE
        6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS**
 
 The
        Partnership has entered into the following significant transactions with
        Atlas
        Resources, Inc. (“Atlas”), the Managing General Partner, and its affiliates as
        provided under the Partnership agreement:
 
 Drilling
                  contracts******to
                  drill and complete wells for the Partnership are charged at cost
                  plus 15%.
                  The cost of the wells includes reimbursement to Atlas of its general
                  and
                  administrative overhead cost ($13,341 per well) and all ordinary
                  and
                  actual costs of drilling, testing and completing the wells. The
                  Partnership paid $69,674,900 to Atlas in 2005 under the drilling
                  contract.As
                of December 31, 2005, the Partnership has funded
                $69,674,900 to Atlas for well drilling contracts of which $63,072,000
                has
                been spent to date on well drilling cost and the remaining balance
                of
                $6,602,900 is shown as part of accounts receivable-affiliate, due
                from
                Atlas, on our balance sheet.Atlas
                  contributed all the undeveloped leases necessary to cover each
                  of the
                  Partnership’s prospects and received a credit to its capital account in
                  the Partnership of  $1,822,600.Administrative
                  costs which are included in general and administrative expenses
                  in the
                  Statement of Operations are payable to Atlas at $75 per well per
                  month.
                  Administrative costs incurred in 2005 were $30,100.Monthly
                  well supervision fees which are included in production expenses
                  in the
                  Statement of Operations are payable to Atlas at $285 per well per
                  month
                  for operating and maintaining the wells. Well supervision fees
                  incurred in
                  2005 were $114,300.
 
 Transportation
                  fees which are included in production expenses in the Statement
                  of
                  Operations are payable to Atlas at rates ranging from $.20-$.70
                  per MCF
                  (one thousand cubic feet) in the primary and secondary drilling
                  areas.
                  Transportation costs incurred in 2005 were $141,300.Our
                  Managing General Partner and its affiliates will be reimbursed
                  for all
                  direct costs expended on our behalf. For the year ended December
                  31, 2005,
                  we reimbursed the Managing General Partner $98,700 for direct
                  costs.Atlas
                  and Anthem Securities, an affiliate of Atlas, received $7,315,900
                  in 2005
                  for fees, commissions and reimbursements as dealer-manager and
                  to organize
                  the Partnership.
 
 As
        the
        Managing General Partner, Atlas performs all administrative and management
        functions for the Partnership including billing revenues and paying expenses.
        Accounts receivable - affiliate on the Partnership’s Balance Sheet represents
        the net production revenues due from Atlas.
  26
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        7 - COMMITMENTS**
 
 Subject
        to certain conditions, investor partners may present their interests beginning
        in 2010 for purchase by Atlas. The purchase price will be calculated by Atlas
        in
        accordance with the terms of the partnership agreement. Atlas is not obligated
        to purchase more than 5% of the units in any calendar year. In the event
        that
        Atlas is unable to obtain the necessary funds, Atlas may suspend its purchase
        obligation.
 
 Beginning
        one year after each of our wells has been placed into production our managing
        general partner, as operator, may retain $200 of our revenues per month to
        cover
        the estimated future plugging and abandonment costs. As of December 31, 2005
        the
        managing general partner has not withheld such funds.
 
 **NOTE
        8 - SUBORDINATION OF MANAGING GENERAL PARTNER’S REVENUE
        SHARE**
 
 Under
        the
        terms of the partnership agreement, Atlas may be required to subordinate
        up to
        50% of its share of production revenues of the Partnership, net of related
        operating costs, administrative costs and well supervision fees to the receipt
        by the investor partners of cash distributions from the Partnership equal
        to at
        least 10% of their agreed subscriptions, 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. In 2005, Atlas was
        not
        required to subordinate any of its revenues to the investor
        Partners.
 
 **NOTE
        9 - DERIVATIVE INSTRUMENTS**
  Atlas
        on
        behalf of the Partnership from time to time enters into natural gas futures
        and
        option 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 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.
 
 Atlas
        formally documents all relationships between hedging instruments and the
        items
        being hedged, including Atlas’s risk management objective and strategy for
        undertaking the hedging transactions. This includes matching the natural
        gas
        futures and options contracts to the forecasted transactions. Atlas assesses,
        both at the inception of the hedge and on an ongoing basis, whether the
        derivatives are highly effective in offsetting changes in the fair value
        of
        hedged items. Historically these contracts have qualified and been designated
        as
        cash flow hedges and recorded at their fair values. Gains or losses on future
        contracts are determined as the difference between the contract price and
        a
        reference price, generally prices on NYMEX. Changes in fair value are recognized
        in Partners’ Capital as Accumulated Other Comprehensive Income (Loss) and
        recognized within the statement of operations in the month the hedged gas
        is
        sold. If it is determined that a derivative is not highly effective as a
        hedge
        or it has ceased to be a highly effective hedge, due to the loss of correlation
        between changes in gas reference prices under a hedging instrument and actual
        gas prices, Atlas will discontinue hedge accounting for the derivative and
        subsequent changes in fair value for the derivative will be recognized
        immediately into earnings.
 
  27
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        9 - DERIVATIVE INSTRUMENTS (CONTINUED)**
 
 At
        December 31, 2005, Atlas had 60 open natural gas futures contracts on behalf
        of
        the Partnership related to natural gas sales covering 804,800 dekatherms
        (“Dth”)
        (net to the Partnership) of natural gas, maturing through December 31, 2009
        at a
        combined average settlement price of $9.24 per Dth. There were no such open
        contracts at December 31, 2004. At December 31, 2005, the Partnership reflected
        net hedging liabilities on its balance sheet of $504,500. Of the $504,500
        net
        loss in accumulated other comprehensive income (loss) at December 31, 2005,
        if
        the fair values of the instruments remain at current market values, the
        Partnership will reclassify $131,100 of net gains to its statement of operations
        over the next twelve month period as these contracts expire, and $635,600
        of
        losses will be reclassified in later periods. Actual amounts that will be
        reclassified will vary as a result of future price changes. Ineffective hedge
        gains or losses are recorded within the statement of operations while the
        hedge
        contract is open and may increase or decrease until settlement of the contract.
        The Partnership realized gains of $53,300 for the year ended December 31,
        2005
        within its statement of operations related to the settlement of qualifying
        hedge
        instruments.
 
 As
        of
        December 31, 2005, Atlas on behalf of the Partnership, had the following
        natural
        gas volumes hedged:
 
 **Natural
                  Gas Fixed - Price Swaps****Production**
              
              
              
              **Average**
              
              **Fair
                  Value****Period**
              
              **Volumes**
              
              **Fixed
                  Price**
              
              **Liability****(2)****Ended
                  December 31,**
              
              **(MMBTU)****(1)**
              
              **(per
                  MMBTU)**
              
              **(in
                  thousands)**2006
              
              
              184,500
              
              $
              11.48
              
              $
              1312007
              
              
              292,400
              
              
              8.77
              
              
              (351
              )2008
              
              
              327,900
              
              
              8.40
              
              
              (285
              )Total
                  liability
              
              
              
              
              
              
              
              $
              (505
              )
  
  (1)
            MMBTU
                represents million British Thermal Units. (2)
            Fair
                value based on forward NYMEX natural gas prices, as
                applicable.  28
  
  **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        9 - DERIVATIVE INSTRUMENTS**  **(CONTINUED)**
 
 The
        following table sets forth the book and estimated fair values of derivative
        instruments at the dates indicated (in thousands):
  **December
                  31, 2005****Book
                  Value**
              
              **Fair
                  Value**AssetsDerivative
                  instruments
              
              $
              145
              
              $
              145$
              145
              
              $
              145LiabilitiesDerivative
                  instruments
              
              $
              (650
              )
              $
              (650
              )$
              (505
              )
              $
              (505
              )
 
 **NOTE
        10 - INDEMNIFICATION**
 
 In
        order
        to limit the potential liability of any investor general partners, Atlas
        has
        agreed to indemnify each investor that elects to be a general partner from
        any
        liability incurred which exceeds such partner’s share of Partnership
        assets.
 
 **NOTE
        11 - 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 managing general partner will
        buy
        partnership units, subject to annual limitations, based upon a valuation
        formula
        price in the partnership agreement. Therefore, reserve value information
        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 December 31:
 **2005**Mineral
                  interest in properties - proved properties
              
              $
              1,801,700Wells
                  and related equipment
              
              
              80,387,500Accumulated
                  depletion
              
              
              (1,540,500
              )**Net
                  capitalized costs**
              
              $
              80,648,700
 
  29
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
        (CONTINUED)**
 
 ***(2)***
            ***Results
                of Operations for Oil and Gas Producing
                Activities*** 
 The
        following table presents the results of operations related to natural gas
        and
        oil production for the period ended December 31:
 **2005**Natural
                  gas and oil sales
              
              $
              4,701,800Production
                  costs
              
              
              (325,800
              )Accretion
                  of asset retirement obligation
              
              
              (108,400
              )Depletion
              
              
              (1,540,500
              )**Results
                  of operations from oil and gas producing
                  activities**
              
              $
              2,727,100
 
 ***(3)***
            ***Costs
                incurred in Oil and Gas Producing
                Activities*** 
 Costs
        incurred for the period ended December 31, are as follows:
 
 **2005**Capitalized
                  asset retirement obligation
              
              $
              1,807,200Acquisition
                  costs
              
              
              1,822,600Tangible
                  equipment and drilling costs
              
              
              78,559,400**Total
                  costs incurred**
              
              $
              82,189,200
 
 ***(4)***
            ***Oil
                and Gas Reserve Information*** 
 The
        information presented below represents estimates of proved natural gas and
        oil
        reserves. The estimates of the Partnership’s proved gas reserves are based upon
        evaluations made by management and verified by Wright & Company, Inc., an
        independent petroleum engineering firm, as of December 31, 2005. All reserves
        are located within the United States. 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 reserves
        are estimated quantities of crude oil and natural gas which geological and
        engineering data demonstrate with reasonable certainty to be recoverable
        in
        future years from known reservoirs under existing economic and operating
        conditions, i.e. prices and costs as of the date the estimate is made. Prices
        include consideration of changes in existing prices provided only by contractual
        arrangements, but not on escalations based upon future conditions.
 
 Proved
        developed reserves are 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.
        All reserves are proved developed reserves and are located in the Appalachian
        Basin area.
  30
  
 **ATLAS
        AMERICA PUBLIC #14-2005 (A) L.P.**
 **(A
        DELAWARE LIMITED PARTNERSHIP)**
 **NOTES
        TO FINANCIAL STATEMENTS** **(CONTINUED)**
 **DECEMBER
        31, 2005**
 
 **NOTE
        11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
        (CONTINUED)**
 
 There
        are
        numerous uncertainties inherent in estimating quantities of proved reserves
        and
        in projecting future net revenues and the timing of development expenditures.
        The reserve data presented represents estimates only and should not be construed
        as being exact. In addition, the standardized measures of discounted future
        net
        cash flows may not represent the fair market value of the Partnership’s oil and
        gas reserves or the present value of future cash flows of equivalent reserves,
        due to anticipated future changes in oil and gas prices and in production
        and
        development costs and other factors for which effects have not been
        provided.
 
 **Natural
                  Gas**
              
              **Oil****(MCF)**
              
              **(BBLS)**Proved
                  developed reserves:Beginning
                  of period
              
              
              ―
              
              
              ―Proved
                  developed reserves
              
              
              22,599,200
              
              
              70,800Production
              
              
              (460,100
              )
              
              (4,900
              )**Balance,
                  December 31, 2005**
              
              
              22,139,100
              
              
              65,900
 
 **ITEM
                  8.**
              **CHANGES
                  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
                  DISCLOSURE:**
 
 None.
 
 **ITEM
        8A. CONTROLS AND PROCEDURES**
 
 Under
        the
        supervision, and with the participation of our managing general partner’s
        management including our managing general partner’s Chief Executive Officer and
        Chief Financial Officer, our managing general partner has evaluated the
        effectiveness of the design and operation of its disclosure controls and
        procedures (as defined in Exchange Act Rule 13a-15(e) and Rule 15d-15(e)
        as of
        the end of the period covered by this annual report on Form 10-KSB, and based
        on
        their evaluation, the Chief Executive Officer and Chief Financial Officer
        have
        concluded that these disclosure controls and procedures are effective in
        all
        material respects, including those to ensure that information required to
        be
        disclosed in reports filed or submitted under the Securities Exchange Act
        is
        recorded, processed, summarized, and reported, within the time periods specified
        in the SEC’s rules and forms, and is accumulated and communicated to management,
        including our managing general partner’s Chief Executive Officer and Chief
        Financial Officer, as appropriate to allow for timely disclosure. There have
        been no changes in our internal controls or in other factors that could
        significantly affect these controls in the fourth quarter and subsequent
        to the
        date of their evaluation.
 
 **ITEM
        8B. OTHER INFORMATION**
 
 None.
  31
  
 **PART
        III**
 
 **ITEM
                  9.**
              **DIRECTORS,
                  EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES,
                  COMPLIANCE****WITH
                  SECTION 16 (A) OF THE EXCHANGE
                  ACT**
 
 **Responsibilities
        of Atlas Resources.** We have
        no employees and rely on our managing general partner, which also serves
        as
        driller-operator of our wells, for managing us and our wells. Our managing
        general partner has complete and exclusive discretion and control over our
        operations and activities and makes all of our decisions affecting the wells
        we
        have drilled. Our managing general partner provides continuing review and
        analysis of all wells and monitors all expenditures and commitments made
        on our
        behalf. In addition, our managing general partner performs administrative
        services relating to our funding and operation, participant reporting, financial
        budgeting and record keeping.
 
 **Business
        of Atlas Resources.** Our
        managing general partner was incorporated in 1979 and depends on Atlas America,
        Inc., its indirect parent company, for management and administrative functions
        and financing its capital contributions to us and its other partnerships.
        Our
        managing general partner pays a management fee to Atlas America, Inc. for
        management and administrative services which amounted to $45.7 million, $21.6
        million and $13.1 million for its fiscal years ended September 30, 2005,
        2004
        and 2003, respectively. See Item 11 “Security Ownership of Certain Beneficial
        Owners and Management” for a discussion of the ownership of our managing general
        partner. During 2004, RAI offered a portion of its common stock in Atlas
        America, Inc. pursuant to an S-1 Registration Statement. Following the offering,
        RAI owned approximately 80.2% of the outstanding shares of Atlas America,
        Inc.’s
        common stock. On June 30, 2005, RAI distributed its remaining 10.7 million
        shares of Atlas America, Inc. to its stockholders in the form of a tax-free
        dividend. Although the distribution itself was tax-free to RAI’s stockholders,
        as a result of the deconsolidation there may be some tax liability arising
        from
        prior unrelated corporate transactions among Atlas America, Inc. and some
        of its
        subsidiaries. These transactions did not have a direct material impact on
        our
        financial position or results of operations, and Atlas America, Inc. (and
        our
        managing general partner) no longer consolidate with RAI as of June 30,
        2005.
 
 In
        addition, Atlas America, Inc. recently announced that it intends to transfer
        to
        a newly-formed wholly-owned limited liability company or limited partnership
        subsidiary of Atlas America, Inc. substantially all of its natural gas and
        oil
        exploration and production assets. As part of that transaction, Atlas America,
        Inc. anticipates that our managing general partner will be converted from
        a
        corporation into a limited liability company that will become an indirect
        subsidiary of Atlas America, Inc.’s newly-formed subsidiary. Our managing
        general partner, however, will continue to serve as our managing general
        partner, and does not expect that any of these transactions will have a material
        effect on our financial position or results of operations. Atlas America,
        Inc.
        further intends to make a registered initial public offering of a minority
        interest, estimated to be 20%, in its newly-formed subsidiary. This report
        does
        not constitute an offer to sell or a solicitation of an offer to buy any
        such
        securities.
 
 Atlas
        America, Inc. is headquartered at 311 Rouser Road, Moon Township, Pennsylvania
        15108, which is also our managing general partner’s primary office.
 
 **Executive
        Officers and Directors.** The
        executive officers and directors of our managing general partner will serve
        until their successors are elected. The executive officers and directors
        of our
        managing general partner are as follows:
 
 **NAME**
              **AGE**
              **POSITION
                  OR OFFICE**Freddie
                  M. Kotek
              50
              Chairman
                  of the Board of Directors, Chief Executive Officer and
                  PresidentFrank
                  P. Carolas
              46
              Executive
                  Vice President - Land and Geology and a DirectorJeffrey
                  C. Simmons
              47
              Executive
                  Vice President - Operations and a DirectorJack
                  L. Hollander
              49
              Senior
                  Vice President - Direct Participation ProgramsNancy
                  J. McGurk
              50
              Senior
                  Vice President, Chief Financial Officer and Chief Accounting
                  OfficerMichael
                  L. Staines
              56
              Senior
                  Vice President, Secretary and a
                  Director
 
  32
  
 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 managing general partner and Atlas 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 managing general partner, if it is stated that they devote
                approximately 100% of their professional time to our managing general
                partner 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 managing
                general partner and Atlas as compared with the other affiliates of
                our
                managing general partner, 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
        and
        Chief Financial Officer of Atlas America from February 2004 to March 2005,
        and
        served as a director from September 2001 until February 2004. 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 devotes approximately 95% 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 affiliates.
 
 **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 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 managing general partner 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 managing general partner.
        Mr.
        Carolas is a certified petroleum geologist and has been with our managing
        general partner 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
        managing general partner and Atlas America.
 
 **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
        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 managing general partner 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. Before Mr. Simmons’
career with Resource America, he had worked with Core Laboratories, Inc.,
        of
        Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons received his Petroleum
        Engineering degree from Marietta College in 1981 and his Masters degree in
        Business Administration from Ashland University in 1992. Mr. Simmons devotes
        approximately 80% 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
        affiliates, primarily Viking Resources and Resource Energy.
  33
  
 **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, the Investment Program Association, and the Financial
        Planning Association. Mr. Hollander devotes approximately 100% of his
        professional time to the business and affairs of the managing general partner
        and Atlas America.
 
 **Nancy
        J. McGurk.** Senior
        Vice President since January 2002, Chief Financial Officer and Chief Accounting
        Officer since January 2001. Ms. McGurk also serves as Senior Vice President
        since January 2002 and Chief Accounting Officer of Atlas America since January
        2001. Ms. McGurk served as Chief Financial Officer for Atlas America from
        January 2001 until February 2004. Ms. McGurk was a Vice President of Resource
        America from 1992 until May 2004 and its Treasurer and Chief Accounting Officer
        from 1989 until May, 2004 when she resigned from Resource America. Also,
        since
        1995 Ms. McGurk has served as Vice President - Finance of Resource Energy,
        Inc.
        Ms. McGurk received a Bachelor of Science degree in Accounting from Ohio
        State
        University in 1978, and has been a Certified Public Accountant since 1982.
        Ms.
        McGurk devotes approximately 80% of her professional time to the business
        and
        affairs of the managing general partner and Atlas America, and the remainder
        of
        her professional time to the business and affairs of the managing general
        partner’s affiliates.
 
 **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, 2004
        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
        managing general partner and Atlas America, and the remainder of his
        professional time to the business and affairs of the managing general partner’s
        affiliates, including Atlas Pipeline Partners GP.
 
 **Audit
        Committee Financial Expert.** The
        Board of Directors of our managing general partner 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.
 
 **ITEM
        10. EXECUTIVE COMPENSATION**
 
 We
        have
        no employees and rely on the employees of our managing general partner and
        its
        affiliates for all services. No officer or director of our managing general
        partner will receive any direct remuneration or other compensation from us.
        Those persons will receive compensation solely from affiliated companies
        of our
        managing general partner. See Item 12 “Certain Relationships and Related Party
        Transactions” for a discussion of compensation paid by us to our managing
        general partner.
 
 **ITEM
        11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**
 
 As
        of
        December 31, 2005, we had issued and outstanding 6,982.05 No officer or director
        of our managing general partner owns any units. Although, subject to certain
        conditions, investor partners may present their units to us beginning in
        2010 or
        purchase, we are prohibited by our partnership agreement from purchasing
        more
        than 5% of our total outstanding units in any calendar year.
 
 Atlas
        America, Inc. owns 100% of the common stock of AIC, which owns 100% of the
        common stock of our managing general partner.
  34
  
 **ITEM
        12. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS**
 
 **Oil
        and Gas Revenues.** After
        formation, our managing general partner paid our organization and offering
        costs
        in the amount of $7,315,900, 70.41% of the equipment costs estimated to be
        $15,487,400, any equipment costs that exceeded 10% of the partnership’s
        subscription proceeds which would otherwise have been charged to the investors
        and contributed all the leases on which the wells were or are being drilled,
        for
        a total capital contribution estimated to be $24,625,800. In return, our
        managing general partner shared in our production revenues in the same
        percentage as its capital contribution bears to our total capital contributions
        except that the managing general partner received an additional 7% of
        partnership revenues. However, our managing general partner’s total revenue
        share may not exceed 35% of partnership revenues regardless of the amount
        of its
        capital contribution. For example, if the managing general partner contributes
        25% of our total capital contributions and you and the other investors
        contribute 75% of our total capital contributions, then the managing general
        partner will receive 32% of our revenues and the other investors will receive
        68% of our revenues. For the period ended December 31, 2005, our managing
        general partner received $1,531,600 from our net production
        revenues.
 
 **Leases.** Following the final closing date for the offering of our units to potential
        investors, which was June 17, 2005, our managing general partner contributed
        oil
        and gas leases to us covering 336 undeveloped prospects for the wells we
        would
        drill and it received a credit to its capital account in us in the amount
        of
        $1,822,600.
 
 **Administrative
        Costs.** Our
        managing general partner and its affiliates receive an unaccountable, fixed
        payment reimbursement for the administrative costs they incur on our behalf
        of
        $75 per well per month, which was proportionately reduced to the extent we
        acquired less than 100% of the working interest in a well. During the period
        ended December 31, 2005, our managing general partner received $30,100, for
        administrative costs.
 
 **Direct
        Costs.** Our
        managing general partner (including when serving as operator) and its affiliates
        will be reimbursed by us for all direct costs expended by them on our behalf.
        During the period ended December 31, 2005, we reimbursed our managing general
        partner $98,700 for direct costs.
 
 **Drilling
        Contracts.** After
        the initial and final closing dates for the offering of our units to potential
        investors, we entered into a drilling contract with our managing general
        partner
        to drill and complete approximately 336 gross wells on our behalf. The total
        amount used by our managing general partner for drilling and completing the
        wells was $63,072,000 for the period ended December 31, 2005.
 
 **Well
        Charges.** Our
        managing general partner, as operator or our wells, is reimbursed at actual
        cost
        for all direct expenses incurred on our behalf and receives well supervision
        fees for operating and maintaining the wells during producing operations
        in the
        amount of $285 per well per month 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 period ended December
        31, 2005, our managing general partner received $114,300, for well supervision
        fees.
 
 **Transportation
        Fees.** We pay a
        gathering fee to our managing general partner at a competitive rate for each
        mcf
        of our natural gas transported. For the period ended December 31, 2005, $141,300
        was paid to our managing general partner for gathering fees. In turn, our
        managing general partner paid 100% of this amount to Atlas Pipeline Partners,
        L.P. for the use of its gathering system in transporting a majority of our
        natural gas production.
 
 **Dealer-Manager
        Fees.** As part
        of the offering of our units to potential investors, Anthem Securities, Inc.,
        an
        affiliate of our managing general partner and the dealer-manager of the
        offering, received a 2.5% dealer-manager fee, a 7% sales commission, a .5%
        reimbursement for accountable permissible non-cash compensation; and an up
        to
        .5% reimbursement of the selling agents’ bonefide accountable due diligence
        expenses in the amount of $6,077,700. The dealer-manager will receive no
        further
        compensation from us related to the sale of our units.
 
 **Other
        Compensation.** For the
        period ended December 31, 2005, our managing general partner did not advance
        any
        funds to us, nor did they provide us with any equipment, supplies or other
        services.
  35
  
 **ITEM
        13. EXHIBITS**
 **EXHIBIT
        INDEX**
 
 **Description**
              **Location**4(a)
              Certificate
                  of Limited Partnership for Atlas America
                Public
                  #14-2005 (A) L.P.
              Previously
                  filed in our Form S-1 on June 30, 20044(b)
              Amended
                  and Restated Certificate and Agreement of Limited Partnership for
                  Atlas
                  America Public #14-2005 (A) L.P.
              Previously
                  filed in our Form S-1 on June 30, 20044(c)
              Drilling
                  and Operating Agreement for Atlas America
                Public
                  #14-2005 (A) L.P.
              Previously
                  filed in our Form S-1 on 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.
 
 **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 period ended December 31, 2005 and for the reviews of the financial
        statements included in our Quarterly Reports on Form 10-QSB during such periods,
        were $21,900.
 
 **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 managing general partner 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. All such services and
        fees
        were pre-approved by the Audit Committee during 2005.
 
 **Code
        of Ethics.** The
        directors and officers of our managing general partner have adopted a Code
        of
        Business Conduct and Ethics that applies to all executive officers and directors
        of Atlas and is posted on Atlas’ website
        (www.atlasamerica.com).
  36
  
 **SIGNATURES**
 
 In
                  accordance with Section 13 or 15(d) of the Exchange Act, the registrant
                  caused this report to be signed on itsbehalf
                  by the undersigned, thereunto duly authorized.Atlas
                  America Public #14-2005 (A) L.P.Atlas
                  Resources Inc., Managing General PartnerDate:
                  March 30, 2006
              
              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, 2006
              
              By:
                  /s/ Freddie M. KotekFreddie
                  M. Kotek, Chairman of the Board of Directors, Chief
                  ExecutiveOfficer
                  and PresidentDate:
                  March 30, 2006
              
              By:
                  /s/ Frank P. CarolasFrank
                  P. Carolas, Executive Vice President - Land and GeologyDate:
                  March 30, 2006
              
              By:
                  /s/ Jeffrey C. SimmonsJeffrey
                  C. Simmons, Executive Vice President - OperationsDate:
                  March 30, 2006
              
              By:
                  /s/ Nancy J. McGurkNancy
                  J. McGurk, Vice President, Chief Financial Officer and
                  ChiefAccounting
                  Officer
 
 **Supplemental
        information to be furnished with reports filed pursuant to Section 15(d)
        of the**
 **Exchange
        Act by Non-reporting Issuers**
 
 An
        annual
        report will be furnished to security holders subsequent to the filing of
        this
        report.
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